Attached files

file filename
EX-10.4 - EXHIBIT 10.4 - EnergyConnect Group Incex10_4.htm
EX-10.6 - EXHIBIT 10.6 - EnergyConnect Group Incex10_6.htm
EX-10.7 - EXHIBIT 10.7 - EnergyConnect Group Incex10_7.htm
EX-32.2 - EXHIBIT 32.2 - EnergyConnect Group Incex32_2.htm
EX-31.2 - EXHIBIT 31.2 - EnergyConnect Group Incex31_2.htm
EX-23.1 - EXHIBIT 23.1 - EnergyConnect Group Incex23_1.htm
EX-32.1 - EXHIBIT 32.1 - EnergyConnect Group Incex32_1.htm
EX-10.9 - EXHIBIT 10.9 - EnergyConnect Group Incex10_9.htm
EX-31.1 - EXHIBIT 31.1 - EnergyConnect Group Incex31_1.htm
EX-10.5 - EXHIBIT 10.5 - EnergyConnect Group Incex10_5.htm
EX-10.8 - EXHIBIT 10.8 - EnergyConnect Group Incex10_8.htm


U.S. Securities and Exchange Commission

Washington, D. C. 20549

Form 10-K

x ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended January 2, 2010

o TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from ________ to ________

Commission File Number : 0-26226

ENERGYCONNECT GROUP, INC.
(Exact Name of Registrant as Specified in Its Charter)
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 and zip code)

(408) 370-3311
(Registrant’s telephone number)

Securities registered under Section 12(b) of the Exchange Act: None
Securities registered under Section 12(g) of the Exchange Act:
Common Stock

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

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).  o Yes      o 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):

o Large accelerated Filer
o Accelerated filer
o Non-accelerated filer
x Smaller reporting company

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


 
1

 

The aggregate market value of the voting stock and non-voting common equity held by non-affiliates (based upon the closing sale price of $0.09 per share on the Over the Counter Bulletin Board on July 2, 2009) was $8,580,216.

The number of shares outstanding of the registrant’s Common Stock as of March 9, 2010 was 95,629,961 shares.
 
 
DOCUMENTS INCORPORATED BY REFERENCE

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.
 

ENERGYCONNECT GROUP, INC.
FORM 10-K INDEX

PART I
 
 
 
Page
 
 
 
 
Item 1.
 
3
 
 
 
 
Item 1A.
 
9
       
Item 2.
 
17
 
 
 
 
Item 3.
 
17
 
 
 
 
PART II
 
 
 
 
Item 4.
 
18
 
 
 
 
Item 5.
 
19
 
 
 
 
Item 6.
 
20
 
 
 
 
Item 6A.
 
26
 
 
 
 
Item 7.
 
27
 
 
 
 
Item 8.
 
47
 
 
 
 
Item 8A.
 
47
 
 
 
 
Item 8B.
 
48
 
 
 
 
PART III
 
 
 
 
Item 9.
 
49
 
 
 
 
Item 10.
  Executive Compensation  49
       
Item 11.
  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters  49
       
Item 12.
  Certain Relationships, Related Transactions and Director Independence  49
       
Item 13.
  Principal Accountant Fees and Services  49
       
PART IV
 
 
 
 
Item 14.
  50

 
2


PART I

ITEM 1.  BUSINESS

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.

Business Summary

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 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 the grid and get paid by agreeing to stand by and curtail based upon a grid event or responding to a price signal. Our customers are commercial and industrial consumers of electricity with whom we contract to identify, develop and if necessary implement curtailment strategies. We enroll our customers 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 customers in accordance with their contract with us.

Description of Market

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 customers to 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.
 
Real-Time Response

Our customers 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 (KW) or megawatts per hour (MW) at the actual LMP less the customer’s retail rate. We in turn pay our customers a percentage of the payment we receive based upon our individual contracts with our customers.

Real-Time Dispatch

Our customers 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 customers of their need to reduce demand. EnergyConnect is paid for our customers standing by to respond to the grid operator’s request to curtail. We in turn pay our customers a percentage of the payment we receive based upon our individual contracts with our customers.

Day-Ahead

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 customers 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 customers buying energy at the real-time rate.

 
3


Corporate Background
 
The Company was incorporated in October 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 2007 we determined that ECI had grown to a self-sustainable transition point, and in November 2007, we agreed to sell the stock of CEI.  The sale was completed on April 24, 2008.   Financial statements and accompanying notes included in this report include disclosure of the results of operations for CEI, for all periods presented, as discontinued operations.  All significant inter-company accounts and transactions have been eliminated in consolidation.

Corporate Strategy

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 the 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 customers. We intend to increase the number of customers by adding additional distribution channels for our proprietary software technology and by configuring our software to work in more energy markets within North America.

New Sales Channels

Historically, we have relied on a direct sales organization supplemented by sales agents to identify and sign up commercial and industrial customers.  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 customers, the cost of customer acquisition will be significantly lower if we can develop these channels and partnerships.

Technology Licenses

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 customers who are under contract with us.  We offer a software-based solution to commercial and industrial customers that, in addition to providing our customers with the ability to transact in the wholesale electricity markets, provides a range of electricity information services for example by showing current electricity loads for our customers, forecast prices, current tariff structures and other information of interest to our customers.
 
We believe that our customers 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 tariff structures such as critical peak pricing or real-time pricing where 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.

Products and Services

We provide grid operators with products similar to those the grid operator purchases from electric power generators. Our products can be grouped into three main categories: capacity, economic, or price-based energy, and reserves.

Capacity – EventConnect

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.  Customers 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.

