Form 10-K

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ¨ Yes x No

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days: x Yes ¨ No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained in this form, and no disclosure will be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). ¨ Yes ¨ No

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

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

The aggregate market value of the voting stock and non-voting common equity held by non-affiliates (based upon the closing sale price of $0.15 per share on the Over the Counter Bulletin Board on July 3, 2010) was $12,937,508.

The number of shares outstanding of the registrant’s Common Stock as of March 29, 2011 was 136,320,765 shares.

The Registrant has incorporated by reference portions of its Proxy Statement for its 2010 Annual Meeting of Shareholders to be filed with the Securities and Exchange Commission within 120 days after the close of the fiscal year covered by this annual report.

We use the terms “EnergyConnect”, the “Company”, “we”, “us” and “our” in this form 10-K to refer to the business of EnergyConnect Group, Inc. and its subsidiary.

EnergyConnect Group, Inc. is a leading provider of demand response services to the electricity grid. Demand response programs provide grid operators with additional electricity generation capacity by encouraging consumers to curtail their electricity usage. Historically, to provide a reliable supply of electricity and to avoid service disruption, electric utilities have increased power generation by building additional power plants and transmission infrastructure. However, an alternative approach to increasing the supply side of electricity is to use demand response programs to reduce overall peak demand or shift load from peak to off-peak times, thereby optimizing the balance of demand and supply and reducing the need for additional power generation capacity. Demand response programs fall into two main groups, programs made for customers to stand by and respond to a grid event initiated by the grid operator and programs that rely on customers curtailing their use of electricity based upon price signals.

Through our proprietary software as a service (SaaS) platform, we allow commercial and industrial consumers of electricity to access demand response programs that are offered by grid operators and get paid by agreeing to stand by and curtail based upon a grid event or responding to a price signal. Our participants are commercial and industrial consumers of electricity. We contract with them to identify, develop and, if necessary, implement curtailment strategies. We enroll our participants in demand response programs operated by grid operators, who pay us for standing by or by reducing load by responding to a price signal. We in turn pass on a portion of these payments to our participants in accordance with their contract with us.

In a wholesale electricity market, such as the energy market operated by the Pennsylvania, New Jersey, Maryland Interconnection, LLC (PJM), the market operator is responsible for buying, selling and delivering wholesale electricity, thereby balancing the needs of suppliers, wholesale customers and other market participants. These markets operate like a stock exchange, with the price of electricity resulting from matching supply, for example power supplied by the generators, with demand, consisting of the retail, industrial and commercial consumers of electricity. The PJM market uses locational marginal pricing (LMP) that reflects the value of electricity at a specific time and location. If the lowest-priced electricity can reach all locations, prices are the same across the entire grid. If there is congestion and energy cannot flow to all locations more-expensive electricity is ordered to meet that demand. As a result, the LMP is higher in those locations of constraint. Wholesale electricity prices fluctuate across the grid based on five-minute intervals; however most consumers of electricity pay rates that are based on an average price of electricity that includes a hedge premium. This means that most consumers do not see wholesale prices and have no way of reacting to them. We have developed and deployed a software solution that allows our customers to see estimates of these prices and transact in the wholesale market.

The energy market consists of Day-Ahead and Real-Time, or Day-Of, markets. The Day-Ahead market is a forward market in which hourly LMPs are calculated for the next operating day based on generation offers, demand bids and scheduled bilateral transactions. The Real-Time market is a spot market in which LMPs are calculated at five-minute intervals based on actual grid operating conditions.

Our participants reduce their usage of electricity based on a pre-determined curtailment strategy they have developed and estimated wholesale electricity prices that we provide. EnergyConnect is paid for the actual

measured reduction in electricity usage, expressed either in kilowatts per hour (KWh) or megawatts per hour (MWh) at the actual LMP less the participant’s retail rate. We in turn pay our participants a percentage of the payment we receive, in each case based upon the contract with our customer.

Our participants reduce their usage of electricity in response to requests by the grid operator. The grid operator notifies us of an emergency event, we in turn notify our participants of their need to reduce demand. EnergyConnect is paid for our participants standing by to respond to the grid operator’s request to curtail. We in turn pay our participants a percentage of the payment we receive based in each case upon our individual contract with them.

Some grid operators establish Day-Ahead economic markets with forward hourly electricity prices. The price certainty of the Day-Ahead market provides a known return for a specific curtailment strategy. For example, pre-cooling buildings in early morning hours facilitates subsequent reductions of energy use in the peak afternoon hours. We provide our participants with the information and support required to participate in the Day-Ahead electrical energy market. EnergyConnect is paid for the reduction in usage. Reductions in excess of the amount committed to the Day-Ahead market are generally paid at the prevailing real-time rate. We in turn pay our customers based upon our contracts with them. Any under-delivery results in penalties from the grid operator and generally must be made up by our participants buying energy at the real-time rate.

The Company was incorporated in August 1986 as an Oregon Corporation, succeeding operations that began in October 1984. In 2009 we moved our corporate headquarters from Lake Oswego, Oregon, to Campbell, California.

In 2003 we acquired a part of Christenson Electric, Inc. (“CEI”), and in 2005, we acquired the remainder of CEI and the stock of EnergyConnect, Inc. (“ECI”). This combined a 60-year old electrical contracting and technology business with a high-growth demand response business. In November 2007 we agreed to sell the stock of CEI. The sale was completed on April 24, 2008. All significant inter-company accounts and transactions have been eliminated in consolidation.

On March 2, 2011, we entered into an Agreement and Plan of Merger with Johnson Controls Holding Company, Inc., a Delaware corporation, (“JCI”), and Eureka, Inc., an Oregon corporation and wholly owned subsidiary of JCI (“Merger Sub”), pursuant to which Merger Sub will merge with and into us, with us being the surviving corporation and a wholly owned subsidiary of JCI (the “Merger”). We currently anticipate the Merger to close some time during the third quarter of 2011.

Our objective is to leverage our unique and proprietary software technology and business processes to provide demand response solutions that service wholesale electricity markets. We offer a complete range of demand response services to commercial and industrial consumers of electricity. We utilize a direct sales organization to identify and enter into contracts with commercial and industrial participants. We intend to increase the number of customers and participants by configuring our software to work in more energy markets within North America and by adding additional distribution channels for our proprietary software technology.

Historically, we have relied on a direct sales organization supplemented by sales agents to identify and sign up commercial and industrial participants. Looking ahead, we intend to use indirect channels in addition to the direct sales organization and develop partnerships with, for example, utilities, technology providers, demand response aggregators and large national companies. As these organizations already have relationships with commercial and industrial consumers, the cost of acquiring new participants will be significantly lower if we can develop these channels and partnerships.

Under our current business model, we are paid by grid operators for the reduction of demand during peak hours, and we share a portion of this revenue with commercial and industrial consumers who are under contract with us. We offer a software-based solution to these participants that, in addition to providing them with the ability to transact in the wholesale electricity markets, provides a range of electricity information services. For example, we show current electricity loads for our customers, forecast prices and provide current tariff structures and other information of interest to our customers.

We believe that our participants and channel partners may be willing to pay a monthly subscription fee for the use of the software rather than a percentage share of the revenues generated from using the software. If we are successful in moving to this model, this will give us a more predictable revenue streams. It will also allow our software to be deployed into markets that do not rely on a wholesale electricity market, to help customers understand electricity prices and usage.

Our technology solution is designed for price-based demand response activities that encourage consumers to change their behaviors and electricity consumption patterns based on peak demand and the wholesale price of electricity. We believe that the market for price-based demand response will increase over the next few years, either through the opening and development of wholesale electricity markets and/or the adoption of more granular tariff structures such as critical peak pricing or real-time pricing. By using more granularity in a tariff, consumers will pay variable prices for electricity based on the time of use which in turn is based on the overall load on the grid.

We provide grid operators with products similar to those the grid operator purchases from electric power generators. EnergyConnect helps grid operators and utilities manage peak demand while empowering energy users to respond to market price signals with real-time energy information and access to a full range of demand response opportunities in the price-responsive, ancillary services and capacity markets. Our customers are mid- to large-sized consumers of electricity in commercial, institutional and industrial organizations. Using our GridConnect™ integrated demand response technology platform (released in July 2010), we help our customers control their energy expenditure and increase demand response earnings while enhancing grid reliability.

More than being just a demand response “aggregator,” EnergyConnect provides web-based tools to connect energy users directly into wholesale electricity markets. Our engineers have developed the GridConnect™

technology platform, which is different from competing products in that it translates multiple streams of energy information, weather trends, price signals, etc. into actionable knowledge that makes sense from a customer’s perspective and drives changes in energy use behavior.

Traditional demand response programs offered to commercial and industrial companies have gravitated toward “standby” or capacity-type programs. In these programs, customers are paid to be on standby for most of the year, and the program is only activated when there is a potential grid emergency or if supply is constrained for a utility. For many programs this may only happen one or two times per year. While these resources have a significant value to the grid, they can provide much more value by being available for short term grid imbalances or times when supply costs are rising. These markets have typically been more challenging for customers to participate in and more difficult for third parties to manage. EnergyConnect makes it easy for customers to participate in all markets and connects them with opportunities to earn money by helping the grid year round.

Experience shows that simple price signals are not enough to motivate customers into actions that change energy use behavior. By connecting our user base with greater visibility and access to energy information and markets, EnergyConnect’s products and services take the complexity out of demand response by effectively answering critical questions from the customers’ context and operational constraints. Moreover, progressive cumulative intelligence allows users to track, among others, their energy savings, demand response earnings and historical participation.

Customers using our proven GridConnect™ product represent a diverse range of vertical markets, such as state and municipal governments, higher education, heavy industry, agriculture, water and sewage treatment, commercial office buildings, cold storage, sports arenas, high tech office campuses, hospitals, shopping centers and retailers, to name a few. The breadth and scope of EnergyConnect’s customer base demonstrates the ability to adapt demand response solutions to a variety of unique markets, applications, and operations.

The capacity solution is the traditional demand response capability that has been in use for over 40 years. Capacity programs are designed to address the few times a year when an emergency event occurs where an electrical grid may approach the capacity limits of electrical generation in the region during the period just before a blackout or brownout. Participants in the capacity program are generally paid a fee to be on standby to respond on several hours’ notice to a request from the grid to reduce electrical usage for a specified period. Each grid operator and/or utility may have unique requirements for notification time, response duration, and performance penalties. Notification by the grid is typically by phone or email.

EventConnect™ is our software solution to assist our participants in managing their capacity programs. We are paid by the grid for having our participants with standby capability reduce usage when called, with specific timing requirements for response and duration. Under the PJM program, the annual commitment and registration is undertaken in the spring for the ensuing 12 months starting in June of each year and including a testing period from June to September. Payments are made to us from PJM weekly over the twelve-month period. We

recognize the revenues from these programs over the four month performance period from June to September. We, in turn, pay our participants a portion of such payments, based on their contracts. Obligations to curtail usage within PJM are for 6 hour durations, a maximum of 10 times per year, with between 2 and 24 hours advance notice. Several such events were called under the PJM capacity program during the period June to September 2010 and we successfully responded on each occasion. In the previous three years, when no events were called during the performance period, we tested our participants’ ability to respond, and they performed over 100% in aggregate.

Payments under the PJM capacity program are set three years in advance. Capacity prices in 2009 were approximately $50,000 per MW per year, increased to approximately $63,000 per MW in 2010, and will fall to $40,000 per MW in 2011. In 2012, prices for PJM will be split by region, and based on the auction held in May 2009, will fall to approximately $6,000 per MW per year in the Western Region of PJM and will increase to approximately $60,000 per MW per year in the Eastern Region of PJM. In 2013, prices for PJM will again be split by region, and based on the auction held in May 2010, will increase to approximately $10,000 per MW per year in the Western Region of PJM and approximately $85,000 per MW per year in the Eastern Region of PJM.

The economic program differs from the capacity program as it allows commercial and industrial consumers of electricity to curtail usage at their discretion based on price signals from the grid. Participants in such programs are paid for their discretionary performance rather than being paid to standby and curtail based on a demand from the grid.

We have developed a proprietary software solution, FlexConnect™, designed specifically to allow our participants to engage in wholesale electricity markets. FlexConnect™ is a hosted SaaS solution with an easy-to-use interface that allows our participants to make curtailment decisions and understand the opportunity in revenue and cost savings that result from executing the curtailment strategy. Through FlexConnect™, we provide grid operators with a reduction in electricity demand at any time when wholesale prices for electricity on the grid are above the consumer retail price. Grid operators pay us the difference between the wholesale price and the retail cost of electricity, at one-hour increments, for verified reductions by our participants from a calculated baseline of usage. In turn, we share a portion of these payments with participants, based on their contracts.

We work with our commercial and industrial consumers to understand their curtailment capability. This includes an analysis of the assets available for curtailment at the facility along with an estimated reduction in consumption of electricity that will result from shutting down the particular assets. This may be achieved by shutting off lighting in unoccupied areas of a building or cycling air conditioning units. For our industrial participants, this may be achieved by delaying firing a furnace in a steel mill, or shutting down the water pumps in a quarry at a cement plant. Our participants may create any number of different curtailment strategies that reflect their specific business processes. These various curtailment strategies are stored in the FlexConnect™ software.

To implement the curtailment strategy, we first either install telemetry or gain access to the facilities’ metering data so we can accurately measure the change in consumption that results from executing a specific curtailment activity. We then work with our participants to understand the criteria they wish to use for triggering a notification for curtailment, based on the business processes in place at their facilities at various times of the day and the magnitude of revenue opportunity at which our participants would like us to notify them of an opportunity to curtail. We then establish the baseline of electricity usage at our participant’s facilities. This involves complex calculations that are performed by our proprietary software based on rules that have been set by the grid operator. The calculations include an estimate of usage based on the previous four days with the most similar situations and adjustments based on weather conditions. The baseline sets the bar against which the curtailment strategy is measured. Finally, we test our participant to ensure that, based on the specific curtailment plans they have entered into FlexConnect™, they can deliver the reduction in usage that they estimate. With this final step, our participants are ready to transact with the wholesale electricity market.

FlexConnect™ continually monitors the market for price signals and provides our participants with estimates of the next days’ hourly price of electricity based on data contained in the day-ahead market. Participants are notified electronically, based upon their pre-determined notification criteria, when there is an opportunity for them to participate in the market. The participant’s facility manager is then required to decide whether to participate or not. If they elect to participate, they select the curtailment strategy and the specific hours they will run the strategy by checking boxes in the FlexConnect™ user interface. FlexConnect™ then calculates, based on the participation hours and curtailment strategy, what revenue opportunity exists for the participant as a result of taking the curtailment actions. If the participant wishes to execute the curtailment strategy, they submit the schedule that we in turn pass on to the grid operator through our software interface. The participant physically executes the strategy by shutting down plant or changing the parameters on its equipment (for example, the temperature on air conditioning) and is required to confirm in FlexConnect™ that the curtailment strategy or a modified version of the strategy has been executed. In a few instances, the notification to run a specific strategy is sent from FlexConnect™ directly to a building system that executes the strategy. FlexConnect™ then measures the actual drop in consumption from the calculated baseline and automatically prepares the documentation that is sent to the grid operator for settlement.

As it can take up to 60 days for the settlement process with the grid operator to be completed, FlexConnect™ includes a shadow settlement process. The forecast wholesale price is replaced with the actual price, which is set one hour after the time of usage. When the settlement process has been completed and we are paid by the grid operator for the curtailment, we pay our participants based on the terms of our contracts with them.

Grid operators provide a real-time and a Day-Ahead market for electrical energy in which we participate. Unlike capacity programs, this is a payment for service solution and there are generally no penalties or charges for not participating.

Reserve products address grid operators’ need to respond to emergencies on the electrical grid such as a lightning strike, switch failure, loss of a tie-line, or sudden loss of a generating plant. Response is generally required within 10 minutes, and response duration is generally less than 30 minutes. EnergyConnect is paid a fee for the period of load reduction commitment or back up generation available on short notice. The amount of the fee may vary by hour and over the year.

Some grids limit the participation of demand response at this time. In the PJM grid, demand response may provide 25% of the synchronous reserve needs in each area of the region. Synchronous reserve requires 10-minute response time with a 30-minute maximum duration. Generally, only our most sophisticated participants are active in this market.

While demand for electricity in North America has contracted lately, mainly due to reduced loads as a result of the economic recession, constraints on new generating or transmission infrastructure may move the regional electric grids closer to capacity limitations. Regardless of whether the constraints on new construction come from “not in my back yard” concerns, environmentalists worried about climate change or the space limitations of large urban cities, the result is delays in planned electrical generation, transmission, and distribution capacity. In this environment, demand response can provide the added buffer to keep grids functioning reliably and to delay or even negate the need to build new infrastructure.