 
4


EventConnect is our software solution for our customers which allows them to manage their capacity programs.  We, in turn, are paid by the grid for having our customers with standby capability reduce usage with specific timing requirements for response and duration.  Under the PJM program, the annual commitment and registration is undertaken in the spring for the following 12 months starting in June of each year and includes 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 testing period from June to September.  Obligations to curtail usage within PJM are for 6 hour durations with a 2 to 24 hour notice for a maximum of 10 times per year.  An event under the capacity program within PJM has not been called for the past three years, although we did test our customers’ ability to respond in June 2009, 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 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.

Economic, or Price-Based Energy – FlexConnect

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 customers to engage in wholesale electricity markets.  FlexConnect is a hosted SaaS solution that allows our customers to use an easy-to-use interface 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 customers from a calculated baseline of usage.

We work with our commercial and industrial customers 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 customers, 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 customers 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 curtail 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 customers 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 customers would like us to notify them of an opportunity to curtail.  We then establish the baseline of electricity usage at our customer’s facilities.  This involves complex calculations that are performed by our proprietary software based on rules that have been set by the grid operator and includes an estimate of usage based on the previous four days with the most similar situations and includes adjustments based on weather conditions. The baseline sets the bar against which the curtailment strategy is measured. Finally, we test our customer 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 customers are ready to transact with the wholesale electricity market.

FlexConnect continually monitors the market for price signals and provides our customers with estimates of the next days’ hourly price of electricity based on data contained in the day-ahead market. Customers are notified electronically, based upon their pre-determined notification criteria, when there is an opportunity for them to participate in the market.  The customer’s facility manager is then required to decide whether to participate or not.  If they elect to participate, the customer selects 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 customer as a result of taking the curtailment actions. If the customer 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 customer physically executes the strategy by shutting down plant or changing the parameters on its equipments (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.

 
5


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 customers 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.

Reserves, Ancillary Services, and Others

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 customers are active in this market.

Electric Power Industry

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 has been developing a National Action Plan on Demand Response.  A draft of this report was released for comment in March, 2010.  We expect a final report to be released later in 2010 and it is expected to help to define a clearer vision of how demand response will develop in the future.

Anatomy and Challenges of Demand Response

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.

 
6


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.

Regulatory Impacts

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 customers 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 customers benefit by maximizing income potential and reducing energy costs.

PJM

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 customers 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.

The PJM Interconnection Capacity program establishes 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.

Customers

Our customers 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 customer we bring into the portfolio adds to our capability to serve the needs of the wholesale electricity market.

Sales Revenue

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.

Competition

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 customers’ 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.

 
7


 
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 customers.  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.

Research and development costs related to both present and future products are expensed in the period incurred.  The Company incurred approximately $0.8 million and $1.7 million of expenditures on research and development for the years ended January 2, 2010, and January 3, 2009, respectively.

Intellectual Property

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 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.

Government Approval or Regulations

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 customers. 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.

Employees

As of January 2, 2010, we directly employed 34 full time employees and one part time contractor.  None of our employees are covered by collective bargaining agreements.

Principal Offices

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.

Debt Facility

On February 26, 2009, we entered into a Business Loan Agreement, a Convertible Secured Promissory Note and Commercial Security Agreement (collectively the “Loan Agreements”) with Aequitas Commercial Finance, LLC (“Aequitas”).  Aequitas is a commercial finance company that provides loan and lease financing to companies.  Aequitas is managed by Aequitas Capital Management, Inc. (“Aequitas Capital”).  Aequitas Capital and its affiliates have previously provided us with debt and equity financing.  William C. McCormick, the Chairman of our Board of Directors, is a member of the Advisory Board of Aequitas Capital.  On December 23, 2009, we signed an amendment to the Loan Agreements.

Pursuant to the terms and conditions of the Loan Agreement and the amendment, Aequitas will provide us with a debt facility enabling us to borrow money in a maximum principal amount not to exceed $5,000,000.  The current interest rate for funds borrowed by us in the first twelve-month term is twenty-three percent (23%) with an additional seven percent (7%) deferred interest per annum.  The accrued deferred interest shall be added to the then current principal balance of the loan at the end of the first twelve- month term.  The interest rate for funds borrowed over the balance of the term is twenty-two percent (22%) with an additional three percent (3%) deferred interest per annum.  The accrued deferred interest shall be added to the then current principal balance of the loan at the end each month.  The loan matures on February 24, 2012.  As security for this loan, we granted Aequitas a first priority security interest in our assets.  The Loan Agreements grant Aequitas the right to convert up to one hundred percent (100%) of unpaid principal and interest into shares of our common stock at an exercise price of $0.0906.

 
8


ITEM 1A.  RISK FACTORS

CERTAIN FACTORS THAT MAY AFFECT FUTURE RESULTS

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.
 
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 Loan Agreements as of January 2, 2010, 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 Loan Agreements or negotiate future waivers or amendments of such covenants, an event of default could occur under the Loan Agreements.  Upon the occurrence and during the continuance of an event of default under the Loan Agreements, Aequitas 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 Loan Agreements 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 loan, there can be no assurance that Aequitas will continue to fund based upon our requests.  If Aequitas fails to fund a request while we are in compliance with the covenants, the only remedy available to us will be a five (5%) reduction in the rate of interest during the period that Aequitas is in default.

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 March 18, 2010, our independent auditors stated that our financial statements for the year ended January 2, 2010 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 operating 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 operating losses and our auditors’ doubts 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 $3.2 million and $34.1 million for the fiscal years ended January 2, 2010, and January 3, 2009, respectively.  At January 2, 2010, 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:

 
9


 
grow our internal and third-party sales and marketing forces to expand the sales of our products;
 
increase our research and development efforts to improve upon our existing products and develop new products; and
 
acquire and/or license new technologies.
 
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.

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, it could make us 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.

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.  While there is currently an application with FERC to re-instate the incentive, there can be no assurance that the PJM incentive will be reinstated.  Furthermore, even if the incentive is approved, there can be no assurance that it will restore previous participation level in the economic program within PJM.

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

Under our current loan facility our lender, Aequitas has a perfected first position security interest in our assets.  This, along with other restrictions in the Loan Agreements, significantly limits our ability to obtain additional credit while the loan 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 the last five 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:

 
our ability to retain our current customers;
 
our ability to sign new customers;
 
the wholesale price of electricity in economic markets; and
 
the ability to configure our software for other markets

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.

 
10


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:

 
fluctuations in demand for our services;
 
length of sales cycles;
 
weather abnormalities;
 
unexpected price changes;
 
changes in the rules by the electric grid operators regarding payments for our transactional energy services;
 
adverse weather conditions, particularly during the winter season, could affect our ability to render services in certain regions of the United States;
 
reductions in the margins of products and services offered by our competitors;
 
costs of integrating technologies or businesses that we add; and
 
delays in payment resulting from administrative delays from utilities in processing settlements.

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.

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.

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. For example FERC is due to rule in a PJM application to re-instate an incentive for price demand response programs. The failure of FERC to rule in favor of such a program could have a material adverse effect on our ability to grow revenues or add more customers. If FERC rules against PJM, this may discourage other markets to develop price response programs that could limit our ability to sell our solutions into new emerging markets.

 
11


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.

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 customers, 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 customer base.

The majority of our customers are under annual contracts, which means we have to re-sign them each year for the capacity and economic programs.  Although we are moving to longer term contracts, there can be no assurance that we will be successful in signing or re-signing customers to longer term contracts.  The failure to sign customers to longer term contracts 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 noncompliance with regulations.  Furthermore, in addition to the risk of significant penalties, our ability to retain our existing customers or sign new customers could be materially adversely affected if we were found to be in noncompliance with regulations.

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

We estimate that we have invested over 100,000 man hours into developing our EventConnect and FlexConnect solutions.  Not only do we have to ensure that our software continues to offer our customers 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.

 
12


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.

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.

In order for us to participate in some markets, we may be required to post letters of credit or security deposits. 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.

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
 
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.
 
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 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:

 
difficulties in staffing, managing and integrating international operations due to language, cultural or other differences;
 
different or conflicting regulatory or legal requirements;
 
foreign currency fluctuations; and
 
diversion of significant time and attention of our management.
 
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.

 
13


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 customer 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.  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.

 
14


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.
 
Intellectual property litigation could harm our business.
 
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 have seen 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 has been significantly reduced in 2009.  We have therefore relied upon the capacity markets to make up nearly all of our revenues in 2009.  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 customers, thereby limiting participation in the economic programs, but can also result in longer sales cycles to sign new customers to our contracts.

 
15


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 customers and 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 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 issue in this offering 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 taxable income may become subject to limitations, which could result in increased future tax liability for us.
 
Shares eligible for future sale may cause the market price for our common stock to decline even if our business is doing well.

Under the Loan Agreements, Aequitas has the right to convert up to 2/3rds of unpaid principal and interest under the loans into shares of our common stock at an exercise price of $0.0906 for amounts outstanding at December 23, 2009, and convert 100% of those monies drawn down against the line thereafter. After February 25, 2010, 100% the principal and interest can be subject to conversion.  As of January 2, 2010, we had outstanding borrowings of $ 2.050 million under the Loan Agreements, which is convertible into approximately 15.085 million shares of our common stock at 2/3rds conversion, or approximately 16% of our issued and outstanding capital or 22.627 million shares of our common stock at 100% conversion, or approximately 24% of our issued and outstanding capital.

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:

 
delaying, deferring or preventing a change in corporate control;
 
impeding a merger, consolidation, takeover or other business combination involving us; and
 
discouraging a potential acquirer from making a tender offer or otherwise attempting to obtain control of us.

 
16


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:

 
that a broker or dealer approve a person’s account for transactions in penny stocks; and
 
the broker or dealer receive from the investor a written agreement to the transaction, setting forth the identity and quantity of the penny stock to be purchased.
 
In order to approve a person’s account for transactions in penny stocks, the broker or dealer must:
 
 
obtain financial information and investment experience objectives of the person; and
 
make a reasonable determination that the transactions in penny stocks are suitable for that person and the person has sufficient knowledge and experience in financial matters to be capable of evaluating the risks of transactions in penny stocks.
 
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:
 
 
sets forth the basis on which the broker or dealer made the suitability determination; and
 
that the broker or dealer received a signed, written agreement from the investor prior to the transaction.
 
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.


ITEM 2.  PROPERTIES

We lease facilities in Campbell, California, Lake Oswego, Oregon, and Conshohoken, Pennsylvania.  These facilities consist of approximately 17,500 square feet of office space.  We do not own or lease any manufacturing space.  We believe our existing facilities are adequate to meet our current needs.


ITEM 3.  LEGAL PROCEEDINGS

During 2008, we were contacted by FERC and asked to provide information to them as part of a non-public inquiry on the demand response markets, and our activity in our markets under FERC tariffs.  Over a period of 8 months, we provided them with the requested documentation both in paper and electronic form, and voluntarily provided them with access to certain of our employees in an effort to answer all questions put forth to us.  On April 28, 2009, staff from FERC’s Office of Enforcement informed EnergyConnect that FERC had found our technology and business processes to be in compliance with the tariff and had closed its inquiry, without any proposed enforcement actions or remedies.

From time to time, we may become involved in various lawsuits and legal proceedings which arise in the ordinary course of business. However, 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. We are currently not aware of any such legal proceedings or claims other than those mentioned in this Item that we believe will have, individually or in the aggregate, a material adverse affect on our business, financial condition or operating results.

 
17


PART II

ITEM 4.  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 following table sets forth the high and low sales prices as reported by the Over the Counter Bulletin Board for the periods indicated.