The electric power industry is in a state of change. Worldwide fluctuations in supplies of key materials and fuels, environmental footprint limits, and public perception are driving change. Expectations and pressures on the industry to improve efficient use of fuels and materials, to improve reliability, and to reduce system losses have increased steadily during that last two decades. We are also seeing the increasing reliance on renewable energy

sources such as solar and wind, which tend to be more uncertain than other forms of power. All of these pressures and changes support the advancement and development of more and better demand response. EnergyConnect is aligned with the changing industry and helps support the needed changes while concurrently reducing electricity costs.

The electric utility industry has many stakeholders. The consumer ultimately bears the price of delivered electricity that is the result of the successful coordination of all of these stakeholders. The industry is dominated by utilities that generally operate as monopolies in their local service territories and are regulated at both the state and federal levels. For regions serving about two-thirds of the consumers in North America, regional grids have replaced the grid management activities of vertically integrated utilities that for many years built and operated the power generating plants and transmission lines that make up the backbone of power supply. These regional grids, in addition to operating the transmission system, operate wholesale electric markets into which generators bid to supply power and from which electric utilities and other retail suppliers bid to purchase power. These markets are more efficient than the vertically integrated monopoly model and have created substantial savings for consumers. Introducing demand response in these markets adds a significant additional level of efficiencies. By providing consumers of electricity an effective means of responding to variable wholesale prices of electricity on the electricity grid, we complete the marketplace for electricity and provide offsetting market forces to electricity generators.

Wholesale Power Markets are regulated by the Federal Energy Regulatory Commission (“FERC”). FERC issued a National Action Plan on Demand Response in June 2010. This report helps to define a clearer vision of how demand response will develop in the future.

The use of demand response as a large scale tool to defer or reduce the need for peaking power plants, transmission lines, or electric distribution facilities is in its infancy. In the US, less than one percent of the initial target market has been accessed. Worldwide the potential is even greater. Demand response has the potential to significantly reduce electric energy line losses and prolong the value of existing transmission lines by reducing electric demand during hours of high usage. This will also reduce the number of new power plants needed as well as shift generation to the most efficient power plants. Demand response can provide these benefits without significant new capital investment or any invasive apparatuses in buildings or industrial sites.

Despite its potential, the growth of demand response has been limited by technology and regulation. Prior to the development of transparent wholesale electric markets, the Internet, and electronic building energy control systems with Internet access, the number of people required to implement effective demand response was prohibitive. Today, by using automated technology to link wholesale market prices and grid conditions with the status, flexibilities, and capabilities of buildings and industrial sites, increased participation is possible.

The enactment of the New Direction for Energy Independence, National Security and Consumer Protection Act in December, 2007, (the “Energy Act of 2007”) presents remarkable opportunities for demand response providers to emerge as active wholesale market resources that are the “green” equivalent of traditional generation and transmission providers. Demand response is codified in the Energy Act of 2007 as a necessary and proven resource that will promote energy conservation, cost savings and energy efficiencies for the emerging “smart grid” by engaging participants with the intelligence required to actively manage consumption during peak demand and high prices. The Energy Act of 2007’s emphasis on smart grid modernization technologies also presents significant opportunities for our core competencies. Our ability to provide scalable automation of demand response transactions will increase the price elasticity and lower the overall regional market price of electricity and improve the efficiency of electricity grids. In addition to beneficial impacts on regional energy markets, our participants benefit by maximizing income potential and reducing energy costs.

Our principal customers are power grid operators, who are primarily a conduit through which electrical curtailment transactions with our participants are processed. The vast majority of our revenues each year are processed through PJM, which serves as the market for electrical transactions in a specific region in the United States.

PJM is the most mature wholesale electricity market in the United States. During the fourth quarter of 2008, wholesale prices fell dramatically due a reduction in load resulting from the economic slowdown. This severely reduced the number of opportunities for our participants to participate in the wholesale market as prices were at or below their retail electricity price. This in turn affected our revenue opportunities. During 2009, wholesale electricity prices have remained at these low levels. For 2010, energy prices improved over 2009 but, like the overall economy, was short of 2007 levels.

The PJM Interconnection Capacity program establishes a three-year laddered pricing structure for demand response participants that are not subject to market fluctuations. Each year has a fixed price that is set three years in advance. Capacity prices in 2009 were approximately $50,000 per MW per year, increased to approximately $63,000 per MW in 2010 and will fall to $40,000 per MW in 2011. In 2012, prices for PJM split by region, and based on the auction held in May 2009, will fall to approximately $6,000 per MW in the Western Region of PJM and will increase to approximately $60,000 in the Eastern Region of PJM. In 2013 prices for PJM again split by region, and based on the auction held in May 2010, will increase to approximately $10,000 per MW per year in the Western Region of PJM and will increase to approximately $85,000 per MW per year in the Eastern Region of PJM.

Our participants are commercial and industrial organizations with whom we enter into contracts to standby or curtail electricity usage based on demand from grid operators or in reaction to a price signal. We aggregate the amount of standbys and curtailments and sell this capacity to grid operators. Most of our sales effort and most of our sales force are focused on bringing electricity consumers into our service offerings. Each participant we bring into the portfolio adds to our capability to serve the needs of the wholesale electricity market.

Most of our sales are to large regional electric grid operators that serve wholesale power markets for electricity. Membership in these regional grids and participation in the committee decision structures of these organizations provide the access and advocacy channels we need to implement, execute, and advance our sales. In addition, some of our sales are generated directly from electric utilities that sponsor demand response programs.

Our competition includes public and private companies that cater to various segments of demand response products and services. We are a full-service provider of demand response products that incorporate our proprietary technologies to leverage our participants’ flexibilities and make it easier to meet the needs of a broad range of needs of grid operators.

Our competitors are utilities and third-party curtailment service providers that contract with utilities that outsource these programs. They make up the largest part of the demand response market today and reflect the bulk of demand response activities over the past 40 years. These programs are not particularly well received by consumers and tend to be ineffective in achieving significant amounts of demand response or significant benefits

to the electric system. More intense concentration on these programs by well financed public utilities and third-party providers has improved performance.

In addition, there are two well financed corporations that offer demand response solutions similar to ours. However, they have not created an integrated software platform for their participants. We have a technological advantage over these competitors at this time because of our use of software. We expect our competitors to attempt to duplicate our business model.

With so few suppliers pursuing a large potential market, we find our market overlapping our competitors’ only with a small percentage of energy consumers.

Part of our value is contained in the proprietary software that we use to manage and control energy consumption patterns in participant properties and integrate strategies and transactions that serve the electric grid. The industry knowledge and accumulated information embedded in our proprietary software is a unique and valuable asset.

We protect our intellectual property rights through a combination of patent, trademark, trade secret and other intellectual property law, nondisclosure agreements and other measures. We own a patent application which covers aspects of enterprise energy automation. The lifetime of a utility patent typically extends for 20 years from the date of filing with the relevant government authority. We hold 1 trademark and have 4 trademark applications pending in the United States. We require our business partners to enter into confidentiality and nondisclosure agreements before we disclose any sensitive aspects of technology and business plans.

We typically enter into proprietary information agreements with employees, consultants, vendors, customers and business partners.

We believe, however, that our financial performance will depend more upon our service, technical knowledge and innovative design abilities than upon such protection. Notwithstanding the foregoing, we will strongly defend all intellectual property rights from infringement.

For more information about risks related to our intellectual property, please see “Item 1A: Risk Factors” including “Our intellectual property rights may not be adequately protected outside the United States, resulting in loss of revenue” and “Intellectual property litigation could harm our business.”

We are subject to and comply with federal regulations pertaining to health and safety, employment, privacy, and related regulations pertinent to all public businesses. FERC must approve all wholesale products purchased by regional grids, and state commissions may be involved in approval of transactions with electric utilities. On January 26, 2010, we announced we had been granted Market Based Rate Authorization (MBRA) by FERC effective August 17, 2009. MBRA allows EnergyConnect to engage in a variety of wholesale electricity market transactions that complement our demand response solutions and expands the range of services we can provide to grid operators, utilities and commercial, industrial and institutional power consumers. As a result of this decision EnergyConnect is now a public utility as defined by Section 201 (e) of the Federal Power Act. We are also subject to certain local government regulations. Any failure by us to comply with foreign, federal, state or local agency regulations could subject us to substantial financial liabilities, operational interruptions and adverse publicity, any of which could materially and adversely affect our business, results of operations and financial condition. We are not aware of any pending or threatened investigation, proceeding or action by foreign, federal, state or local agencies, or third parties involving our current business or facilities.

Research and development costs are charged to operations as incurred. The Company incurred approximately $1.0 million and $0.8 million of expenditures on research and development for the years ended January 1, 2011, and January 2, 2010, respectively.

As of January 1, 2011, we directly employed 43 full time employees, two part time employees, four full time contractors and one part time contractor. None of our employees are covered by collective bargaining agreements.

Our principal corporate office is located at 901 Campisi Way, Suite 260, Campbell, CA 95008, and our telephone number is (408) 370-3311. We are an Oregon corporation. We maintain a website at www.energyconnectinc.com. The information contained on this website is not deemed to be a part of this annual report.

Our Sales and Support principal operating office is in Conshohocken, Pennsylvania, and our main development office is based in Portland, Oregon.

On November 5, 2010, the Company and EnergyConnect, Inc. (collectively with the Company, the “Borrowers”) entered into a $4,000,000 revolving loan credit facility (the “Credit Facility”) with Silicon Valley Bank and Partners For Growth III, L.P. (collectively, the “Lenders”), which matures on September 30, 2011. Advances under the Credit Facility are to be made by the Lenders to the Borrowers on a formulaic basis based on 100% of the Company’s accounts receivable owed by Pennsylvania New Jersey Maryland Interconnection LLC and its successors and assigns (“PJM”) which arise in the ordinary course of the Company’s business. Advances made by the Lenders to the Borrowers under the Credit Facility accrue interest at a rate of 12.5% per annum. The obligations of the Borrowers under the Credit Facility are secured by a first priority security interest in all of the Borrowers’ assets, including intellectual property. The Credit Facility contains various representations and warranties, covenants (including, but not limited to, limitations on dispositions of assets, changes in business, management, ownership or business locations, mergers or acquisitions, indebtedness, encumbrances, dividends and investments,) and events of default typical for a transaction of this type. In addition, the Borrowers are required to (i) perform to at least 85% of PJM’s requirements for “Load Management Event Compliance” for the period from June 1st through September 30th, (ii) maintain a minimum unrestricted cash balance at Silicon Valley Bank of at least $1,000,000 at all times, and (iii) achieve confirmed registrations for the 2011 PJM “Capacity Program” of at least $20,000,000 by March 31, 2011. A violation of one or more of these covenants or the occurrence of certain other events could result in a default permitting the termination of the Lenders’ commitments under the Credit Facility and/or the acceleration of any loan amounts then outstanding. The Borrowers must use the proceeds advanced under the Credit Facility solely as working capital and to fund their general business requirements. As partial consideration for providing the Borrowers with the Credit Facility, the Company granted to the Lenders a 7-year warrant to purchase 3,750,000 shares of the Company’s common stock at a price per share of $0.15. A copy of this agreement is attached hereto as Exhibit 4.2 and the foregoing summary is qualified in its entirety by the terms of the agreement, which are incorporated herein by this reference.

Some of the information included herein contains forward-looking statements as defined in Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Such forward-looking statements are based on the beliefs of, estimates made by and information currently available to our management and are subject to certain risks, uncertainties and assumptions. Any statements contained herein (including, without limitation, statements to the effect that the Company, we, or management “may,” “will,” “expects,” “anticipates,” “estimates,” “predicts,” “continues,” “plans,” “believes,” or “projects,” “should,” “could,” “would,” “intends” or statements concerning “potential” or “opportunity,” and any variations thereof, comparable terminology or the negative thereof) that are not statements of historical fact should be construed as forward-looking statements. Our actual results may vary materially from those expected in these forward-looking statements. Our business, prospects, financial condition and operating results could be materially and adversely affected by any of these risks, as well as other risks not currently known to us or that we currently consider immaterial. The trading price of our common stock could decline due to any of these risks, and you may lose all or part of your investment. In assessing the risks described below, you should also refer to the other information contained in the report, including our consolidated financial statements and the related notes.

On March 2, 2011, the closing price of our stock was $0.129 per share. On March 3, 2011, we announced the signing of the Merger Agreement. Following the announcement, our stock has been trading at prices in excess of $0.20 per share. The obligations of JCI, Merger Sub and us to complete the Merger are subject to the satisfaction (or waiver) of the following conditions, among others:

In addition, JCI’s and Merger Sub’s obligation to effect the Merger is subject to the satisfaction or waiver of the following conditions:

We cannot give any assurance that all of the conditions to the Merger will either be satisfied or waived or that the Merger will occur.

If we fail to comply with covenants related to our loan agreements, we may be required to repay our indebtedness thereunder, which may have an adverse effect on our liquidity.

Although we were in compliance with all covenants under the revolving line of credit (“credit line”) as of January 1, 2011, it is possible that we may not be in compliance or fail to comply with certain covenants or other

agreements in the future. Some of the covenants are subjective in nature that gives our lender the opportunity to call an event of default based upon their good faith opinion. If we are unable to meet the financial or other covenants, including the subjective covenants, under the credit line or negotiate future waivers or amendments of such covenants, an event of default could occur. Upon the occurrence and during the continuance of an event of default under the revolving line of credit, Silicon Valley Bank and Partners for Growth (collectively, “SVB”) has available a range of remedies customary in these circumstances, including without limitation declaring all outstanding debt, together with accrued and unpaid interest thereon, to be immediately due and payable, foreclosing on the assets securing the obligations arising under the credit line and/or ceasing to provide additional revolving loans, which could have a material adverse effect on us.

Even if we are in compliance with all the covenants and other terms of our credit line, there can be no assurance that SVB will continue to provide funds based upon our requests.

Our independent auditors have expressed substantial doubt about our ability to continue as a going concern, which may hinder our ability to obtain future financing.

In their report dated April 1, 2011, our independent auditors stated that our financial statements for the year ended January 1, 2011 were prepared assuming that we would continue as a going concern, and that they have substantial doubt about our ability to continue as a going concern. Our auditors’ doubts are based on our incurring net losses and deficits in cash flows from continuing operations. We continue to experience net losses. Our ability to continue as a going concern is subject to our ability to generate a profit and/or obtain necessary funding from outside sources, including by the sale of our securities, or obtaining loans from financial institutions, where possible. Our continued net losses increase the difficulty of our meeting such goals and our efforts to continue as a going concern may not prove successful.

We have incurred net losses since our inception, and we may continue to incur net losses in the future and may never reach profitability.

We were incorporated in the State of Oregon in 1986, and began commercial sales of our demand response products in 2005. We have yet to demonstrate that we can generate sufficient sales of our products to become profitable. The extent of our future operating losses and the timing of profitability are uncertain, and we may never achieve profitability. We have incurred significant net losses since our inception, including losses of approximately $0.3 million and $3.2 million for the fiscal years ended January 1, 2011, and January 2, 2010, respectively. At January 1, 2011, we had an accumulated deficit of $158 million. It is possible that we will never generate sufficient revenues from product sales to achieve profitability. Even if we do achieve significant revenues from our product sales, we expect our operating expenses to increase as we, among other things:

As a result of these activities, we may never become profitable. Even if we do achieve profitability, we may not be able to sustain or increase profitability on an ongoing basis.

If we experience continuing losses and are unable to obtain additional funding, our business operations will be harmed, and if we do obtain additional financing, our shareholders may suffer significant dilution.

Additional capital is required to effectively support the operations and to otherwise implement our overall business strategy. Even if we receive additional financing, it may not be sufficient to sustain or expand our business development operations or continue our business operations.

There can be no assurance that financing will be available in amounts or on terms acceptable to us, if at all. The inability to obtain additional capital will restrict our ability to grow and may reduce our ability to continue to conduct business operations. If we are unable to obtain additional financing, we will likely be required to curtail our business development plans. Any additional equity financing will involve dilution to our then existing shareholders.

A substantial majority of our revenues are and have been generated from contracts with, and open market sales to, a small number of grid operators and utilities, and the modification or termination of these contracts or sales relationships could materially adversely affect our business.

We are reliant upon both grid operators such as PJM and utilities for our revenues. Changes to market rules or sales relationships with these entities could have a material adverse impact on our business. We have experienced significant changes of the rules by PJM. In 2007, PJM initiated an economic incentive that encourages a significant activity level within the economic program. When the incentive expired in late 2007, the number of customers participating in the economic program declined significantly. On March 15, 2011, the FERC issued Order 745 regarding compensation of demand response in organized markets. The new rule directs that Independent System Operators (“ISOs”) and Regional Transmission Operators (“RTOs”) such as PJM implement changes to economic compensation such that compensation at full LMP is required when there is a net benefit to doing so. The RTOs are directed to specify an LMP price threshold above which economic demand response would be paid full LMP. The threshold levels remain to be identified by the RTOs. The ruling is expected to allow participation by some entities currently excluded and to remove barriers to entry for customers served by public power utilities. These changes should encourage more demand response activity. However, because many of the details of implementation remain uncertain, there can be no assurance as to the timing and participation levels in the economic programs within PJM and the other RTOs.