Fiscal 2008
 
 
High
 
 
 
Low
 
First Quarter
 
$
0.96
 
 
$
0.43
 
Second Quarter
 
 
0.56
 
 
 
0.33
 
Third Quarter
 
 
0.63
 
 
 
0.34
 
Fourth Quarter
 
 
0.40
 
 
 
0.08
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fiscal 2009
 
 
High
 
 
 
Low
 
First Quarter
 
$
0.21
 
 
$
0.05
 
Second Quarter
 
 
0.14
 
 
 
0.09
 
Third Quarter
 
 
0.09
 
 
 
0.06
 
Fourth Quarter
 
 
0.12
 
 
 
0.05
 
 
As of March 9, 2010 we had 189 record holders of our common stock. The number of record holders was determined from the records of our transfer agent and does not include beneficial owners of common stock whose shares are held in the names of various security brokers, dealers, and registered clearing agencies.  The Company has not declared or paid any cash dividends on the Common Stock in recent years and does not currently intend to do so. The Company intends to retain any future earnings for reinvestment in its business or to use such earnings to repay debt.

Securities Authorized for Issuance Under Equity Compensation Plans

The following equity compensation information, as of January 2, 2010, is presented in compliance with SEC regulation S-K Item 201(d).

Plan category
 
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))
 
 
(a)
   
(b)
   
(c)
 
Equity compensation plans approved by security holders
 
 
14,509,530
 
 
$
0.29
 
 
 
1,746,632
 
Equity compensation plans not approved by security holders
 
 
33,055,055
 
 
$
2.21
 
 
 
N/A
 
Total
 
 
47,564,585
 
 
$
1.63
 
 
 
N/A
 

Unregistered Securities Sold in 2009

None.

Issuer Purchases of Equity Securities

None.

 
18


ITEM 5.  SELECTED FINANCIAL DATA

SELECTED FINANCIAL DATA

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 2, 2010, and January 3, 2009 and the balance sheet data at January 2, 2010, and January 3, 2009 are derived from our audited financial statements which are included elsewhere in this annual report. The statement of operations data for the years ended December 29, 2007, December 30, 2006, and December 31, 2005 and the balance sheet data at December 29, 2007, December 30, 2006, and December 31, 2005, 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.

See Notes 4 and 5 of the Consolidated Financial Statements for further discussions of the Company’s acquisitions.

 
 
Fiscal years ended
 
 
 
 
 
   
 
 
 
 
 
 
   
 
 
 
January 2, 2010
 
 
January 3, 2009
 
 
December 29, 2007
 
 
December 30, 2006
 
 
December 31, 2005
 
Statements of Operations:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenue
 
$
19,921
 
 
$
25,859
 
 
$
12,626
 
 
$
3,202
 
 
$
     1,173
 
Cost of revenue
 
 
12,882
 
 
 
18,420
 
 
 
8,788
 
 
 
3,032
 
 
 
      666
 
Gross profit
 
 
7,038
 
 
 
7,439
 
 
 
3,837
 
 
 
170
 
 
 
      507
 
Operating expense
 
 
9,317
 
 
 
41,486
(2)
 
 
8,180
 
 
 
6,076
 
 
 
78,215
(1)
Income (loss) from continuing operations
 
 
(2,279
)
 
 
(34,066
)
 
 
(4,341
)
 
 
1,561
   
 
(78,721
)
Net income (loss)
 
 
(3,222
)
 
 
(34,077
)
 
 
(14,035
)
 
 
833
   
 
(77,953
)
Net income (loss) per share
 
$
(0.03
)
 
$
(0.37
)
 
$
(0.17
)
 
$
0.01
   
$
(2.91
)
Weighted average shares
 
 
95,481
 
 
 
91,245
 
 
 
82,536
 
 
 
71,374
 
 
 
27,048
 
                                         
Balance Sheet Data:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash, including certificates of deposit
 
$
1,162
 
 
$
710
 
 
$
892
 
 
$
2,545
 
 
$
729
 
Total assets
 
 
9,775
 
 
 
7,357
 
 
 
48,085
 
 
 
57,147
 
 
 
55,241
 
Total liabilities
 
 
9,746
 
 
 
5,361
 
 
 
16,828
 
 
 
13,019
 
 
 
27,337
 
Shareholders’ equity (deficit)
 
$
29
 
 
$
1,996
 
 
$
31,258
 
 
$
43,616
   
$
(27,904
)
 
1
Includes write-off in 2005 of impaired goodwill of $77.2 million resulting from the testing of the carrying value of goodwill purchased in the acquisition of ECI in October 2005.
 
2
Includes write-off in 2008 of impaired goodwill of $29.4 million resulting from the testing of the carrying value of goodwill purchased in the acquisition of ECI in October 2005.

 
19


ITEM 6.  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:

 
discuss future expectations;
 
contain projections of future results of operations or of financial condition; and
 
state other “forward-looking” information.

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 9.”

Critical Accounting Policies

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:

Revenue Recognition
 
We produce revenue 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 revenue in 2009 was processed through the PJM Interconnection. 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 have little risk, if any, from the concentration of revenue through this power grid as it is a not-for-profit organization that exists to act as the market for electrical transactions.

In 2008, we revised our accounting for reserves for collections of our wholesale energy market revenues. The revision in our reserve accounting is a result of improvements in our ability to accurately estimate collections, which is based upon historical trends and timely and accurate information.   Previously the transactions were recorded as revenue on the settlement date, which typically fall 45-70 days after the transaction date from which the revenue is derived, because management believed that without an established history for this source of revenue, and the potential for disputes, that the settlement date, on which both parties agree to the amount of revenue to recognize, was the most conservative and appropriate date to use.  For periods beginning with the first quarter of 2008 and forward, revenue from these settlements were accrued into the prior month instead of recognizing revenue as the settlement amounts were received.  The record of these settlement amounts being realized over the prior two years had been extremely accurate so that management believed it was appropriate to accrue the settlement amounts into the prior month.  This revision in our reserve accounting resulted in an extra month of revenue being recorded in the first quarter of 2008.  This first quarter of 2008 contained the payment received in January of 2008 (which was not accrued into December) and the settlement amounts from the fifth business day in February, March and April of 2008, each of which was accrued into the prior months of January, February and March of 2008.

 
20


An additional source of our revenue results from activities in the capacity program. Under this program we enter into agreements with the power grid operators whereby a monthly reserve fee is paid for our agreement to standby, ready 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’re 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.

Accruals for Contingent Liabilities

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.
 
Purchase Price Allocation and Impairment of Intangible and Long-Lived Assets

Intangible and long-lived assets to be held and used are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts of such assets may not be recoverable. Determination of recoverability is based on an estimate of undiscounted future cash flows resulting from the use of the asset, and its eventual disposition. Measurement of an impairment loss for intangible and long-lived assets that management expects to hold and use is based on the fair value of the asset as estimated using a discounted cash flow model.
 
We measure the carrying value of goodwill recorded in connection with the acquisitions for potential impairment in accordance with Accounting Standard Codification (“ASC”) 350 (formerly, Financial Standards Accounting Board “FASB” No. 142, Goodwill and Other Intangible Assets.) To determine whether or not goodwill may be impaired, a test is required at least annually, and more often when there is a change in circumstances that could result in an impairment of goodwill. If the trading of our common stock is below book value for a sustained period, or if other negative trends occur in our results of operations, a goodwill impairment test will be performed by comparing book value to estimated market value. An impairment loss would be recognized if the fair value of the reporting unit is less than the carrying value of the reporting unit’s net assets on the date of the evaluation.

We tested our intangibles for impairment as of the end of fiscal years 2005 through 2008. Goodwill of $106.5 million was recorded upon the acquisition of ECI in October 2005, and represented the excess of the purchase price over the fair value of the net tangible and intangible assets acquired. At December 31, 2005, it was determined in an independent valuation that the goodwill generated in this transaction was impaired. The Company decided to write off approximately $77.2 million of this goodwill.  At January 3, 2009, it was determined that the remaining carrying value of goodwill generated from the 2005 transaction was impaired. The Company decided to write off the remaining carrying value of goodwill of $29.4 million. The write-off of the goodwill and the amortization of the intangible assets are included in operating expenses in the consolidated statements of operations.  There were no changes in the carrying value of goodwill at December 30, 2006 and December 29, 2007.
 
Stock-Based Compensation

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.

We are using the Black-Scholes option-pricing model as its method of valuation for share-based awards.  Our determination of fair value of share-based payment awards on the date of grant using an option-pricing model is affected by our stock price as well as assumptions regarding a number of highly complex and subjective variables. These variables include, but are not limited to our expected stock price volatility over the term of the awards, and certain other market variables such as the risk free interest rate.

Stock-based compensation expense recognized for the twelve months ended January 2, 2010, and January 3, 2009 was approximately $796,000, and $870,000, respectively.

Computation of Net Income (Loss) per Share

Basic earnings (loss) per common share is computed using the weighted-average number of common shares outstanding during the period.  Diluted earnings per common share is computed using the combination of dilutive common share equivalents, which include convertible preferred shares, options and warrants and the weighted-average number of common shares outstanding during the period.  During the years ended January 2, 2010 and January 3, 2009 common stock equivalents are not considered in the calculation of the weighted average number of common shares outstanding because they would be anti-dilutive, thereby decreasing the net loss per common share.

 
21


Concentrations

Financial instruments that potentially subject us to concentrations of credit risk consist primarily of accounts receivable. During the year ended January 2, 2010, and January 3, 2009, revenue from one market operator, PJM, accounted for approximately $17.6 million and $24.7 million or 88.1% and 95.6% of revenues, respectively.   This revenue is the result of multiple participating electric consumers who each executed myriad energy transactions that were aggregated and billed to the PJM Interconnection, or PJM.  The revenue is dependent on actions taken by these third parties in conjunction with ECI for which PJM as our customer remits payment.  The transactions form the basis for our revenue.  We have little risk, if any, from the concentration of revenue through this power grid as it’s a not-for-profit organization that exists to act as the market for electrical transactions.  Of these participants, there was one whose transactions resulted in revenue that totaled 10% or more of our revenue in the twelve months ended January 2, 2010 and January 3, 2009.

At January 2, 2010 and January 3, 2009, there was one customer whose accounts receivable accounted for more than 10% of total outstanding trade accounts receivable.  We have little risk, if any, from the concentration of receivables through this power grid as it’s a not-for-profit organization that exists to act as the market for electrical transactions.  We perform limited credit evaluations of our customers and do not require collateral on accounts receivable balances.  We have not experienced any credit losses for the periods presented.   The level of revenue resulting from any single participant’s transactions may vary and the loss of any one of these participants, or a decrease in the level of revenue from transactions generated by any one of these participants, could have a material adverse impact on our financial condition and results of operations.

Fair Value Measurement

We adopted the provisions of ASC 820 (formerly, FASB No. 157, Fair Value Measurements and Disclosures) on December 30, 2007, the beginning of our 2008 fiscal year. ASC 820 clarifies the principle that fair value should be based on the assumptions market participants would use when pricing an asset or liability and establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. Under the standard, fair value measurements are separately disclosed by level within the fair value hierarchy. As originally issued, it was effective for fiscal years beginning after November 15, 2007, with early adoption permitted. It does not require any new fair value measurements. It only applies to accounting pronouncements that already require or permit fair value measures, except for standards that relate to share-based payments.

On February 12, 2008, the FASB allowed deferral of the effective date of ASC 820 for one year, as it relates to nonfinancial assets and liabilities. Accordingly, our adoption related only to financial assets and liabilities.