We face pricing pressure relating to electric capacity made available to grid operators and utilities and in the percentage or fixed amount paid to commercial, institutional and industrial customers for making capacity available, which could adversely affect our results of operations and financial position and delay or prevent our future profitability.

We are experiencing increased competition in capacity programs. As there are limited barriers to entry, we have seen a number of small companies enter into capacity programs. This in turn has led to an increase in the share of our revenues that we share with our customers in order to remain competitive in capacity programs, resulting in increased pressure on our gross margins.

Demand response, as sponsored by grid operators and utilities, is regulated by state and federal commissions. Changes in regulations could limit our ability to deliver our products to electrical grids. Lack of change in some regions could restrict the growth of demand response.

Demand response is heavily regulated by FERC and state public utility commissions. Recently, regulators at federal and state levels have been supportive of facilitating the demand response business as an effective way to improve reliability and reduce costs on electrical grids. There have been a number of reports prepared by FERC that support and encourage price responsive demand response programs. However a change in FERC commissioners or federal and state attitudes toward demand response could have a material adverse effect on our business. The failure of FERC to rule in favor of such programs could have a material adverse effect on our ability to grow revenues or add more customers. If FERC were to rule against PJM, this may discourage other markets to develop price response programs, thus limiting our ability to sell our solutions into new emerging markets.

Regional grids establish local operating rules for demand response offerings, which limit the revenue opportunity for demand response offerings.

Regional grids establish local operating rules that restrict and limit demand response offerings. Grid operating rules are established through committee processes and may be subject to FERC approval. Though demand response providers are members of regional grids and participate on these committees, other members such as electrical generators and utilities are much larger and may use their influence to set rules that limit demand response.

All regional grids have rules that guide demand response revenue opportunities. In 2008, PJM Interconnection introduced new rules that changed the revenue opportunities for demand response offerings, and instituted a screening process that may limit some customers’ desire or ability to enter markets served by PJM. Additional rules may be established to restrict or outright eliminate current demand response offerings and revenue opportunities.

Our ability to provide security deposits or letters of credit is limited and could negatively affect our ability to bid on or enter into significant long-term agreements or arrangements with utilities or grid operators.

Recent regulatory developments may require us to post letters of credit or security deposits in order to participate in key demand response programs. Given our limited access to capital, we may not have sufficient funds to meet these credit requirements that may in turn preclude us from participating in these markets, adversely affecting our ability to create shareholder value as a standalone company.

Our competitors may develop automated systems and business processes that are equivalent to ours, limiting or removing our current competitive advantage.

Some of our competitors are larger and may have the financial resources to develop automated systems and business processes that would allow them to compete effectively with our price-based products and strategies. Our competitors may also develop the ability to deliver in volume the same set of products that we currently provide. Finally our competitors may choose to provide similar products at lower costs. The occurrence of any of the foregoing could negatively impact our results, and our share price could suffer as a consequence.

Our loan agreements contain financial and operating restrictions that may limit our access to credit.

Under our current credit line our lender, Silicon Valley Bank, has a perfected first position security interest in our assets. This, along with other restrictions in the credit line, significantly limits our ability to obtain additional credit while this line is in place.

We have a history of losses which may continue and which may negatively impact our ability to achieve our business objectives.

We have incurred operating losses for three of the last four years, and net losses for each of the last four

years. We cannot be certain that we can achieve or sustain profitability on a quarterly or annual basis in the future. Our operations are subject to the risks and competition inherent in the establishment of a business enterprise. Revenues and profits, if any, will depend upon numerous factors, including without limitation:

If we continue to incur losses, our accumulated deficit will continue to increase, which may make it harder for us to obtain financing and achieve our business objectives. Failure to achieve such goals would have an adverse impact which could result in reducing or limiting our operations.

Our annual and quarterly results fluctuate and may cause our stock price to decline.

Our annual and quarterly operating results have fluctuated in the past and will likely fluctuate in the future. We believe that period to period comparisons of our results of operations are not a good indication of our future performance. A number of factors, many of which are outside of our control, are likely to cause these fluctuations. The factors outside of our control include without limitation:

Because our operating results may vary significantly from quarter to quarter, our operating results may not meet the expectations of securities analysts and investors, and the price for our common stock could decline significantly which may expose us to risks of securities litigation, impair our ability to attract and retain qualified individuals using equity incentives and make it more difficult to complete acquisitions using equity as consideration.

If the software we use in providing our demand response and energy management solutions produces inaccurate information or is incompatible with the systems used by our customers, we could be unable to provide our solutions, which could lead to a loss of revenues and trigger penalty payments.

We provide our customers with estimates of bill savings and revenues resulting from executing a specific curtailment strategy. These estimates are in turn based on a number of factors such as customer tariff structures, estimated wholesale electricity prices and estimates of the reduction in electricity usage as a result of a curtailment activity. If the estimates we provide prove to be significantly different from actual payments or savings, our customers’ use of the software could reduce. They may be subject to certain penalties if our estimates are inaccurate in Day-Ahead markets.

Our success is dependent on the actions of our participants, many of whom are large corporations and who may choose to limit their shifting or curtailment of electrical load. Non-performance to commitments by participants could subject us to financial penalties.

We are dependent on the load shifting and curtailment actions of our participants to generate energy reductions that are valuable to the grid and produce revenue. Our participants may choose to implement other strategies to reduce the cost of electricity or may focus on other areas of their business to increase income or reduce costs. In some cases for capacity products, failure to meet committed reductions in energy usage could expose us to financial penalties that exceed the revenue opportunity.

Our success is dependent on the continuous operation of our data center. We will lose the ability to track revenue transactions during a data outage which would result in lost revenue.

Our business processes are highly automated and require the active operation of our data center to track and process revenue transactions. We will lose the ability to track and collect revenue for any period of time that our data center is not operational. While highly secure, redundant, and hardened, the operation of our data center is exposed to the negative effects of prolonged power outages or natural disasters such as earthquakes.

Increased infrastructure investment and or lower fuel prices could reduce the cost of electricity, which would negatively impact demand response revenues.

Revenues from demand response offerings are dependent on high wholesale prices for electricity during periods of high usage. Prices are particularly high when system generating capacity operates near its limits. Although increased investment in electric facilities generally increases costs, in some scenarios, increased investment in generation and transmission infrastructure could reduce prices and thereby lead to lower revenue for demand response offerings. Decreases in fuel costs, such as natural gas, could reduce the price of electricity during peak daily usage and reduce our revenue from our price-based demand response offerings.

We have a limited operating history in an emerging market, which may make it difficult to evaluate our business and prospects, and may expose us to increased risks and uncertainties.

The markets in which we operate are still developing. Although PJM, which is our primary market, is the most developed wholesale electricity market within North America and other regions are looking to adopt similar market models, there can be no assurance that wholesale electricity markets will develop beyond PJM. To the extent that wholesale electricity markets do not develop, our revenue growth may be adversely affected, and the price of our stock may suffer as a consequence.

If we fail to successfully educate existing and potential grid operators and utility customers regarding the benefits of our demand response and energy management solutions or a market otherwise fails to develop for those solutions, our ability to sell our solutions and grow our business could be limited.

We depend upon the acceptance of our technology platform by customers, grid operators and utilities, as a major driver of revenues. For example, we are currently in discussions with a number of utilities to adopt our technology and price-based demand response products as a solution to new state regulations that are coming into effect. There can be no assurance that the utilities will adopt price-based demand response programs or even if they do so, that they will use our proprietary solution.

The failure to renew or sign new contracts with commercial and industrial consumers, would negatively impact our business by reducing our revenues, delaying or preventing our profitability and requiring us to spend more money to maintain and grow our commercial, institutional and industrial participant base.

The majority of our participants are under annual contracts, which means we have to re-sign them each year for the capacity and economic programs. Although we have moved towards longer term contracts, there can be no assurance that we will be successful in signing more participants to longer term contracts, or in re-signing existing participants annually. The failure to retain participants could have a significant impact on our revenues.

We may incur significant penalties and fines if found to be in non-compliance with any applicable State or Federal regulation, despite our best efforts at compliance and adherence.

Although we have been in compliance with State and Federal regulations and have not incurred significant fines our business could suffer a material adverse impact if we were found to be in non-compliance with regulations. Furthermore, in addition to the risk of significant penalties, our ability to retain our existing participants or sign new participants could be materially adversely affected if we were found to be in non-compliance with regulations.

The success of our businesses depends in part on our ability to develop and increase the functionality of our GridConnect™ software solutions.

We estimate that we have invested over 100,000 man hours into developing our GridConnect™ solution, which affords access to our EventConnect™, FlexConnect™ and ReadyConnect™ software. Not only do we have to ensure that our software continues to offer our participants up-to-date functionalities to transact in the electricity markets, we also need to continue to innovate and improve our solutions so our software remains easy to use yet critical to our customers’ energy strategies.

Our success is dependent on the growth in energy management and curtailment programs, and to the extent that such growth slows and the need for services curtail, our business may be harmed.

The demand response industry segment is in a fast changing environment. While revenue from the energy products we sell have been growing annually, rules changes within the grids in which we operate may change from time to time. It is difficult to predict whether these changes will result in curtailing the continued expansion of the markets we serve. If the rate of growth should slow, or energy consumers reduce their participation in these programs, our operating results may decline or fail to meet growth goals, and our share price could suffer.

Some of our competitors are larger and have greater financial and other resources than we do and those advantages could make it difficult for us to compete.

In the demand response industry, several companies have achieved substantially greater market shares than we have, have longer operating histories, have larger customer bases, and have substantially greater financial, development and marketing resources than we do, which may give them a competitive advantage over us. Our competitors who succeed may enjoy increased revenues and profits from an increase in market share, and our results and share price could suffer as a consequence.

The failure to manage our growth in operations and acquisitions of new product lines and new businesses could have a material adverse effect on us.

Any growth of our operations could place a significant strain on our current management resources. To manage growth, we will need to continue to improve our operational and financial systems, procedures and controls, and hiring, training and management of employees.

Our future growth may be attributable to acquisitions of new product lines and new businesses. We anticipate that future acquisitions, if successfully consummated, may create increased working capital requirements, which will likely precede by several months any material contribution to our net income by an acquisition.

Our failure to manage growth or future acquisitions successfully could seriously harm our operating results. Also, acquisition costs could cause our quarterly operating results to vary significantly. Furthermore, our shareholders’ interests would be diluted if we financed the acquisitions by incurring convertible debt or issuing securities.

Although we currently only have operations within the United States, if we were to acquire an international operation, we would face additional risks, including without limitation:

Our success largely depends on our ability to hire, retain, integrate and motivate sufficient numbers of qualified personnel, including senior management. The management of our business is dependent on key personnel that may be difficult to replace.

Our success depends on our ability to attract and retain highly skilled personnel, including senior management and international personnel. Our chief executive officer, Kevin Evans, is particularly important to our ability to succeed. From time to time we experience turnover in some of our senior management positions. We compensate our employees through a combination of salary, benefits and equity compensation. Recruiting and retaining skilled personnel is highly competitive, particularly in the San Francisco Bay Area where we are headquartered. If we fail to provide competitive compensation to our employees, it will be difficult to retain, hire and integrate qualified employees and contractors, and we may not be able to maintain and expand our business. If we do not retain our senior managers or other key employees for any reason, we risk losing institutional knowledge and experience, expertise and other benefits of continuity and the ability to attract and retain other key employees. In addition, we must carefully balance the growth of our employee base with our current infrastructure, management resources and anticipated operating cash flows. If our revenue growth or employee levels vary significantly, our operating cash flows and financial condition could be adversely affected. Volatility or lack of positive performance in our stock price may also affect our ability to retain key employees, many of whom have been granted stock options, other equity incentives or both. Our practice has been to provide equity incentives to our employees through the use of stock options and other equity vehicles, but the number of shares available for new options and other forms of securities grants is limited. We may find it difficult to provide competitive stock option grants or other equity incentives, and our ability to hire, retain and motivate key personnel may suffer.

Recently and in past years, we have initiated reductions in our workforce of both employees and contractors to align our employee base with our anticipated revenue base or with our areas of focus, and we have experienced turnover in our workforce. These reductions have resulted in reallocations of duties, which could result in employee and contractor anxiety. Reductions in our workforce could make it difficult to attract, motivate and retain employees and contractors, which could affect our ability to deliver our products in a timely fashion and adversely affect our business.

Payment for most of our products is dependent on administrative approval of the utility servicing each customer. If one or more utilities choose to delay payments to us, our revenues will be delayed or reduced.

The regional electrical grids are our customers and pay us for our products, but the utility servicing each participant approves each transaction and can delay or object to payment based on the rules of the particular grid. Certain utilities have delayed payments for prolonged periods. We cannot be sure that we will be paid for all transactions in the future.

Our growth is dependent on having a broad range of products in each region that we operate. Restrictions or delays on products that we may provide will reduce or eliminate our competitive advantage.

Our broad range of products provides a competitive advantage in the recruitment of customers and participants. Restrictions on our ability to offer multiple products in a region or delays in our ability to bring current products to new regions will reduce our competitive position and delay growth in those regions. We may not be able to anticipate or control all the rules or regulations that affect each product in each region.

Our growth is dependent on the cooperation of other stake holders such as utilities and electrical generators. To the extent that these stake holders resist change, our growth may be slowed.

Utilities and electrical generators are the largest members of electrical grids and may for their own reasons act to slow or prevent the growth of demand response. The cooperation of all stakeholders is required to facilitate the growth of our business.

Failure to keep pace with the latest technological changes could result in decreased revenues.

The market for our services is partially characterized by rapid change and technological improvements. Failure to respond in a timely and cost-effective way to these technological developments could result in serious harm to our business and operating results. We have derived, and we expect to continue to derive, a significant portion of our revenues from technology-based products. As a result, our success will depend, in part, on our ability to develop and market product and service offerings that respond in a timely manner to the technological advances of our customers, evolving industry standards and changing client preferences.

During the ordinary course of our business, we may become subject to lawsuits or indemnity claims, which could materially and adversely affect our business and results of operations.

We have in the past been, and may in the future be, named as a defendant in lawsuits, claims and other legal proceedings during the ordinary course of our business. In addition, pursuant to our service arrangements, we generally indemnify our customers for claims related to the services we provide there under. Furthermore, our electrical, technology, and transactional services are integral to the operation and performance of the electricity distribution and transmission infrastructure. As a result, we may become subject to lawsuits or claims for any failure of the systems that we provide, even if our services are not the cause for such failures. In addition, we may incur civil and criminal liabilities to the extent that our services contributed to any property damage or blackout. With respect to such lawsuits, claims, proceedings and indemnities, we have and will accrue reserves in accordance with generally accepted accounting principles. In the event that such actions or indemnities are ultimately resolved unfavorably at amounts exceeding our accrued reserves, or at material amounts, the outcome could materially and adversely affect our reputation, business and results of operations. In addition, payments of significant amounts, even if reserved, could adversely affect our liquidity position.

Our intellectual property rights may not be adequately protected outside the United States, resulting in loss of revenue.

We believe that our software and other intellectual property and proprietary rights, whether licensed or owned by us, are important to our success and our competitive position. In the course of any potential international expansion, we may, however, experience conflict with various third parties who acquire or claim ownership rights in certain intellectual property. We cannot assure you that the actions we have taken to establish and protect our intellectual property and other proprietary rights will be adequate to prevent imitation of our products by others or to prevent others from seeking to block sales of our products as a violation of the proprietary rights of others. Also, we cannot assure you that others will not assert rights in, or ownership of, our proprietary rights or that we will be able to successfully resolve these types of conflicts to our satisfaction. In addition, the laws of certain foreign countries may not protect proprietary rights to the same extent as do the laws of the United States.

We may become involved in various legal proceedings which arise in the ordinary course of business with possibly adverse results, and are currently named as defendants in a putative class action lawsuit.

From time to time, we may become involved in various lawsuits and legal proceedings which arise in the ordinary course of business. Litigation is subject to inherent uncertainties, and an adverse result in these or other matters may arise from time to time that may harm our business.