Upon adoption ASC 820, there was no cumulative effect adjustment to beginning retained earnings and no impact on the consolidated financial statements.

Valuation techniques considered under ASC 820 techniques are based on observable and unobservable inputs. The Standard classifies these inputs into the following hierarchy:

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 includes 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, credits 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.

In October 2008, the FASB clarified the application of ASC 820 in determining the fair value of a financial asset when the market for that financial asset is not active.

We adopted the provisions of ASC 825 (formerly, SFAS No. 159, The Fair Value Option for Financial Assets and Liabilities – Including an Amendment of FASB Statement No. 115) on December 30, 2007, the beginning of our 2008 fiscal year. ASC 825 permits us to choose to measure certain financial assets and liabilities at fair value that are not currently required to be measured at fair value (the “Fair Value Option”). Election of the Fair Value Option is made on an instrument-by-instrument basis and is irrevocable. At the adoption date, unrealized gains and losses on financial assets and liabilities for which the Fair Value Option has been elected are reported as a cumulative adjustment to beginning retained earnings. We did not elect the Fair Value Option as we had no financial assets or liabilities that qualified for this treatment. In the future, if we elect the Fair Value Option for certain financial assets and liabilities, we would report unrealized gains and losses due to changes in their fair value in net income at each subsequent reporting date. The adoption of this statement had no impact on our consolidated financial statements.

 
22


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.

Results of Operations

The following table sets forth, as a percentage of sales, certain consolidated statement of operations data relating to the business for the periods indicated.

 
 
Fiscal 2009
 
 
Fiscal 2008
*
 
 
 
 
 
 
 
Net revenue
 
 
100
%
 
 
100
%
Cost of revenue
 
 
65
 
 
 
71
 
Gross profit
 
 
35
 
 
 
29
 
Operating expenses
 
 
46
 
 
 
47
 
Loss from operations
 
 
(11
)
 
 
(18
)
Other income (expense)
 
 
(5)
 
 
 
-
 
Loss before income taxes
 
 
(16
)
 
 
(18
)
Provision for income taxes
 
 
-
 
 
 
-
 
Loss from continuing operations
 
 
(16
)
 
 
(18
)
Net loss
 
 
(16
)%
 
 
(18
)%

* This table does not include the percentage of sales due to the impairment of goodwill of approximately $29.4 million.  Presentation of this non-cash item would make the comparison of this year to the other years presented, meaningless.

Revenue.  Revenue for the fiscal year ended January 2, 2010 was $ 19.9 million compared to $25.9 million for the fiscal year ended January 3, 2009.  The decrease in revenue between periods is due to significantly lower wholesale energy market transaction activities within our participant base as a result of historically low wholesale electricity prices within PJM, offset in part by increased capacity transactions. Wholesale energy market and ancillary services revenues fell from approximately $17.2 million in fiscal 2008 to approximately $1.5 million in fiscal 2009.  We also recorded approximately $18.4 million in fiscal 2009 revenue in capacity programs, compared to approximately $8.0 million from capacity programs in 2008.  The revenue in the twelve months ended January 3, 2009 consists of thirteen months of revenue due to the change in our policy for recognizing revenue.  The revenue for the twelve monthly periods ended January 3, 2009, recognized on the same basis as the revenue for the twelve-months ended January 2, 2010, and totaled $24.2 million. There was one participant whose transactions contributed to revenue from PJM that comprised over 10% of our 2009 consolidated revenue. The Company’s revenue is subject to seasonal influences that affect the wholesale prices on which the majority of our revenue is derived.  The Company’s revenue is also subject to changes in tariff rules implemented by PJM that could adversely affect the Company’s results from operations.

Cost of revenue.  Cost of revenue totaled $12.9 million (65%) for the fiscal year ended January 2, 2010 compared to $18.4 million (71%) for the fiscal year ended January 3, 2009.  Cost of revenue includes the portion of energy transaction revenue that is paid to participating energy consumers that initiate revenue generating transactions.  Also included in costs of revenues is the amortization of a developed technology intangible asset that amounted to 1% for the fiscal years ended January 2, 2010, and January 3, 2009, respectively.

Gross profit.  Gross profit for the fiscal year ended January 2, 2010, was $7 million (35%) compared to $7.4 million (29%) for the fiscal year ended January 3, 2009.  This increase in gross profit is due primarily to the higher levels of revenue generated from capacity transactions.  Future gross profits and gross margins will depend on the volume and mix of sales of products and services to our customers.

Operating expenses.  Operating expenses are comprised mainly of payroll costs, outside services, stock-based compensation and product development.  These expenses for the fiscal year ended January 2, 2010 were $9.3 million compared to $12.1 million (excluding approximately $29.4 million of goodwill impairment charges) for the fiscal year ended January 3, 2009.  The decrease in operating expenses is due to lower payroll costs and costs associated with consultants as a result of a number of cost cutting activities during the year.

 
23


Write-off of impaired goodwill and intangibles.   We test our goodwill for potential impairment at the end of each fiscal year.  There was no charge for impairment of goodwill in the fiscal year ended January 2, 2010. The appraisal that was conducted in fiscal 2008 concluded that there was an impairment of $29 million to the carrying value of goodwill as of January 3, 2009.

Other income (expense).  Other interest income was $1,000 for the year ended January 2, 2010 compared to $50,000 for the year ended January 3, 2009.  Other interest expense was $944,000 for the year ended January 2, 2010 compared to $69,000 for the year ended January 3, 2009.  The increase in other income (expense) was due to interest payable on our loan facility with Aequitas  that we entered into on February 26, 2009 and amended on December 23, 2009. Under the terms of the agreement, outstanding balances on the line attract an interest rate of thirty percent (30%) of which twenty-three percent (23%) is paid in cash on a monthly basis and seven percent (7%) as accrued and is added to the unpaid principal balance of the loan on the first anniversary of the of the effective date of the agreement.
 