At present, EnergyConnect, its board of directors, JCI Holding and Eureka, Inc., a wholly owned subsidiary of JCI Holding, are named as defendants in three putative class action lawsuits brought by alleged shareholders challenging EnergyConnect’s proposed merger with JCI Holding. The shareholder actions generally allege, among other things, that each member of the EnergyConnect board of directors breached their fiduciary duties to EnergyConnect shareholders by authorizing the sale of EnergyConnect to JCI Holding for consideration that does not maximize value to EnergyConnect shareholders. The complaints also allege that EnergyConnect, JCI Holding

and Eureka, Inc. aided and abetted the breaches of fiduciary duty allegedly committed by the members of the EnergyConnect board of directors. The shareholder actions seek equitable relief, including enjoining the defendants from consummating the merger on the agreed-upon terms. On March 28, 2011, the court entered an order consolidating the three cases into one matter.

Litigation regarding patents and other intellectual property rights is extensive in the technology industry. In the event of an intellectual property dispute, we may be forced to litigate. Such litigation could involve proceedings instituted by the U.S. Patent and Trademark Office or the International Trade Commission, as well as proceedings brought directly by affected third parties. Intellectual property litigation can be extremely expensive, and these expenses, as well as the consequences should we not prevail, could seriously harm our business.

If a third party claims an intellectual property right to technology we use, we may be forced to discontinue an important product or product line, alter our products and processes, pay license fees or cease our affected business activities. Although we might under these circumstances attempt to obtain a license to the intellectual property in dispute, we may not be able to do so on favorable terms, or at all.

Furthermore, a third party may claim that we are using inventions covered by the third party’s patent rights and may go to court to stop us from engaging in our normal operations and activities, including making or selling our product candidates. These lawsuits are costly and could affect our results of operations and divert the attention of managerial and technical personnel.

Our competitors may have filed, and may in the future file, patent applications covering technology similar to ours. Any such patent application may have priority over our or our licensors’ patent applications and could further require us to obtain rights to issued patents covering such technologies. If another party has filed a United States patent application on inventions similar to ours, we may have to participate in an interference proceeding declared by the United States Patent and Trademark Office to determine priority of invention in the United States. The costs of these proceedings could be substantial, and it is possible that such efforts would be unsuccessful, resulting in a loss of our United States patent position with respect to such inventions.

Some of our competitors may be able to sustain the costs of complex patent litigation more effectively than we can because they have substantially greater resources. In addition, any uncertainties resulting from the initiation and continuation of any litigation could have a material adverse effect on our ability to raise the funds necessary to continue our operations.

We depend on the electric power industry for revenues and, as a result, our operating results have experienced, and may continue to experience, significant variability due to volatility in electricity prices, seasonality of peak demand and overall demand for electricity. An oversupply of electric generation capacity and varying regulatory structures, program rules and program designs in certain regional power markets could negatively affect our business and results of operations.

We saw a significant shift in the profile of our revenues from fiscal 2008 to fiscal 2009. As electricity prices have been near all-time lows due to low fuel prices and the impact of the economic recession, the ability for our customers to transact in the economic programs was significantly reduced in 2009 and 2010. We have therefore relied upon the capacity markets to make up nearly all of our revenues over the last two years. In contrast, in 2008 we saw strong electricity prices and very active economic programs that accounted for a majority of our revenues.

Global economic and credit market conditions, and any associated impact on spending by utilities or grid operators or on the continued operations of our commercial, institutional and industrial customers, could have a material adverse effect on our business, operating results, and financial condition.

General worldwide economic conditions have experienced a downturn due to the effects of the subprime lending crisis, general credit market crisis, collateral effects on the finance and banking industries, concerns about inflation, slower economic activity, decreased consumer confidence, reduced corporate profits and capital spending, adverse business conditions and liquidity concerns. This can not only manifest itself into low fuel prices and lower level of demand for electricity that result in wholesale electricity prices being below the retail rates for our participants, thereby limiting participation in the economic programs, but can also result in longer sales cycles to sign new participants to our contracts.

Regional grids that have active wholesale markets could revert to vertical control by utilities, limiting our revenue opportunities.

State regulators could restrict or eliminate wholesale markets for electricity that are the basis for priced-based energy demand response, thereby limiting our revenue opportunities. Very high prices or lack of generating capacity to match demand could create political pressure, as happened in California in 2000, to return to vertical control of generation through delivery to utilities, which would reduce the revenue opportunity for our demand response offerings.

Technological advances could reduce the cost of electricity, limiting our revenue.

Technological advances could increase electrical generating capacity, reduce transmission losses and thereby reduce the price of electricity. In addition, advances in electricity storage capabilities could come to market that would allow grid operators an alternative solution to help balance the load on the grid. Development of either technology could reduce revenue opportunities for our demand response products.

Failure of other providers of demand response products to provide value to the electricity grids may limit the entire demand response market through unfavorable regulation and/or operating rules on particular grids.

Our growth in the demand response area is dependent in part on other electricity grids developing wholesale markets for electricity. Other grid operators are likely to look to PJM programs and monitor the success of these programs before deciding to introduce similar programs in their area. One of the elements of this decision making may be how curtailment service providers within PJM managed the demand response activities. If other providers see areas of the PJM program that have not worked effectively they could create potentially unfavorable regulations or operating rules within their grids that could limit opportunities for us to expand.

Our ability to use our net operating loss carryforwards may be subject to limitation which could result in increased future tax liability for us.

Generally, a change of more than 50% in the ownership of a company’s stock, by value, over a three-year period constitutes an ownership change for U.S. federal and state income tax purposes. An ownership change may limit a company’s ability to use its net operating loss carryforwards attributable to the period prior to such change. The number of shares of our common stock that we issued as a result of our private placement in 2008, combined with debt conversion in 2010, may be sufficient, taking into account prior or future shifts in our ownership over a three-year period, to cause us to undergo an ownership change. As a result, if we earn net taxable income, our ability to use our pre-change net operating loss carryforwards to offset U.S. federal and state taxable income may become subject to limitations, which could result in an increased future tax liability for us. In addition, we will not be able to utilize any operating loss carryovers in California due to the California Budget Act of 2010, S870, enacted on October 8, 2010, which suspended the utilization of net operating loss carryovers for purposes of California state tax.

Our directors and management will exercise significant control over our company, which will limit your ability to influence corporate matters.

Our directors and management, acting together, could have the ability to control the outcome of matters submitted to our stockholders for approval, including the election of directors and any merger, consolidation or sale of all or substantially all of our assets. In addition, these stockholders, acting together, would have the ability to control the management and affairs of our company. Accordingly, this concentration of ownership might harm the market price of our common stock by:

Natural disasters and events beyond our control can affect our operations and ability to collect revenues.

Our operations and revenues can be subject to natural disasters and other events beyond our control, such as earthquakes, fires, tsunami, extreme wind conditions, power failures, telecommunication loss, terrorist attacks and acts of war. Our corporate headquarters and a portion of our critical business offices are located in California near major earthquake faults. Such events of disaster, whether natural or manmade, could cause severe destruction or interruption to our operations and as a result, our business could suffer serious harm.

If we fail to remain current on our reporting requirements, we could be removed from the OTC Bulletin Board, which would limit the ability of broker-dealers to sell our securities and the ability of shareholders to sell their securities in the secondary market.

Companies trading on the OTC Bulletin Board, such as us, must be reporting issuers under Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, and must be current in their reports under Section 13 in order to maintain price quotation privileges on the OTC Bulletin Board. If we fail to remain current on our reporting requirements, we could be removed from the OTC Bulletin Board, and the market liquidity for our securities could be severely adversely affected by limiting the ability of broker-dealers to sell our securities and the ability of shareholders to sell their securities in the secondary market. There can be no assurance that in the future we will always be current in our reporting requirements.

Our common stock is subject to the “penny stock” rules of the SEC and the trading market in our securities is limited, which makes transactions in our stock cumbersome and may reduce the value of an investment in our stock.

The Securities and Exchange Commission has adopted Rule 15g-9 which establishes the definition of a “penny stock,” for the purposes relevant to us, as any equity security that has a market price of less than $5.00 per share or with an exercise price of less than $5.00 per share, subject to certain exceptions. For any transaction involving a penny stock, unless exempt, the rules require:

In order to approve a person’s account for transactions in penny stocks, the broker or dealer must:

The broker or dealer must also deliver, prior to any transaction in a penny stock, a disclosure schedule prescribed by the Commission relating to the penny stock market, which, in highlight form:

Generally, brokers may be less willing to execute transactions in securities subject to the “penny stock” rules. This may make it more difficult for investors to dispose of our common stock and cause a decline in the market value of our stock.

Disclosure also has to be made about the risks of investing in penny stocks in both public offerings and in secondary trading and about the commissions payable to both the broker-dealer and the registered representative, current quotations for the securities and the rights and remedies available to an investor in cases of fraud in penny stock transactions. Finally, monthly statements have to be sent disclosing recent price information for the penny stock held in the account and information on the limited market in penny stocks.

We do not own any real property. Our leased facilities as of January 1, 2011 are as follows:

We believe that our current facilities are suitable and adequate to meet our anticipated needs for the foreseeable future.

Litigation (see also Subsequent Events in Note 15 to the Consolidated Financial Statements in Part II, Item 8):

EnergyConnect, its board of directors, JCI Holding and Eureka, Inc., a wholly owned subsidiary of JCI Holding, are named as defendants in three putative class action lawsuits brought by alleged shareholders challenging EnergyConnect’s proposed merger with JCI Holding. The shareholder actions generally allege, among other things, that each member of the EnergyConnect board of directors breached their fiduciary duties to EnergyConnect shareholders by authorizing the sale of EnergyConnect to JCI Holding for consideration that does not maximize value to EnergyConnect shareholders. The complaints also allege that EnergyConnect, JCI Holding and Eureka, Inc. aided and abetted the breaches of fiduciary duty allegedly committed by the members of the EnergyConnect board of directors. The shareholder actions seek equitable relief, including enjoining the defendants from consummating the merger on the agreed-upon terms. On March 28, 2011, the court entered an order consolidating the three cases into one matter.

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER REPURCHASES OF EQUITY SECURITIES.

Our common stock is quoted on the Over the Counter Bulletin Board under the symbol “ECNG.OB.” The transfer agent for our common stock is Mellon at 17 Battery Place, New York, NY 10004.

The following table sets forth the high and low intra-day bid information for our Common Stock for the fiscal quarters indicated as reported on the OTC Bulletin Board. The quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not represent actual transactions.

Our common stock is thinly traded and any reported sale prices may not be a true market-based valuation of our common stock. On January 1, 2011, the closing bid price of our common stock, as reported on the OTC Bulletin Board, was $0.11.

As of March 29, 2011, there were approximately 171 holders of record of our common stock.

Trades in our common stock may be subject to Rule 15g-9 under the Exchange Act, which imposes requirements on broker/dealers who sell securities subject to the rule to persons other than established customers and accredited investors. For transactions covered by the rule, broker/dealers must make a special suitability determination for purchasers of the securities and receive the purchaser’s written agreement to the transaction before the sale.

The SEC also has rules that regulate broker/dealer practices in connection with transactions in “penny stocks.” Penny stocks generally are equity securities with a price of less than $5.00 (other than securities listed on some national exchanges, provided that the current price and volume information with respect to transactions in that security is provided by the applicable exchange or system). The penny stock rules require a broker/dealer, before effecting a transaction in a penny stock not otherwise exempt from the rules, to deliver a standardized risk disclosure document prepared by the SEC that provides information about penny stocks and the nature and level of risks in the penny stock market. The broker/dealer also must provide the customer with current bid and offer quotations for the penny stock, the compensation of the broker/dealer and its salesperson in the transaction, and monthly account statements 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 before effecting the transaction, and must be given to the customer in writing before or with the customer’s confirmation. These disclosure requirements may have the effect of reducing the level of trading activity in the secondary market for shares of common stock.

No purchases of the Company’s equity securities were made by or on behalf of the company or any Company affiliated purchaser within the meaning of Section 240.10b-18(a)(3) during the fourth quarter of 2010.

We have never declared or paid dividends on shares of our common stock. We intend to retain future earnings, if any, to support the development of our business and therefore do not anticipate paying cash dividends for the foreseeable future. Payment of future dividends, if any, will be at the discretion of our board of directors after taking into account various factors, including current financial condition, operating results and current and anticipated cash needs.

The following equity compensation information, as of January 1, 2011, is presented in compliance with SEC regulation S-K Item 201(d).

On September 8, 2010, following notice that the Company intended to repay the balance of the convertible loan facility, Aequitas Commercial Finance, LLC (“Aequitas”) opted to convert, pursuant to the loan agreement as amended between the Company and Aequitas, all but $1 of the remaining principal plus accrued interest, totaling $3,307,280, into 36,504,180 shares of common stock.

On November 10, 2010, the Company issued 2,500,000 units of restricted stock to various officers of the Company. Twenty five percent of the restricted stock units vest six months after the date of grant and twelve and one half percent of the restricted stock units vest every three months thereafter, such that 100% of the restricted stock units shall be fully vested on the two year anniversary of the date of grant.

The following selected consolidated financial data should be read in conjunction with our consolidated financial statements and related notes and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included elsewhere in this annual report. The statements of operations data for the twelve months ended January 1, 2011, and January 2, 2010 and the balance sheet data at January 1, 2011, and January 2, 2010 are derived from our audited financial statements which are included elsewhere in this annual report. The statement of operations data for the years ended January 3, 2009, December 29, 2007, and December 30, 2006, and the balance sheet data at January 3, 2009, December 29, 2007, and December 30, 2006, are derived from our audited financial statements which are not included in this annual report. The historical results are not necessarily indicative of results to be expected for future periods. The following information is presented in thousands, except per share data.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Some of the information in this annual report contains forward-looking statements. These statements are made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Forward-looking statements inherently involve substantial risks and uncertainties. One can identify these statements by forward-looking words such as “may,” “will,” “expect,” “anticipate,” “believe,” “estimate” and “continue,” or similar words. One should read statements that contain these words carefully because they:

We believe it is important to communicate our expectations. However, there may be events in the future that we are not able to accurately predict or over which we have no control. Our actual results and the timing of certain events could differ materially from those anticipated in these forward-looking statements as a result of certain factors, including those set forth under “Risk Factors,” “Business” and elsewhere in this Form 10-K. See “Risk Factors beginning on page 11.”

EnergyConnect Group, Inc. is a leading provider of demand response services to the electricity grid. Demand response programs provide grid operators with additional electricity generation capacity by encouraging consumers to curtail their electricity usage. Historically, to provide a reliable supply of electricity and to avoid service disruption, grid operators have increased power generation by building additional power plants and transmission infrastructure. However, an alternative approach to increasing the supply side of electricity is to use demand response programs to reduce overall peak demand or shift load from peak to off-peak times, thereby optimizing the balance of demand and supply and reducing the need for additional power generation capacity. Demand response programs fall into two main groups: programs made for participants to stand by and respond to a grid event initiated by the grid operator, and programs that rely on participants curtailing their use of electricity based upon price signals.

Through our proprietary software as a service (SaaS) platform, we allow commercial and industrial consumers of electricity to access demand response programs that are offered by the grid and get paid by agreeing to stand by and curtail based upon a grid event or responding to a price signal. Our participants are commercial and industrial consumers of electricity with whom we contract to identify, develop and if necessary implement curtailment strategies. We enroll our participants in demand response programs operated by grid operators, who pay us for standing by or by reducing load by responding to a price signal. We make payments to our participants based on the terms and conditions of their contract with us.

The Company was incorporated in August 1986 as an Oregon Corporation, succeeding operations that began in October 1984. The Company’s headquarters are located in Campbell, California.

In a wholesale electricity market, such as the energy market operated by Pennsylvania, New Jersey, Maryland Interconnection, LLC (“PJM”), the market operator is responsible for buying, selling and delivering wholesale electricity thereby balancing the needs of suppliers, wholesale customers and other market participants. These markets operate like a stock exchange, with the price of electricity resulting from matching supply, for example power supplied by the generators, with demand, consisting of the retail, industrial and commercial consumers of electricity. The PJM market uses locational marginal pricing (“LMP”) that reflects the value of electricity at a specific time and location. If the lowest-priced electricity can reach all locations, prices are the same across the

entire grid. If there is congestion and energy cannot flow to all locations, more expensive electricity is ordered to meet that demand. As a result, the LMP is higher in those locations of constraint. Wholesale electricity prices fluctuate based on five-minute intervals across the grid, however most consumers of electricity pay rates that are based on an average price of electricity that includes a hedge premium. This means that most consumers do not see wholesale prices and have no way of reacting to them. We have developed and deployed a software solution that allows our participants to transact in the wholesale market.

Our participants reduce their usage of electricity based on a pre-determined curtailment strategy they have developed and estimated prices for wholesale electricity that we provide. EnergyConnect is paid for the actual measured reduction in electricity usage expressed either in kilowatts per hour (KWh) or megawatts per hour (MWh) at the actual LMP less the participant’s retail rate. We in turn pay our participants a percentage of the payment we receive based upon our individual contracts with them.

Some grid operators establish Day-Ahead economic markets with forward hourly electricity prices. The price certainty of the Day-Ahead market provides a known return for a specific curtailment strategy, for example, by pre-cooling buildings in early morning hours to create subsequent reductions of energy use in the peak afternoon hours. We provide our participants with all the information and support required to participate in the Day-Ahead electrical energy market. EnergyConnect is paid for the reduction in usage. Reductions in excess of the amount committed to the Day-Ahead market are generally paid at the prevailing Real-Time rate. Under-delivery generally must be made up by our participants buying energy at the Real-Time rate.

The discussion and analysis of financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We continuously evaluate, our estimates and judgments, including those related to revenue recognition, sales returns, bad debts, excess inventory, impairment of goodwill and intangible assets, income taxes, contingencies and litigation. Our estimates are based on historical experience and assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions. We discuss the development and selection of the critical accounting estimates with the Audit Committee of our Board of Directors on a quarterly basis, and the Audit Committee has reviewed our related disclosure in this Form 10-K.

We believe the following critical accounting policies, among others, affect our more significant judgments and estimates used in the preparation of our consolidated financial statements:

We provide grid operators with products similar to those the grid operator purchases from electric power generators. Our products can be grouped into two main categories: “Capacity” and “Economic”.

The Capacity programs are designed to curtail usage during times when an electrical grid approaches its capacity limits of electrical generation just before a blackout or brownout. Participants in the capacity program are generally paid a fee to be on standby to respond on several hours’ notice to a request from the grid to reduce electrical usage for a specified period.

The Economic programs differ from the capacity programs as they allow commercial and industrial consumers of electricity to curtail usage at their discretion based on price signals from the grid. Participants in such programs are paid for their discretionary performance rather than being paid to standby and curtail based on a request from the grid.

Under the Capacity programs grid operators pay us an annual fee in weekly installments to stand by and provide demand response resources to the grid when the grid calls an event. We record these payments as revenue over the time when we are required to perform under these capacity programs. For some programs our obligation to perform does not match the period over which we are paid by the grid, in which case we recognize revenues over the mandatory performance period.

Under the Economic programs we are paid by the grid for our commercial and industrial participants’ ability to reduce electricity usage in response to a price signal from the grid. Through our software we summarize price responsive activity and submit to the grid for payment. At the end of each monthly period the power grid approves the payments and we, in turn, recognize revenue based upon the grid approval.

An additional source of our revenue is derived from agreements with the power grid operators whereby a monthly reserve fee is paid for our agreement to be available to provide relief in the form of curtailment of energy usage in times of high energy demand. We record these payments as revenue over the period during which we are required to perform under these programs. Under certain programs, our obligation to perform may not coincide with the period over which we receive payments under that program. In these cases we record revenue over the mandatory performance obligation period and record a receivable for the amount of payments that will be received after that period has been completed.

Some of our contracts with our participants are multi-year contracts for their participation in capacity markets where both the pricing and the participant’s commitment are known. Contracts signed for delivery in future years form the basis of our backlog. As of January 1, 2011, we had approximately 196 MW of capacity backlog with our participants, compared to no backlog at January 2, 2010.

We make estimates of liabilities that arise from various contingencies for which values are not fully known at the date of the accrual. These contingencies may include accruals for reserves for costs and awards involving legal settlements, costs associated with vacating leased premises or abandoning leased equipment, and costs involved with the discontinuance of a segment of a business. Events may occur that are resolved over a period of time or on a specific future date. Management makes estimates of the potential cost of these occurrences, and charges them to expense in the appropriate periods. If the ultimate resolution of any event is different than management’s estimate, compensating entries to earnings may be required.

In accordance with ASC 360, Accounting for the Impairment or Disposal of Long-Lived Assets, we assess the impairment of long-lived assets whenever events or changes in circumstances indicate that their carrying value may not be recoverable from the estimated future cash flows expected to result from their use and eventual disposition. Our long-lived assets subject to this evaluation include property and equipment and amortizable intangible assets. If our estimate of future undiscounted net cash flows is insufficient to recover the carrying value of the assets, we will record an impairment loss in the amount by which the carrying value of the assets exceeds the fair value. If assets are determined to be recoverable but the useful lives are shorter than originally estimated, we depreciate or amortize the net book value of the asset over the newly determined remaining useful lives.

We account for stock-based compensation under the provisions of ASC 718-10 and ASC 505-50, “Stock Compensation and Equity Based Payments to Non-Employees”. ASC 718 requires companies to estimate the fair value of share-based payment awards on the date of grant using an option-pricing model. The value of the portion of the award that is ultimately expected to vest is recognized as expense over the requisite service periods in our Consolidated Statement of Operations.

The weighted average grant date fair value of all options granted in the years ended January 1, 2011 and January 2, 2010 was $0.10 and $0.08, respectively. These fair values were computed using the Black-Scholes pricing model and the following assumptions:

The amounts expensed for stock-based compensation related to options totaled $448,907 and $742,225 for the years ended January 1, 2011 and January 2, 2010, respectively.

The financial information presented for the years ended January 1, 2011 and January 2, 2010 represents activity in EnergyConnect Group, Inc. and its wholly-owned operating subsidiary, EnergyConnect, Inc (ECI).

Revenue. The Company generates revenue mainly from demand response transactions regulated by a Federal Energy Regulatory Commission (FERC) tariff. These transactions include economic or price-based programs and capacity programs. Economic or price-based programs entail voluntary, daily opportunities to enter into transactions in the energy markets based on our participants’ responses to fluctuations in hourly energy prices.

Capacity programs allow for payments to partners such as ECI based on energy availability and curtailment when required by an electric grid to stabilize the supply and demand of electricity on the grid. Also included in the FERC tariff are rules under which we recognize revenue in capacity-based energy programs.

The FERC tariff also allows for other revenue opportunities in helping to meet various needs of electric grids. We recognize revenue from these programs ratably over the months during which our response is required.

Revenue for the year ended January 1, 2011 was $31,644,000 compared to $19,921,000 for the year ended January 2, 2010, an increase of 58.8%. This increase in year-over-year revenue in ECI is due primarily to an

increase in PJM capacity revenues from the annual program from $12,274,000 to $21,101,000, or 71.9%. We also recognized revenue of $6,578,000 from a capacity transaction in the first quarter of 2010, compared to $4,084,000 from similar capacity transactions in the first six months of 2009, an increase of 61.1%.

Gross Profit. Gross profit for the year ended January 1, 2011 was $12,169,000 (or 38.5% of revenue) compared to $7,038,000 (or 35.3% of revenue) for the year ended January 2, 2010, an increase of 72.9%. This increase is attributable to the $4,691,000 gross profit generated by the high margin capacity transaction completed in the first quarter of 2010 compared to the $3,023,000 generated by capacity transactions in the first six months of 2009, and also an increase in the profitability of the annual program from $3,675,000 to $7,091,000, the increase being primarily attributable to the $8,827,000 increase in revenue from this program.

Gross profit comprises revenue, less the related amounts due to our participants for capacity commitments made by them, and for transactions initiated by them, and various costs required to do business in the grids in which we operate. Future gross profit margins will depend on the Company’s ability to sign contracts with participants for appropriate percentages for the duration of the contract term.

Operating Expenses. Operating expenses were $10,849,000 (34.3% of revenue) for the year ended January 1, 2011, compared to $9,317,000 (46.8% of revenue) for the year ended January 2, 2010, an increase of 16.4%. The increase in expenses is primarily due to increases of $582,000 in legal and professional fees, $903,000 in personnel costs, including salaries, and $140,000 in occupancy costs, offset by a decrease in non-cash stock-based compensation of $207,000.

Interest expense, net and other. Net interest expense was $1,580,000 for the year ended January 1, 2011, compared to $943,000 for the year ended January 2, 2010. Net interest expense in both 2010 and 2009 comprised mainly interest expense incurred under the Company’s debt facility and amortization of debt discount associated with the beneficial conversion feature of the debt facility. Net interest expense increased in 2010 due to an acceleration of the charge against debt discount and the $150,000 in minimum interest charges incurred when the loan was repaid, and due to higher average aggregate borrowings, offset by a reduction in interest rates. Following conversion of the principal balance of the Aequitas loan into common stock in September 2010, interest expenses are expected to be significantly lower in the future, although there will be interest payable at 12.5% on borrowings against the Company’s line of credit, and there is also a non-cash charge of approximately $34,000 per month relating to amortization of the expense attributed to warrants issued to obtain this line through September 30, 2011.

Taxation. Income tax expense was $48,000 in the year ended January 1, 2011, all relating to state tax charges for which insufficient net operating losses were available to offset the current year’s taxable income, partly due to California’s suspension of utilization of NOL carryovers. We have provided a full valuation allowance on our net deferred tax asset.

Since inception, we have financed our operations and capital expenditures through public and private sales of equity securities, cash from operations, and borrowings under operating and revolving lines of credit.

At January 1, 2011, the Company had positive working capital of approximately $3,207,000, compared to approximately $278,000 at January 2, 2010. The increase is primarily due to the increase in receivables resulting from increased revenue from the PJM capacity program, partially offset by a corresponding increase in payables to participants. The Company derived significant liquidity in the year ended January 1, 2011, as the balance on its convertible note was repaid in common stock. Further, the Company has obtained a $4,000,000 revolving line of credit which matures on September 30, 2011.

Accounts receivable increased to $12,613,000 at January 1, 2011 from $6,811,000 at January 2, 2010. The increase was primarily due to the increase in revenue from the annual PJM capacity program. We receive funds from this capacity transaction over the PJM program year on a weekly basis starting each June. Our remaining receivables will increase and decrease in accordance with the revenue recognized in each quarter. The large majority of our revenue, and therefore cash and receivables, is generated through PJM, which serves as the market for electrical transactions in a specific region in the United States. We are members of PJM, and our relationship with this power grid is perpetual. We do have a concentration of receivables from PJM, however, we do not believe there is a significant risk arising from this concentration.

Property and equipment, net of depreciation increased to $189,000 at January 1, 2011, compared to $187,000 at January 2, 2010. This increase was due to approximately $139,000 in additions to fixed assets offset by normal depreciation charges of $137,000 during the year. After acquiring computer equipment for approximately $150,000 in the first quarter of 2011, we do not anticipate spending significant amounts to acquire other fixed assets for the foreseeable future.

Accounts payable and related accruals increased to $10,796,000 at January 1, 2011 from $7,509,000 at January 2, 2010. The increase was primarily due to increase in cost of revenue from the annual PJM capacity program, commensurate with the increase in revenue. At January 1, 2011, other than normal obligations to vendors, payables consist primarily of payment obligations to participants in our capacity programs, not currently due, and to normal monthly obligations in our economic programs.

As a result of our history of losses and our experiencing difficulty in generating sufficient cash flow to meet our obligations and sustain our operations, our independent registered public accounting firm in their report dated April 1, 2011, included in our January 1, 2011 Form 10-K, expressed substantial doubt about our ability to continue as going concern.

We believe that revenues generated by operations, combined with our $4 million line of credit, will be adequate to fund our operations until September 2011. Thereafter, we may need to renew the credit facility or obtain alternative financing in order to attain cash flow break even from operations. Financing transactions may include the issuance of equity or debt securities, obtaining credit facilities, or other financing mechanisms. However, the trading price of our common stock, the downturn in the U.S. stock and debt markets and the first priority lien on all of our assets granted to our secured lender could make it more difficult to obtain financing through the issuance of equity or debt securities. Even if we are able to raise the funds required, it is possible that we could incur unexpected costs and expenses, fail to collect significant amounts owed to us, or experience unexpected cash requirements that would force us to seek alternative financing. Further, if we issue additional equity or debt securities, stockholders may experience additional dilution or the new equity securities may have rights, preferences or privileges senior to those of existing holders of our common stock. If additional financing is not available or is not available on acceptable terms, we may have to curtail our operations.

By adjusting the Company’s operations and development to the level of capitalization, management believes it has sufficient capital resources to meet projected cash flow deficits. However, if the Company is not successful in generating sufficient liquidity from operations or in raising sufficient capital resources on acceptable terms, or is no longer in compliance with the terms of its debt facility, this could have a material adverse effect on the Company’s business, results of operations, liquidity and financial condition. If operations and cash flows continue to improve through these efforts, management believes that the Company can continue to operate. However, no assurance can be given that management’s actions will result in profitable operations or the resolution of its liquidity problems.

We record revenue and therefore accounts receivable through agreements with both building owners and the power grid operators. Under our agreements with facilities owners, we use electrical and energy related products that help energy consumers control energy use in their buildings. In conjunction with this agreement we are members of the power grid operators and have agreed to provide the grids with energy, capacity, and related ancillary services during specified times and under specified conditions. These transactions are summarized at the end of each monthly period and submitted to the power grids for settlement and approval. While the power grids are our customers, they are primarily a conduit through which these electrical curtailment transactions are processed. The vast majority of our revenues each year are processed through PJM, which serves as the market for electrical transactions in a specific region in the United States. Transactions are initiated by building owners, who are our participants. These transactions form the basis for our revenue.

Financial transactions and instruments that potentially subject us to concentrations of credit risk consist primarily of revenue generating transactions and the resultant accounts receivable. We record no allowance for doubtful accounts, and the Company has never recorded a bad debt expense with respect to its present activities.

During the years ended January 1, 2011, and January 2, 2010, sales to one customer, PJM, accounted for $29,121,000, or 92.0% of revenue, and $17,552,000, or 88.1% of revenue, respectively. Our sales to PJM are made up of a number of transactions with participants. No single participant accounted for 10% or more of our revenue in either period. PJM accounted for 98.0% of accounts receivable at both January 1, 2011, and January 2, 2010.

While the Company has been able to manage its working capital needs with the current credit facilities, additional financing is likely required in order to meet its current and projected cash flow requirements from operations. We may need additional investments in order to continue operations to cash flow break even. We cannot guarantee that we will be able to obtain such investments. Financing transactions may include the issuance of equity or debt securities, obtaining credit facilities, or other financing mechanisms. However, the trading price of our common stock and the downturn in the U.S. stock and debt markets could make it more difficult to obtain financing through the issuance of equity or debt securities. Even if we are able to raise the funds required, it is possible that we could incur unexpected costs and expenses, fail to collect significant amounts owed to us, or experience unexpected cash requirements that would force us to seek alternative financing. Further, if we issue additional equity or debt securities, stockholders may experience additional dilution or the new equity securities may have rights, preferences or privileges senior to those of existing holders of our common stock.

At January 1, 2011, we had commitments for capital expenditures totaling approximately $150,000, all for computer equipment.

In the opinion of management, inflation will not have an impact on our financial condition and results of operations.

We do not maintain off-balance sheet arrangements nor do we participate in any non-exchange traded contracts requiring fair value accounting treatment.

See Notes 5 and 8 to the Consolidated Financial Statements for a full description of convertible debt transactions with a related party in the years ended January 1, 2011 and January 2, 2010. The balance outstanding on this debt

was fully converted into shares of common stock in September 2010. As of January 1, 2011, there are no amounts owed to related parties other than nominal amounts incurred in the normal course of business.

The following is a summary of our significant contractual cash obligations for the periods indicated that existed as of January 1, 2011, and is based on information appearing in the notes to consolidated financial statements included elsewhere in this filing.

See Note 2 to the Consolidated Financial Statements in Part II, Item 8 for a full description of new accounting pronouncements, including the respective expected dates of adoption, none of which have had, or are expected to have, a material impact on our results of operations or financial condition.

We do not own or trade any financial instruments about which disclosure of quantitative and qualitative market risks are required to be disclosed.

We have audited the accompanying consolidated balance sheet of EnergyConnect Group, Inc. and subsidiary (collectively, the “Company”) as of January 1, 2011, and the related consolidated statements of operations, stockholders’ equity and cash flows for the year then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based upon our audit.

We conducted our audit in accordance with 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. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of EnergyConnect Group, Inc. and subsidiary as of January 1, 2011, and the results of their operations and their cash flows for the year then ended in conformity with U.S. generally accepted accounting principles.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 14 for the year ended January 1, 2011, the Company has suffered recurring losses from operations and is experiencing difficulty in generating sufficient cash flow to meet its obligations and sustain its operations, which raises substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 14 to the financial statements. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

We have audited the accompanying consolidated balance sheets of EnergyConnect Group, Inc. and its wholly-owned subsidiary (the “Company”) as of January 2, 2010, and the related consolidated statements of operations, stockholders’ equity, and cash flows for the year ended January 2, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based upon our audit.