Gain/loss from discontinued operations.  Discontinued operations for all years presented contain the operations of Christenson Electric.  Christenson Electric was sold to a corporation formed by the management of CEI on November 29, 2007.  The shareholders of the Company voted to approve the transaction at a shareholders’ meeting on March 10, 2008, and it closed on April 24, 2008.  The results of discontinued operations for the year ended January 3, 2009 included a gain on the sale of discontinued operations of $135,000, and a loss from discontinued operations of $146,000 for the four months while CEI was part of the consolidated group.

Non-cash Expense Items

We have entered into several acquisitions, financings, debt conversions and other transactions where goodwill and amortizable intangible assets were recorded, and/or common stock or warrants were issued as a part of the transactions.  Many of the issuances resulted in non-cash charges to our statement of operations.  Additionally, other transactions and events occurred in which significant non-cash expense or income arose due to the nature of those occurrences.  The following table lists these items and the effect net income or loss in our statements of operations for the fiscal years ended January 2, 2010, and January 3, 2009.

 
 
Year ended
 
 
Year ended
 
Non-cash expense item description*
 
January 2, 2010
 
 
January 3, 2009
 
 
 
 
 
 
 
 
Common stock issued for services
 
$
-
 
 
$
243,883
 
Stock-based compensation issued for services
 
 
-
 
 
 
28,645
 
Stock-based compensation issued to directors and employees
 
 
796,225
 
 
 
841,338
 
Intangible amortization
 
 
239,067
 
 
 
239,067
 
Amortization of debt discount
 
 
315,318
 
 
 
-
 
Write down of goodwill
 
 
-
 
 
 
29,353,527
 
 
 
 
 
 
 
 
 
 
Total transactional non-cash expense
 
$
1,350,610
 
 
$
30,706,460
 

*This table does not include depreciation expense.

Liquidity and Capital Resources

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.

Accounts receivable increased to $6.8 million at January 2, 2010 from $4.4 million at January 3, 2009.  The increase is due to the larger amount of revenues from the PJM capacity program.  Management expects these receivables to increase in future periods as revenue from this program increases.
 
Property and equipment, net of depreciation, decreased to $187,000 at January 2, 2010 compared to $299,000 at January 3, 2009.  This decrease was due to minimal expenditures on fixed assets during the year offset by depreciation charges relating to prior years fixed asset purchases.
 
 
24

 
Accounts payable increased to $7.5 million at January 2, 2010 from $5.2 million at January 3, 2009. Payables consist primarily of payments we make to our customers and third-party vendors. This increase is the result of higher levels of revenue generated in the PJM capacity program in 2009.

During fiscal 2009 we entered into loan agreements with Aequitas.  The amount outstanding under the loan agreements was approximately $2.1 million at January 2, 2010. We are in compliance with all related covenants.

On May 7, 2008, we issued 9,051,310 shares of our common stock and 4,525,655 warrants to purchase shares of our common stock, in exchange for $3.5 million in gross proceeds and elimination of $103,000 of payables.

In 2009 and 2008, we incurred operating losses of $2.3 million and $34.0 million, respectively.  The operating loss in fiscal 2008 included a $29.4 million non-cash loss due to the impairment of the carrying value of goodwill.

On February 26, 2009, the Company entered into a $5 million loan agreement with Aequitas.  On December 23, 2009, we amended the agreement. The agreement provides us with a revolving credit facility that enables 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 is 23% with an additional 7% deferred interest per annum.  For the balance of the term and for amounts borrowed under the amendment the interest rate is 22% with an additional 3% deferred interest per annum. The accrued, deferred interest at 7% shall be added to the current principal balance of the loan at the end of the first twelve- month term.  The accrued deferred interest at 3% shall be added to the current principal balance of the loan at the end of each month during the term of the facility. The loan matures on February 24, 2012.  We granted the lender a first priority security interest in all of our assets.  The lender also has 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.  While the Company believes that the availability of funds from this debt facility, with cash generated from operations, will be sufficient to meet the Company’s operating capital needs through 2012, conditions may change in the markets in which the Company operates that may cause the borrowing capacity under this debt facility to become limited.  There can be no assurance that the Company will be able to meet the covenants required under the amendment. There can be no assurance that funds will be available under the loan agreements even if we are in compliance with all of the covenants.

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.
 
Our registered independent certified public accountants have stated in their report dated March 18, 2010 that we have incurred operating losses in the last two years, and that we are dependent upon management’s ability to develop profitable operations.  These factors among others may raise substantial doubt about our ability to continue as a going concern.

We have no commitments for capital expenditures in material amounts at January 2, 2010.

Inflation

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

Off-Balance Sheet Arrangements

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

Related Party Transactions

As a part of the discontinued operations, we have previously had a number of promissory notes, lines of credit and lease obligations owed to related parties.  As of January 2, 2010, as a part of continuing operations, there are no amounts owed to related parties other than nominal amounts incurred in the normal course of business

 
25


Contractual Obligations and Commitments

The following is a summary of our significant contractual cash obligations for the periods indicated that existed as of January 2, 2010, and is based on information appearing in the notes to consolidated financial statements included elsewhere in this filing.

 
 
Total
 
 
Less than 1 Year
 
 
1-2 Years
 
 
3-5 Years
 
 
More than 5 Years
 
Operating Leases
 
$
826,254
 
 
$
385,109
 
 
$
441,145
 
 
$
-
 
 
$
-
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total obligations
 
$
826,254
 
 
$
385,109
 
 
$
441,145
 
 
$
-
 
 
$
-
 

Recent Accounting Pronouncements

See Note 2 of the Consolidated Financial Statements for a full description of new accounting pronouncements, including the respective expected dates of adoption and effects on results of operations and financial condition.