We conducted our audit in accordance with standards of the Public Company Accounting Oversight Board (United States of America). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatements. 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 our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of EnergyConnect Group, Inc. and its wholly-owned subsidiary as of January 2, 2010, and the consolidated results of its operations and its cash flows for the year ended January 2, 2010, in conformity with accounting principles generally accepted in the United States of America.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 14, the Company is experiencing difficulty in generating sufficient cash flow to meet its obligations and sustain its operations, which raises substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 14. The accompanying statements do not include any adjustments that might result from the outcome of this uncertainty.

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

EnergyConnect Group, Inc. is a leading provider of demand response services to the electricity grid. Demand response programs provide grid operators with additional electricity generation capacity by encouraging consumers to curtail their electricity usage. Historically, to provide a reliable supply of electricity and to avoid service disruption, grid operators have increased power generation by building additional power plants and transmission infrastructure. However, an alternative approach to increasing the supply side of electricity is to use demand response programs to reduce overall peak demand or shift load from peak to off-peak times, thereby optimizing the balance of demand and supply and reducing the need for additional power generation capacity. Demand response programs fall into two main groups, programs made for participants to stand by and respond to a grid event initiated by the grid operator and programs that rely on participants curtailing their use of electricity based upon price signals.

Through our proprietary software as a service (SaaS) platform, we allow commercial and industrial consumers of electricity to access demand response programs that are offered by the grid and get paid by agreeing to stand by and curtail based upon a grid event or responding to a price signal. Our participants are commercial and industrial consumers of electricity with whom we contract to identify, develop and if necessary implement curtailment strategies. We enroll our participants in demand response programs operated by grid operators, who pay us for standing by or for reducing load by responding to a price signal. We in turn pass on a portion of these payments to our participants in accordance with their contract with us.

The consolidated financial statements include the accounts of EnergyConnect Group, Inc. and its wholly owned operating subsidiary, EnergyConnect, Inc. (collectively the “Company”).

The Company was incorporated in August 1986 as an Oregon corporation, succeeding operations that began in October 1984. In 2009 we moved our corporate headquarters from Lake Oswego, Oregon to Campbell, California.

The Company’s fiscal year is the 52 or 53 week period ending on the Saturday closest to the last day of December. The Company’s current fiscal year is the 52 week period ended January 1, 2011. The Company’s last fiscal year was the 52 week period ended January 2, 2010.

The Consolidated Statements of Operations, presented above, contain revenue and expense data of EnergyConnect Group, Inc. for the years ended January 1, 2011, and January 2, 2010. On October 13, 2005, EnergyConnect Group, Inc. acquired its wholly-owned subsidiary, EnergyConnect, Inc (“ECI”). The revenue and expense data of ECI is included in the Consolidated Statements of Operations. All significant inter-company accounts and transactions have been eliminated in consolidation.

The Company considers all highly liquid investments with an original maturity or remaining maturity of three months or less at the date of purchase to be cash equivalents. Cash and cash equivalents are primarily maintained at two financial institutions.

Advertising and marketing costs of $0.03 million and $0.01 million were expensed as incurred in the years ended January 1, 2011, and January 2, 2010, respectively.

Property and equipment are stated at cost less accumulated depreciation and amortization. Depreciation is charged using the straight-line method over the estimated useful lives of the assets as follows:

Under the Capacity programs grid operators pay us an annual fee in weekly installments to stand by and provide demand response resources to the grid when the grid calls an event. We record these payments as revenue over the time when we are required to perform under these capacity programs. For some programs our obligation to perform does not match the period over which we are paid by the grid in which case we recognize revenues over the mandatory performance period.

Under the Economic programs we are paid by the grid for our commercial and industrial participants’ ability to reduce electricity usage in response to a price signal from the grid. Through our software we summarize price responsive activity and submit to the grid for payment. At the end of each monthly period the power grid approves the payments, and we in turn recognize revenue based upon the grid approval.

The vast majority of our revenue in 2009 and 2010 was processed through the Pennsylvania, New Jersey, Maryland Interconnection, LLC (“PJM”). PJM serves as the market for electrical transactions in a specific region in the United States. Our agreement with PJM is an ongoing one as we are members of PJM. These transactions are initiated by building owners, who are our participants. The transactions form the basis for our revenue.

We assess the impairment of long-lived assets whenever events or changes in circumstances indicate that their carrying value may not be recoverable from the estimated future cash flows expected to result from their use and eventual disposition. Our long-lived assets subject to this evaluation include property and equipment and amortizable intangible assets. If our estimate of future undiscounted net cash flows is insufficient to recover the carrying value of the assets, we will record an impairment loss in the amount by which the carrying value of the assets exceeds the fair value. If assets are determined to be recoverable but the useful lives are shorter than originally estimated, we depreciate or amortize the net book value of the asset over the newly determined remaining useful lives.

The Company accounts for income taxes using the asset and liability approach, which requires the recognition of deferred tax liabilities and assets for the expected future tax consequences of temporary differences between the carrying amounts and the tax basis of assets and liabilities. The effect on deferred taxes of a change in tax rates is recognized in operations in the period that includes the enactment date. In addition, we have adopted the provisions of FASB guidance on accounting for uncertainty in income taxes which provides a financial statement recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Under this guidance, we may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement.

Basic net income (loss) per share is computed by dividing net income (loss) by the weighted average number of common shares outstanding during the period. Diluted income (loss) per share is calculated by dividing net income (loss) by the weighted average number of common shares outstanding plus common share equivalents from conversion of dilutive stock options, warrants, and restricted stock using the treasury method, and convertible securities using the as-converted method, except when antidilutive. In the event of a net loss, the effects of all potentially dilutive shares are excluded from the diluted net loss per share calculation as their inclusion would be antidilutive.

The Company measures the fair value of all stock-based awards to employees, including stock options, on the grant date and records the fair value of these awards, net of estimated forfeitures, to compensation expense over the service period. The fair value of awards to consultants is measured on the dates on which performance of services is completed, with interim valuations recorded at balance sheet dates while performance is in progress. The fair value of options is estimated using the Black-Scholes valuation model, and of restricted stock is based on the Company’s closing share price on the measurement date. The value of the portion of the award that is ultimately expected to vest is recognized as expense over the requisite service periods in our Consolidated Statements of Operations.

The Company has no items of other comprehensive income or expense. Accordingly, the Company’s comprehensive loss and net loss are the same for all periods presented.

The preparation of financial statements and related disclosures in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the

reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. The Company evaluates, on an on-going basis, its estimates and judgments, including those related to revenue recognition, bad debts, impairment of intangible assets, income taxes, contingencies and litigation. Its estimates are based on historical experience and assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions.

Segments are defined as components of the Company’s business for which separate financial information is available that is evaluated by the Company’s chief operating decision maker (its CEO) in deciding how to allocate resources and assess performance. The Company presently has only one operating segment, comprising domestic operations only.

Certain reclassifications have been made to prior periods’ data to conform to the current presentation. These reclassifications had no effect on reported net losses.

Fair value measurements are determined under a three-level hierarchy for fair value measurements that prioritizes the inputs to valuation techniques used to measure fair value, distinguishing between market participant assumptions developed based on market data obtained from sources independent of the reporting entity (“observable inputs”) and the reporting entity’s own assumptions about market participant assumptions developed based on the best information available in the circumstances (“unobservable inputs”).

Fair value is the price that would be received to sell an asset or would be paid to transfer a liability (i.e., the “exit price”) in an orderly transaction between market participants at the measurement date. In determining fair value, we primarily use prices and other relevant information generated by market transactions involving identical or comparable assets (“market approach”). We also consider the impact of a significant decrease in volume and level of activity for an asset or liability when compared with normal activity to identify transactions that are not orderly.

The highest priority is given to unadjusted quoted prices in active markets for identical assets (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). Securities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The three hierarchy levels are defined as follows:

Level 1 inputs are observable inputs and use quoted prices in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date and are deemed to be most reliable measure of fair value.

Level 2 inputs are observable inputs and reflect assumptions that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the reporting entity.

Level 2 inputs include 1) quoted prices for similar assets or liabilities in active markets, 2) quoted prices for identical or similar assets or liabilities in markets that are not active, 3) observable inputs such as interest rates and yield curves observable at commonly quoted intervals, volatilities, prepayment speeds, credit risks, default rates, and 4) market-corroborated inputs.

Level 3 inputs are unobservable inputs and reflect the reporting entity’s own assumptions about the assumptions market participants would use in pricing the asset or liability based on the best information available under the circumstances.

The carrying value of the Company’s cash and cash equivalents, accounts receivable, accounts payable and other current assets and liabilities approximate fair value because of their short-term maturity. The Company has not elected the fair value option with respect to any of its assets or liabilities.

In April 2010, the FASB issued ASC Update No. 2010-17, Milestone Method of Revenue Recognition (ASU 2010-17). ASU 2010-17 provides guidance on defining a milestone and determining when it may be appropriate to apply the milestone method of revenue recognition for research or development transactions. ASU 2010-17 is effective for interim and annual reporting periods beginning after June 15, 2010, with early adoption permitted. We adopted this standard effective July 4, 2010, and its adoption did not have a material impact on our consolidated financial position or results of operations.

In January 2010, the FASB issued ASC Update No. 2010-06, Improving Disclosure about Fair Value Measurements (ASU 2010-06). ASU 2010-06 requires additional disclosures regarding fair value measurements, amends disclosures about post-retirement benefit plan assets and provides clarification regarding the level of disaggregation of fair value disclosures by investment class. ASU 2010-06 is effective for interim and annual reporting periods beginning after December 15, 2009, except for certain Level 3 activity disclosure requirements that will be effective for reporting periods beginning after December 15, 2010. The adoption of this standard did not and will not have a material impact on our consolidated financial position or results of operations.

In September 2009, the FASB ratified ASC Update No. 2009-13, Multiple-Deliverable Revenue Arrangements (ASU 2009-13). ASU 2009-13 amends existing revenue recognition accounting pronouncements that are currently within the scope of FASB ASC Subtopic 605-25. This consensus provides for two significant changes to the existing multiple element revenue recognition guidance. First, this guidance deletes the requirement to have objective and reliable evidence of fair value for undelivered elements in an arrangement and will result in more deliverables being treated as separate units of accounting. The second change modifies the manner in which the transaction consideration is allocated across the separately identified deliverables. These changes may result in entities recognizing more revenue up-front, and entities will no longer be able to apply the residual method and defer the fair value of undelivered elements. Upon adoption of these new rules, each separate unit of accounting must have a selling price, which can be based on management’s estimate when there is no other means to determine the fair value of that undelivered item, and the arrangement consideration is allocated based on the relative selling price. This accounting guidance is effective no later than fiscal years beginning on or after June 15, 2010 but may be adopted early as of the first quarter of an entity’s fiscal year. Entities may elect to adopt this accounting guidance either through prospective application to all revenue arrangements entered into or materially modified after the date of adoption or through a retrospective application to all revenue arrangements for all periods presented in the financial statements. We adopted this standard effective April 4, 2010, and its adoption did not have a material impact on our consolidated financial position or results of operations.

Management does not believe that any other recently issued, but not yet effective, accounting standards if currently adopted would have a material effect on the accompanying financial statements.

Depreciation expense (which includes amortization of leasehold improvements) included in operating expenses was $136,797 and $140,447 for the years ended January 1, 2011 and January 2, 2010, respectively.

Amortization of intangible assets included as a charge to income was $239,066 and $239,067 for the years ended January 1, 2011, and January 2, 2010, respectively. Based on the Company’s current intangible assets, amortization expense for the next five years will be as follows:

On November 5, 2010, we entered into a $4,000,000 revolving line of credit with Silicon Valley Bank and Partners For Growth III, L.P. (collectively “SVB”). Borrowings under the agreement are at an interest rate of 12.5%. The facility matures on September 30, 2011. We granted the lender a first priority security interest in all of our assets. We issued a total of 3.75 million warrants to SVB in connection with the agreement. These warrants have a term of seven years, and an exercise price of $0.15. Utilizing the Black-Scholes valuation model and assumptions of the fair value of common stock of $0.15, an expected term of five years, estimated volatility of 81.88%, a zero dividend rate and a risk free interest rate of 1.10%, the Company determined the total allocated fair value of the warrants to be $365,625. This sum was recorded within current assets, and is being amortized as interest expense on a straight line basis over the term of the credit line.

As at January 1, 2011, the Company had not yet borrowed against the line. The Company is in compliance with all covenants under this facility.

On February 26, 2009, the Company entered into a $5 million loan agreement with Aequitas Commercial Finance, LLC (“Aequitas”, see also Note 8). On December 23, 2009, the Company entered into an amendment of the convertible debt agreement. This loan agreement, as amended, provided us with a debt facility that enabled us to borrow money in a maximum principal amount not to exceed $5 million. The interest rate for funds borrowed by us in the first 12 month term was 23% payable monthly in arrears, with an additional 7% deferred interest per annum. For the balance of the term, and for all amounts borrowed under the amendment, the interest rate was 22% payable monthly in arrears, with an additional 3% deferred interest per annum. The accrued deferred interest at 7% was added to the current principal balance of the loan at the end of the first twelve-month term. The accrued deferred interest at 3% was added to the current principal balance of the loan prior to conversion. The lender was granted a first priority security interest in all of our assets, and had the right to convert up to 100% of unpaid principal and interest into shares of our common stock at an exercise price of $0.0906 per share, either on the planned maturity date of February 24, 2012, or to the extent the Company gave notice of its intent to pay down the principal balance outstanding.

On September 8, 2010, following notice that the Company intended to repay the balance of the facility, the lender opted to convert all but $1 of the remaining principal plus accrued interest, totaling $3,307,280, into 36,504,180 shares of common stock. The Company repaid the remaining $1 on September 24, 2010.

The balance of this debt facility comprises the following at January 1, 2011 and January 2, 2010:

In 2009, the Company recognized an imbedded conversion feature present in the convertible note (which equaled the intrinsic value of the conversion option on each date funds were drawn down from the facility) as additional paid-in capital and as a discount against the convertible note. The intrinsic value recognized was $452,381 in the year ended January 2, 2010, which was recorded as both additional paid-in capital and as a discount against the convertible note. In the year ended January 1, 2011, the Company recognized a further $585,758 as additional paid-in capital and as a discount against the convertible note, which arose both when funds were drawn down, and when deferred and accrued interest was added to principal prior to conversion.

This debt discount attributed to the beneficial conversion feature was amortized over the convertible note’s maturity period as interest expense. In addition, an accelerated charge of the unamortized expense, based on the proportion of debt repaid to debt outstanding prior to repayment, was recorded whenever principal was either paid down or converted to common stock. We amortized the convertible note debt discount attributed to the beneficial conversion feature and recorded non-cash interest expense in the amount of $722,821 and $315,318 for the years ended January 1, 2011 and January 2, 2010, respectively. The balance of unamortized debt discount that was expensed on conversion to common stock on September 8, 2010, including the debt discount that arose when accrued interest was transferred to principal immediately prior to conversion, amounted to $516,845.

Interest paid to Aequitas totaled $941,840 and $452,816 for the years ended January 1, 2011 and January 2, 2010, respectively. Interest payments in the year ended January 1, 2011, include $150,000 in minimum interest charges of $50,000 per month for the remaining contract term of ninety days after the balance of principal was repaid, and $257,280 in deferred and accrued interest charges paid in common stock, following conversion on September 8, 2010. In addition, the Company paid Aequitas fees of $3,000 per month from March 2009 until August 2010. Aequitas agreed to release its liens on the Company’s assets and waive all covenants and loan fees during the termination period following receipt of the $150,000 minimum interest charges, which the Company paid on October 1, 2010.

The balance owed on the debt facility (including deferred interest) was recorded as long-term debt. We remained current with our obligations under this agreement, and were in compliance with all covenants, up to the date of conversion.

We are authorized to issue up to 225,000,000 shares of common stock, no par value. As of January 1, 2011, and January 2, 2010, there were 135,735,879 and 95,629,961 shares, of common stock outstanding, respectively. Holders of the common stock are entitled to one vote per share on all matters to be voted upon by the stockholders. Holders of common stock are entitled to receive ratably such dividends, if any, as may be declared by the Board of Directors out of funds legally available therefore. Upon the liquidation, dissolution, or winding up of our company, the holders of common stock are entitled to share ratably in all of our assets which are legally available for distribution after payment of all debts and other liabilities and liquidation preference of any outstanding common stock. The outstanding shares of common stock are validly issued, fully paid and non-assessable.

During the year ended January 1, 2011, the Company issued 36,504,180 shares due to the conversion of debt of $3,307,279 at $0.0906 per share (see Note 5). In addition, the Company issued an aggregate of 650,000 and 450,000 shares of common stock during the years ended January 1, 2011, and January 2, 2010, respectively, all of which were issued to directors for their services on the Company’s board (see Note 7). Further, in the year ended January 1, 2011, the Company issued 2,500,000 shares of restricted stock to five of the Company’s officers, issued 551,738 shares of common stock due to the exercise of options (see Note 7), and retired 100,000 shares as partial repayment of a note receivable from an employee. There were no shares of restricted stock issued to officers, options exercised or shares retired in the year ended January 2, 2010.

We are authorized to issue up to 10,000,000 shares of preferred stock, no par value. The 10,000,000 shares of preferred stock authorized are undesignated as to preferences, privileges and restrictions. As the shares are issued, the Board of Directors must establish a “series” of the shares to be issued and designate the preferences, privileges and restrictions applicable to that series. As of January 1, 2011, and January 2, 2010, there were no remaining shares of any series of preferred stock outstanding.

The Company presently grants awards under the 2004 Stock Incentive Plan, as amended (the “Plan”). The purpose of the Plan is to enable the Company to attract and retain the services of (1) selected employees, officers and directors of the Company or of any subsidiary of the Company and (2) selected nonemployee agents, consultants, advisors, persons involved in the sale or distribution of the Company’s products and independent contractors of the Company or any subsidiary. The Plan is administered by the Compensation Committee of the

Board of Directors, who may grant various awards, including Incentive Stock Options (“ISOs”), Non-Statutory Stock Options (“NSOs”), Stock Appreciation Rights and Restricted Shares.

A summary of stock option and restricted stock transactions in the two years ended January 1, 2011 is as follows:

The Company has issued both options and restricted stock under the Plan. Restricted stock grants afford the recipient the opportunity to receive shares of common stock, subject to certain terms, whereas options give them the right to purchase common stock at a set price. The Company’s options generally have vesting restrictions that are eliminated over a four-year period, although vesting may be over a shorter period, or may occur on the grant date, depending on the terms of each individual award.

The Company received $39,579 for the 551,738 options exercised during the year ended January 1, 2011, which had an intrinsic value of $35,349. There were no options exercised during the year ended January 2, 2010.

The following table summarizes information concerning options outstanding and exercisable as of January 1, 2011, with the first line showing options that were in-the-money:

The aggregate intrinsic value of options outstanding and exercisable at January 1, 2011 was $225,864 and $131,589, respectively. Aggregate intrinsic value is the total pretax amount (i.e., the difference between the Company’s stock price and the exercise price) that would have been received by the option holders had all their in-the-money options been exercised.

The fair value of stock options vested in the years ended January 1, 2011 and January 2, 2010 was $574,990 and $540,533, respectively. The weighted average grant date fair value of all options granted in the years ended

January 1, 2011 and January 2, 2010 was $0.10 and $0.08, respectively, computed using the Black-Scholes pricing model and the following assumptions:

The amounts expensed for stock-based compensation related to options totaled $448,907 and $742,225 for the years ended January 1, 2011, and January 2, 2010, respectively. The amounts expensed for stock-based compensation related to restricted stock awards totaled $140,261 and $54,000 for the years ended January 1, 2011, and January 2, 2010, respectively. Of these, expenses of $112,000 and $54,000 for the years ended January 1, 2011, and January 2, 2010, respectively, relate to awards to independent directors of the Company (including two who were elected in the year ended January 1, 2011) in connection with their services as directors. These awards granted the directors a total of 650,000 and 450,000 shares of the Company’s common stock in 2010 and 2009, respectively (see Note 6). These shares are fully vested on the award date, but are restricted from transfer, except as permitted for estate planning purposes, until January 15 of the year following the award. The remaining expense of $28,261 in the year ended January 1, 2011 relates to awards totaling 2,500,000 unregistered shares to five officers of the Company on November 10, 2010, which will vest 25% after six months, then 12.5% at the end of each three month period, assuming continuous employment, so these shares will be fully vested after two years.

At January 1, 2011, the total stock-based compensation cost not yet recognized was $1,082,182. This cost is expected to be recognized over an estimated weighted average amortization period of 2.19 years. No amounts related to stock-based compensation costs have been capitalized. The tax benefit and the resulting effect on cash flows from operating and financing activities related to stock-based compensation costs were not recognized as the Company currently provides a full valuation allowance for all of its deferred taxes.

The Company has various warrants to purchase shares of its common stock outstanding, which were issued in conjunction with private placements, acquisitions and debt issuance, or in exchange for services received. All warrants contain standard anti-dilution clauses in the event of recapitalization, stock splits or combinations, merger or reorganization, dividends or distributions and similar equity adjustments, but none of the warrants presently outstanding contain anti-dilution provisions that would prevent them from being considered indexed to the Company’s own stock, so they are all accounted for within Stockholders’ Equity.

A summary of changes in the number of outstanding common stock warrants in the year ended January 1, 2011 is as follows:

The 3,750,000 warrants with an exercise price of $0.15, expiring in November 2017, were issued in conjunction with obtaining a line of credit in 2010 (see Note 5).

The Company had a convertible debt facility with Aequitas Commercial Finance LLC, an affiliate of Aequitas Management LLC which, with its associates, had beneficial ownership of more than 10% of the Company at January 1, 2011, following conversion of principal outstanding on the debt facility into 36,504,180 shares of our common stock. Aequitas has disclosed in its most recent 13D filing with the SEC that it has approximately a 30% ownership position. One of the Company’s directors (until his resignation, effective September 17, 2010), William McCormick, is also an advisor of Aequitas Management LLC. Interest paid to Aequitas totaled $941,840 and $452,816 for the years ended January 1, 2011 and January 2, 2010, respectively. Interest payments in the year ended January 1, 2011, include $150,000 in minimum interest charges of $50,000 per month for the remaining contract term of ninety days after the balance of principal was repaid, and $257,280 in accrued interest charges that were added to the principal balance of the note, and thus paid in common stock as part of the conversion on September 8, 2010. In addition, the Company paid Aequitas fees of $3,000 per month from March 2009 until August 2010. See also Notes 5 and 6 above.

Income tax expense consisted of $48,137 and $2,680 provision for various states for the years ended January 1, 2011, and January 2, 2010, respectively. We made no provision for federal income taxes due to our federal net operating loss carryforwards to offset both regular taxable income and alternative minimum taxable income and our utilization of deferred state tax benefits

The provision for income taxes for the years ended January 1, 2011, and January 2, 2010, differs from the amount which would be expected as a result of applying the statutory tax rates to the losses before income taxes due primarily to changes in the valuation allowance to fully reserve net deferred tax assets.

As of January 1, 2011, and January 2, 2010, EnergyConnect had deferred tax assets primarily consisting of its net operating loss carryforwards. However, because of cumulative losses in several consecutive years, the Company has recorded a full valuation allowance such that its net deferred tax asset is zero.

We must also make judgments whether the deferred tax assets will be recovered from future taxable income. To the extent that we believe that recovery is not likely, we must establish a valuation allowance. A valuation allowance has been established for deferred tax assets which we do not believe meet the “more likely than not” criteria. Our judgments regarding future taxable income may change due to changes in market conditions, changes in tax laws, tax planning strategies or other factors. If our assumptions and consequently our estimates change in the future, the valuation allowances we have established may be increased or decreased, resulting in a respective increase or decrease in income tax expense.

In July 2006, the FASB issued authoritative guidance on accounting for uncertainty in income taxes, which requires that realization of an uncertain income tax position must be more likely than not (i.e. greater than 50% likelihood of receiving a benefit) before it can be recognized in the consolidated financial statements. The guidance further provides the benefit to be realized assuming a review by tax authorities having all relevant information and applying current conventions. The interpretation also clarifies the consolidated financial statements classification of tax related penalties and interest and set forth new disclosures regarding unrecognized tax benefits. The adoption of ASC 740-10 did not have a material impact on our financial position or results of operations. The Company has not provided any reserve as of January 1, 2011.

At January 1, 2011, the Company had available net operating loss carryforwards of approximately $25.4 million for federal income tax and $20.1 million for state (including $2.5 million for California, where the use of carryforwards has been suspended) purposes. Such carryforwards may be used to reduce consolidated taxable income, if any, in future years through their expiration in 2011 to 2029 subject to limitations of Section 382 of the Internal Revenue Code, as amended. Utilization of net operating loss carryforwards may be limited due to the ownership changes resulting from the Company’s initial public offering in 1995 and the Company’s acquisitions, stock issuances and debt conversion since then. In addition, the Company has research and development credits aggregating approximately $47,000 for income tax purposes at January 1, 2011. Such credits may be used to reduce taxes payable, if any, in future years through their expiration in 2011 and 2012.

The following table presents the computation of basic and diluted losses per share:

The following potential common shares arising from stock options, restricted stock, warrants and convertible debt were excluded from the computation of diluted net loss per share attributable to holders of common stock as they had anti-dilutive effects for the periods indicated:

We have three facility lease agreements. Aggregate future minimum obligations for leases in effect as of January 1, 2011, are as follows:

Rent expense charged to operations for the years ended January 1, 2011, and January 2, 2010, was approximately $471,000 and 365,000, respectively.

The Company appointed Kevin R. Evans President and Chief Executive effective January 5, 2009. Pursuant to the employment agreement, the Company agreed to pay Mr. Evans an annual base salary of $300,000. In February, 2009, Mr. Evans signed an amendment to his employment agreement lowering his salary to $225,000. In addition, and pursuant to a change of control agreement, the Company has agreed to pay Mr. Evans twelve months of severance pay upon a change of control of the Company or upon Mr. Evans termination without cause or his resignation for good reason – based on his original salary of $300,000. Following the announcement of the planned merger (see Note 15), Mr. Evans’ salary has reverted to the original annual base of $300,000.

From time to time, the Company may become involved in various lawsuits and legal proceedings which arise in the ordinary course of business. Litigation is subject to inherent uncertainties, and an adverse result in these or other matters may arise from time to time that may harm our business. There were no ongoing legal proceedings during the year ended January 1, 2011. See Note 15 for legal proceedings that have subsequently arisen.

The Company has a 401(k) plan (the “Plan”) that allows eligible employees to contribute part of their annual compensation to the Plan, subject to certain limitations. Each employee directs the investment of their contributions across a series of mutual funds, and their contributions vest immediately. The Company does not make any matching contributions, and the costs of administering the Plan are not material.

The accompanying audited consolidated financial statements have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. As shown in the consolidated financial statements during the years ended January 1, 2011 and January 2, 2010, the Company incurred net losses of $0.3 million and $3.2 million, respectively and generated negative cash flow from operations in the amount of $1.1 million and $1.3 million, respectively. These factors among others indicate that the Company may be unable to continue as a going concern for a reasonable period of time. While we believe the revolving line of credit with SVB (see Note 5), along with cash generated by operations, will be adequate for our working capital needs until at least September 30, 2011, we may need to renew the line of credit or obtain additional capital in order to sustain and expand operations thereafter.

The following table sets forth selected unaudited quarterly information for the Company’s years ended January 1, 2011, and January 2, 2010:

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive and financial officers, as appropriate to allow timely decisions regarding required disclosure.

As of the end of the period covered by this Annual Report, we carried out an evaluation, under the supervision and with the participation of our Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)). Based on that evaluation our CEO and CFO concluded, as of the end of such period, our disclosure controls and procedures were effective in ensuring that the information required to be filed or submitted under the Exchange Act is recorded, processed, summarized and reported as specified in the Securities and Exchange Commission’s rules and forms, and accumulated and communicated to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure. Our management has undergone a testing process with respect to our disclosure controls and procedures which includes the establishment of internal policies related to financial reporting.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Those rules define internal control over financial reporting as a process designed to provide reasonable assurance regarding the reliability of

financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Our internal control over financial reporting includes those policies and procedures that:

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projection of any evaluation of effectiveness to future periods is subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

A material weakness is a control deficiency, or combination of control deficiencies, that results in there being more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected.

Management’s assessment of the effectiveness of our internal control over financial reporting has not identified any material weaknesses as of January 1, 2011. In making this assessment, management used the criteria set forth in “Internal Control over Financial Reporting – Guidance for Smaller Public Companies” issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”).

This annual report does not include an attestation report of the Company’s independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s independent registered public accounting firm pursuant to rules of the SEC that permit the Company to provide only management’s report in this annual report.

There were no changes in internal controls over financial reporting that occurred during the period covered by this report that have materially affected, or are reasonably likely to materially effect, our internal control over financial reporting.

Information required by this item is incorporated by reference to the EnergyConnect Proxy Statement for the 2011 Annual Meeting of Shareholders.

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

Information required by this item is incorporated by reference to the EnergyConnect Proxy Statement for the 2011 Annual Meeting of Shareholders.

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

Information required by this item is incorporated by reference to the EnergyConnect Proxy Statement for the 2011 Annual Meeting of Shareholders.

In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


ENERGYCONNECT GROUP, INC.

By:		/s/ Kevin R. Evans
		Kevin R. Evans Chief Executive Officer

KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Kevin R. Evans and Amir Ameri, jointly and severally, his or her attorneys-in-fact, each with the power of substitution, for him or her in any and all capacities, to sign any amendments to this Annual Report on Form 10-K, and to file the same, with exhibits thereto and other documents in connection therewith with the Securities and Exchange Commission, hereby ratifying and confirming all that each of said attorneys-in-fact, or his or her substitute or substitutes may do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated:


Oregon		93-0935149
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)


901 Campisi Way, Suite 260, Campbell, CA		95008
(Address of Principal Executive Offices)		(Zip Code)


¨ Large accelerated filer		¨ Accelerated filer		¨ Non-accelerated filer		x Smaller reporting company


		Page
Item 1.	Business		1
Item 1A.	Risk Factors		11
Item 1B.	Unresolved Staff Comments		23
Item 2.	Properties		23
Item 3.	Legal Proceedings		23
Item 4.	(Removed and Reserved)		23

PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Repurchases of Equity Securities		24
Item 6.	Selected Financial Data		26
Item 7.	Management’s Discussion and Analysis of Financial Condition And Results of Operations		27
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		34
Item 8.	Financial Statements and Supplementary Data		35
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		55
Item 9A(T).	Controls and Procedures		55
Item 9B.	Other Information		56

PART III

Item 10.	Directors, Executive Officers, and Corporate Governance		57
Item 11.	Executive Compensation		57
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		57
Item 13.	Certain Relationships and Related Transactions, and Director Independence		57
Item 14.	Principal Accountant Fees and Services		57

PART IV

Item 15.	Exhibits and Financial Statement Schedules		58

SIGNATURES			60

EXHIBIT INDEX			61


Location	Square Feet	Primary Use	Lease Terms
Campbell, CA	5,218 sq ft	Office space (headquarters)	Lease expires August 31, 2012

Lake Oswego, OR	9,693 sq ft	Office space	Lease expires July 31, 2011

Conshohocken, PA	2,562 sq ft	Office space	Lease expires September 30, 2012


Fiscal 2009	High		Low
First Quarter	$	0.21	$	0.05
Second Quarter		0.14		0.08
Third Quarter		0.09		0.05
Fourth Quarter		0.14		0.04

Fiscal 2010	High		Low
First Quarter	$	0.20	$	0.07
Second Quarter		0.19		0.12
Third Quarter		0.26		0.14
Fourth Quarter		0.18		0.09


	Number of Securities to be issued upon exercise of outstanding options and warrants		Weighted average exercise price of outstanding options and warrants		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Plan category	(a)		(b)		(c)
Equity compensation plans approved by security holders		12,770,251	$	0.20		2,163,985
Equity compensation plans not approved by security holders		14,040,874	$	1.44		N/A

Total		26,811,125	$	0.85		N/A


	January 1, 2011			January 2, 2010			January 3, 2009			December 29, 2007			December 30, 2006
Statements of Operations:
Revenue	$	31,644		$	19,921		$	25,859		$	12,626		$	3,202	⁽¹⁾
Cost of revenue		19,475			12,883			18,420			8,789			3,032	⁽¹⁾
Gross profit		12,169			7,038			7,439			3,837			170	⁽¹⁾
Operating expense		10,849			9,317			41,486	⁽³⁾		8,180			6,076	⁽¹⁾
Income (loss) from continuing operations		1,320			(2,279	)		(34,066	)		(4,341	)		1,561	⁽¹⁾
Net income (loss)		(308	)		(3,222	)		(34,077	)		(14,036	)		833	⁽¹⁾
Net income (loss) per share	$	—		$	(0.03	)	$	(0.37	)	$	(0.17	)	$	0.01	⁽¹⁾
Weighted average shares		107,833			95,481			91,245			82,536			71,374

Balance Sheet Data:
Cash and cash equivalents	$	1,136		$	1,062		$	410		$	758	⁽²⁾	$	2,193	⁽²⁾
Total assets		15,920			9,775			7,357			48,086	⁽²⁾		57,147	⁽²⁾
Long-term liabilities		25			1,913			—			61	⁽²⁾		1,261	⁽²⁾
Total liabilities		11,312			9,746			5,361			16,828	⁽²⁾		13,531	⁽²⁾
Shareholders’ equity	$	4,608		$	29		$	1,996		$	31,258	⁽²⁾	$	43,616	⁽²⁾


	2010	2009
Risk-free interest rate	1.15 – 2.60%	1.80 – 2.75%
Expected dividend yield	0%	0%
Expected term	5 years	5 years
Expected volatility	82%	118%


	Total		Less than 1 Year		1-2 Years		3-5 Years		More than 5 Years
Operating Leases	$	436,342	$	312,834	$	123,508	$	—	$	—
Capital Expenditure		150,000		150,000		—		—		—

Total obligations	$	586,342	$	462,834	$	123,508	$	—	$	—


	January 1, 2011			January 2, 2010
Assets
Current assets:
Cash and cash equivalents	$	1,136,074		$	1,062,306
Accounts receivable, net of zero allowance		12,612,560			6,811,495
Other current assets		745,383			237,242

Total current assets		14,494,017			8,111,043
Property and equipment, net		188,696			187,085
Intangible assets, net		1,159,695			1,398,761
Other assets		77,508			78,035

Total assets	$	15,919,916		$	9,774,924

Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable	$	10,796,332		$	7,508,561
Other current liabilities		490,653			324,886

Total current liabilities		11,286,985			7,833,447

Long term liabilities:
Note payable, net of debt discount		—			1,912,937
Other liabilities		24,804			—

Commitments and contingencies (Note 12)

Stockholders’ equity:
Preferred Stock, no par value, 10,000,000 shares authorized, none outstanding at January 1, 2011 or January 2, 2010		—			—
Common Stock, no par value, 225,000,000 shares authorized, 135,735,879 and 95,629,961 shares issued and outstanding at January 1, 2011 and January 2, 2010, respectively		162,911,984			158,024,289
Accumulated deficit		(158,303,857	)		(157,995,749	)

Total stockholders’ equity		4,608,127			28,540

Total liabilities and stockholders’ equity	$	15,919,916		$	9,774,924


	Common Stock						Accumulated Deficit			Total
	Shares			Amount			Accumulated Deficit			Total
Balances as of January 3, 2009		95,179,961		$	156,769,983		$	(154,773,728	)	$	1,996,255
Restricted shares issued to directors		450,000			54,000			—			54,000
Stock-based compensation related to options		—			742,225			—			742,225
Collection of notes receivable for exercise of stock options		—			5,700			—			5,700
Beneficial conversion feature related to convertible debt		—			452,381			—			452,381
Net loss		—			—			(3,222,021	)		(3,222,021	)

Balances as of January 2, 2010		95,629,961		$	158,024,289		$	(157,995,749	)	$	28,540
Restricted shares issued to directors		650,000			112,000			—			112,000
Stock-based compensation related to options		—			448,907			—			448,907
Collection of notes receivable for exercise of stock options		—			13,786			—			13,786
Repayment of note receivable via surrender of stock		(100,000	)		(13,500	)		—			(13,500	)
Common shares issued upon exercise of options		551,738			39,579			—			39,579
Restricted stock issued to officers		2,500,000			28,261			—			28,261
Beneficial conversion feature related to convertible debt		—			585,758			—			585,758
Common stock issued on conversion of debt		36,504,180			3,307,279			—			3,307,279
Fair value of warrants issued					365,625			—			365,625
Net loss		—			—			(308,108	)		(308,108	)

Balances as of January 1, 2011		135,735,879		$	162,911,984		$	(158,303,857	)	$	4,608,127


	January 1, 2011			January 2, 2010
Cash flows from operating activities:
Net loss	$	(308,108	)	$	(3,222,021	)
Reconciling adjustments
Depreciation of equipment		136,797			140,447
Amortization of intangible assets		239,066			239,067
Stock-based compensation related to options		448,907			742,225
Stock-based compensation related to restricted stock		140,261			54,000
Amortization of debt discount including beneficial conversion feature		722,821			315,318
Change in operating assets and liabilities:
Accounts receivable		(5,801,065	)		(2,437,677	)
Other current assets		(156,016	)		331,902
Other assets		527			(7,159	)
Accounts payable		3,287,771			2,392,265
Other liabilities		190,571			197,871

Net cash used in operating activities		(1,098,468	)		(1,253,762	)

Cash flows from investing activities:
Purchase of property and equipment		(138,408	)		(28,270	)
Increase in intangible assets		—			(4,206	)

Net cash used in investing activities		(138,408	)		(32,476	)

Cash flows from financing activities:
Repayments on line of credit		—			(117,257	)
Proceeds from debt financing, net of repayments		1,257,279			2,050,000
Proceeds from exercise of stock options		39,579			—
Collection of notes receivable for exercise of stock options		13,786			5,700

Net cash provided by financing activities		1,310,644			1,938,443

Net increase in cash and cash equivalents		73,768			652,205
Cash and cash equivalents at beginning of the period		1,062,306			410,101

Cash and cash equivalents at end of the period	$	1,136,074		$	1,062,306

Supplemental disclosures of cash flow information:
Interest paid (includes $257,280 paid in conversion shares in the year ended January 1, 2011)	$	949,593		$	427,919
Income taxes paid	$	—		$	—
Supplemental schedule of non-cash investing and financing activities:
Beneficial conversion feature related to convertible debt	$	585,758		$	452,381
Common stock issued on conversion of debt	$	3,307,279		$	—
Issuance of warrants to obtain line of credit	$	365,625		$	—
Repayment of note receivable via surrender of stock	$	13,500		$	—


Computers and software		3 years
Leasehold improvements		3 to 5 years, or remaining lease term if shorter
Furniture and fixtures		5 years


	January 1, 2011			January 2, 2010
Developed technology	$	2,394,873		$	2,394,873
Less accumulated amortization		(1,235,178	)		(996,112	)

	$	1,159,695		$	1,398,761


Year	Amortization Expense
2011	$	239,067
2012		239,067
2013		239,067
2014		239,067
Thereafter		203,427

Total	$	1,159,695


	January 1, 2011			January 2, 2010
Convertible note payable:
Draw-down of principal, net	$	3,049,999		$	2,050,000
Deferred interest added to principal		257,280			—
Conversion to common stock		(3,307,279	)		—

Net principal balance		—			2,050,000
Debt discount – beneficial conversion feature, net of accumulated amortization of $1,038,139 and $315,318 at January 1, 2011, and January 2, 2010, respectively.		—			(137,063	)

Note payable, net of debt discount	$	—		$	1,912,937


	Shares Available for Grant			Stock Options					Restricted Stock
	Shares Available for Grant			Number of Options Outstanding			Weighted Average Exercise Price		Number of Shares Outstanding			Weighted Average Grant-Date Fair Value
Balance at January 4, 2009		10,507,104			6,078,870		$	0.81		—		$	—
Granted		(11,363,249	)		11,363,249		$	0.08		—		$	—
Granted – restricted stock		(450,000	)		—		$	—		450,000		$	0.12
Vested – restricted stock		—			—		$	—		(450,000	)	$	0.12
Cancelled or expired		2,932,589			(2,932,589	)	$	0.41		—		$	—

Balance at January 2, 2010		1,626,444			14,509,530		$	0.29		—		$	—
Granted		(2,860,000	)		2,860,000		$	0.15		—		$	—
Granted – restricted stock		(650,000	)		—		$	—		650,000		$	0.17
Exercised		—			(551,738	)	$	0.07		—		$	—
Vested – restricted stock		—			—		$	—		(650,000	)	$	0.17
Cancelled or expired		4,047,541			(4,047,541	)	$	0.52		—		$	—

Balance at January 1, 2011		2,163,985			12,770,251		$	0.20		—		$	—


	Options Outstanding						Options Exercisable
Range of Exercise Prices	Number Outstanding as of January 1, 2011		Weighted Average Remaining Contractual Life (in Years)		Weighted Average Exercise Price		Number Exercisable as of January 1, 2011		Weighted Average Remaining Contractual Life (in Years)		Weighted Average Exercise Price
$0.050 - $0.109		4,398,896		7.65	$	0.06		2,500,457		7.24	$	0.06
$0.110 - $2.702		8,371,355		4.86	$	0.28		3,479,789		2.57	$	0.43

		12,770,251		5.82	$	0.20		5,980,246		4.52	$	0.27


Balance on January 2, 2010		During the Year Ended January 1, 2011							Balance on January 1, 2011		Exercise Price		Expiration Date
Balance on January 2, 2010		Granted		Exercised		Forfeited			Balance on January 1, 2011		Exercise Price		Expiration Date
	—		3,750,000		—		—			3,750,000	$	0.15	November 2017
	316,425		—		—		(316,425	)		—	$	0.38	March to July 2010
	100,000		—		—		—			100,000	$	0.40	May 2013
	4,565,874		—		—		—			4,565,874	$	0.60	May 2013
	2,752,323		—		—		(2,752,323	)		—	$	0.90	September to October 2010
	19,695,433		—		—		(19,695,433	)		—	$	2.58	October 2010
	5,625,000		—		—		—			5,625,000	$	3.00	June 2011

	33,055,055		3,750,000		—		(22,764,181	)		14,040,874


	January 1, 2011			January 2, 2010
State Taxes	$	10,882		$	891
Accruals and Reserves		33,401			—
Stock-based Compensation		97,960			—
Net Operating Loss Carryforwards		9,315,383			11,393,048
Research and Development Credits		46,510			73,431

Total Deferred Tax Assets		9,504,136			11,467,370
Valuation Allowance		(9,032,291	)		(11,261,191	)

Total Deferred Tax Assets after Valuation Allowance		471,845			206,179

Fixed Assets and Intangibles		(471,845	)		(206,179	)

Total Deferred Tax Liabilities		(471,845	)		(206,179	)

Net Deferred Tax Asset	$	—		$	—


	Year ended January 1, 2011			Year ended January 2, 2010
Net loss	$	(308,108	)	$	(3,222,021	)

Basic and diluted loss per share	$	—		$	(0.03	)

Basic and diluted weighted average common shares outstanding		107,832,925			95,480,783


	Year Ended
	January 1, 2011		January 2, 2010
Outstanding options		13,527,096		14,280,927
Unvested restricted stock		357,143		—
Outstanding warrants		28,351,363		33,055,055
Shares issuable upon conversion of convertible note		27,642,357		23,034,774

Total potential common shares excluded from denominator for diluted EPS computation		69,877,959		70,370,756


Year	Amount
2011	$	312,834
2012		123,508
2013 and beyond		—

Total	$	436,342


	Year ended January 1, 2011
	First			Second			Third		Fourth
Revenue	$	7,023,833		$	6,442,099		$	17,408,942	$	769,481
Gross profit	$	4,569,242		$	1,744,249		$	5,308,161	$	547,122
Net income (loss)	$	2,081,826		$	(1,089,596	)	$	1,451,505	$	(2,751,843	)
Net income (loss) per share – basic and diluted	$	0.02		$	(0.01	)	$	0.01	$	(0.02	)

	Year ended January 2, 2010
	First			Second			Third		Fourth
Revenue	$	1,210,211		$	7,521,756		$	10,337,922	$	850,636
Gross profit	$	568,223		$	3,223,973		$	3,116,750	$	129,322
Net income (loss)	$	(2,081,574	)	$	601,050		$	528,411	$	(2,269,908	)
Net income (loss) per share – basic and diluted	$	(0.02	)	$	0.01		$	0.01	$	(0.02	)


Reports of Independent Registered Public Accounting Firms			35

Financial Statements:

Consolidated Balance Sheets			37

Consolidated Statements of Operations			38

Consolidated Statements of Stockholders’ Equity			39

Consolidated Statements of Cash Flows			40

Notes to Consolidated Financial Statements			41


Exhibit No.		Description
2.1		Acquisition Agreement by and between Registrant and CEI Acquisition, LLC dated as of November 27, 2007 (Incorporated by reference to Exhibit 2.1 to Registrant’s Current Report on Form 8-K filed December 3, 2007).

2.2		First Amendment to Acquisition Agreement by and between CEI Acquisition, LLC and Registrant dated January 30, 2008 (Incorporated by reference to Exhibit 2.1 to Registrant’s Current Report on Form 8-K filed February 5, 2008).

2.3		Agreement and Plan of Merger, dated as of March 2, 2011, by and among EnergyConnect Group, Inc., Johnson Controls Holding Company, Inc., and Eureka, Inc. (Incorporated by reference to Exhibit 2.1 to Registrant’s Current Report on Form 8-K filed March 7, 2011).

3.1		Fourth Amended and Restated Bylaws (Incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed December 23, 2010).

3.2		Eighth Restated Articles of Incorporation (Incorporated by reference to Exhibit 3(i) to Registrant’s Current Report on Form 8-K filed March 21, 2005).

4.1		Form of Warrant to purchase shares of common stock (Incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K filed May 13, 2008).

4.2		Form of Warrant to purchase shares of common stock dated as of November 5, 2010.

10.1†		Microfield Group, Inc. 2004 Stock Incentive Plan (Incorporated by reference to Exhibit 10.22 to the Registrant’s Annual Report on Form 10-KSB filed May 20, 2005).

10.2		Form of Securities Purchase Agreement dated May 7, 2008 by and among Microfield Group, Inc. and the purchasers set forth on the signature page thereto (Incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed May 13, 2008).

10.3		Form of Registration Rights Agreement dated May 7, 2008 by and among Microfield Group, Inc. and the purchasers signatory thereto (Incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K filed May 13, 2008).


Exhibit No.		Description
10.4		First Amendment dated December 23, 2009 to Loan Agreement dated February 26, 2009 by and among EnergyConnect Group, Inc. and Aequitas Commercial Finance, LLC, as amended December 23, 2009 (Incorporated by reference to Exhibit 10.4 to the Registrant’s Annual Report on Form 10-K filed March 18, 2010).

10.5†		Employment Offer Letter to John Stremel (Chief Technology Officer), dated as of August 5, 2005 (Incorporated by reference to Exhibit 10.5 to the Registrant’s Annual Report on Form 10-K filed March 18, 2010).

10.6†		Employment Offer Letter to William Munger (VP of Human Resources and Chief of Staff), dated as of August 2, 2006 (Incorporated by reference to Exhibit 10.6 to the Registrant’s Annual Report on Form 10-K filed March 18, 2010).

10.7†		Employment Offer Letter to Andrew Warner (formerly Chief Financial Officer), dated as of July 21, 2009 (Incorporated by reference to Exhibit 10.7 to the Registrant’s Annual Report on Form 10-K filed March 18, 2010).

10.8†		Employment Agreement with Kevin Evans (Chief Executive Officer) dated as of January 5, 2009 (Incorporated by reference to Exhibit 10.8 to the Registrant’s Annual Report on Form 10-K filed March 18, 2010).

10.9†		Change of Control Agreement with Kevin Evans (Chief Executive Officer) dated as of January 5, 2009 (Incorporated by reference to Exhibit 10.9 to the Registrant’s Annual Report on Form 10-K filed March 18, 2010).

10.10		Loan and Security Agreement dated as of November 5, 2010 (Incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed November 10, 2010).

10.11†		Incentive Plan effective as of January 20, 2011 (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed January 27, 2011).

10.12		Consulting Agreement with Tatum dated December 2, 2010.

14		Code of Business Conduct and Ethics (Incorporated by reference to Exhibit 14 to the Registrant’s Amendment No. 1 to Form S-1 filed on May 2, 2006).

21.1		Subsidiaries of the Registrant.

23.1		Consent of SingerLewak LLP, Registered Independent Accountants.

23.2		Consent of RBSM LLP, Registered Independent Accountants.

31.1		Certification of Chief Executive Officer pursuant to Section 302, of the Sarbanes-Oxley Act of 2002.

31.2		Certification of Chief Financial Officer pursuant to Section 302, of the Sarbanes-Oxley Act of 2002.

32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


Signature		Title
/s/Kevin R. Evans		Chief Executive Officer and Director
Kevin R. Evans		Date: April 1, 2011

/s/Amir Ameri		Chief Financial Officer
Amir Ameri		Date: April 1, 2011

/s/ Gary D. Conley		Chairman of the Board and Director
Gary D. Conley		Date: April 1, 2011

/s/Rodney M. Boucher		Director
Rodney M. Boucher		Date: April 1, 2011

/s/ N. Beth Emery		Director
N. Beth Emery		Date: April 1, 2011

/s/ Andrew N. MacRitchie		Director
Andrew N. MacRitchie		Date: April 1, 2011

/s/ John P. Metcalf		Director
John P. Metcalf		Date: April 1, 2011

/s/ Thomas P. Reiter		Director
Thomas P. Reiter		Date: April 1, 2011

/s/ Kurt E. Yeager		Director
Kurt E. Yeager		Date: April 1, 2011