Item 6A.  Quantitative and Qualitative Disclosures About Market Risk

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

 
26


ITEM 7.  FINANCIAL STATEMENTS


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


Board of Directors
EnergyConnect Group, Inc.
Campbell, California


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 January 3, 2009 and the related consolidated statements of operations, stockholders' equity, and cash flows for each of the two years in the period 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 audits.

We conducted our audits 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.  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 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 audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of EnergyConnect Group, Inc. and its wholly-owned subsidiary as of January 2, 2010 and January 3, 2009 and the consolidated results of its operations and its cash flows for each of the two years in the period 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 16, 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 15.  The accompanying statements do not include any adjustments that might result from the outcome of this uncertainty.


/s/RBSM LLP


New York, New York,
March 18, 2010

 
27


ENERGYCONNECT GROUP, INC.
CONSOLIDATED BALANCE SHEETS
AS OF JANUARY 2, 2010 AND JANUARY 3, 2009

 
 
January 2, 2010
   
January 3, 2009
 
Current assets:
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
1,062,306
 
 
$
410,101
 
Certificates of deposit
 
 
100,200
 
 
 
300,000
 
Accounts receivable, net of allowance of $0 as of January 2, 2010 and January 3, 2009
 
 
6,811,495
 
 
 
4,373,818
 
Other current assets
 
 
137,042
 
 
 
269,144
 
Total current assets
 
 
8,111,043
 
 
 
5,353,063
 
 
 
 
 
 
 
 
 
 
Property and equipment, net (Note 3)
 
 
187,085
 
 
 
299,263
 
Other assets
 
 
78,035
 
 
 
70,876
 
Intangible assets, net (Note 5)
 
 
1,398,761
 
 
 
1,633,622
 
Total Assets
 
$
9,774,924
 
 
$
7,356,824
 
 
 
 
 
 
 
 
 
 
Current liabilities:
 
 
 
 
 
 
 
 
Accounts payable and accrued expenses
 
$
7,508,561
 
 
$
5,116,296
 
Bank line of credit (Note 9)
 
 
-
 
 
 
117,257
 
Other current liabilities
 
 
324,886
 
 
 
127,016
 
Total current liabilities
 
 
7,833,447
 
 
 
5,360,569
 
                 
Long-term liabilities:
               
Note payable, net of discount of $137,063 (Note 9)
   
1,912,937
     
-
 
 
 
 
 
 
 
 
 
 
Commitments and contingencies (Note 13)
 
 
 
 
 
 
 
 
Shareholders’ equity:
 
 
 
 
 
 
 
 
Common stock, no par value, 225,000,000 shares authorized, 95,629,961 and 95,179,961 shares issued and outstanding, respectively
 
 
121,926,000
 
 
 
120,671,694
 
Common stock warrants (Note 8)
 
 
36,098,289
 
 
 
36,098,289
 
Accumulated deficit
 
 
(157,995,749
)
 
 
(154,773,728
)
Total shareholders’ equity
 
 
28,540
 
 
 
1,996,255
 
Total Liabilities and Shareholders’ Equity
 
$
9,774,924
 
 
$
7,356,824
 
 
 
The accompanying notes are an integral part of these consolidated financial statements

 
28


ENERGYCONNECT GROUP, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED JANUARY 2, 2010 AND JANUARY 3, 2009
 
 
 
January 2, 2010
 
 
January 3, 2009
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenue
 
$
19,920,525
 
 
$
25,858,704
 
 
 
 
 
 
 
 
 
 
Cost of revenue
 
 
12,882,257
 
 
 
18,419,335
 
 
 
 
 
 
 
 
 
 
Gross profit
 
 
7,038,268
 
 
 
7,439,369
 
 
 
 
 
 
 
 
 
 
Operating expenses
 
 
 
 
 
 
 
 
Sales, general and administrative
 
 
9,317,077
 
 
 
12,132,761
 
Goodwill impairment (Note 5)
 
 
-
 
 
 
29,353,527
 
 
 
 
 
 
 
 
 
 
Total operating expenses
 
 
9,317,077
 
 
 
41,486,288
 
 
 
 
 
 
 
 
 
 
Loss from operations
 
 
(2,278,809
)
 
 
(34,046,919
)
 
 
 
 
 
 
 
 
 
Other income (expense)
 
 
 
 
 
 
 
 
Interest income
 
 
513
 
 
 
49,736
 
Interest expense
 
 
(943,725
)
 
 
(68,586
)
 
 
 
 
 
 
 
 
 
Total other income (expense)
 
 
(943,212
 
 
(18,850
)
 
 
 
 
 
 
 
 
 
Loss before provision for income taxes
 
 
(3,222,021
)
 
 
(34,065,769
)
 
 
 
 
 
 
 
 
 
Provision for income taxes (Note 11)
 
 
-
 
 
 
-
 
 
 
 
 
 
 
 
 
 
Loss from continuing operations
 
 
(3,222,021
)
 
 
(34,065,769
)
 
 
 
 
 
 
 
 
 
Discontinued operations:
 
 
 
 
 
 
 
 
Loss on discontinued operations - Christenson Electric (Note 4)
 
 
-
 
 
 
(11,281
)
 
 
 
 
 
 
 
 
 
Net loss
 
$
(3,222,021
)
 
$
(34,077,050
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Basic and diluted net loss per share from continuing operations (Note 12)
 
$
(0.03
)
 
$
(0.37
)
 
 
 
 
 
 
 
 
 
Basic and diluted net loss per share from discontinued operations (Note 12)
 
$
(0.00
)
 
$
(0.00
)
 
 
 
 
 
 
 
 
 
Basic and diluted net loss per share (Note 12)
 
$
(0.03
)
 
$
(0.37
)
 
 
 
 
 
 
 
 
 
Weighted average shares used in per share calculations:
 
 
 
 
 
 
 
 
Basic
 
 
95,480,783
 
 
 
91,245,072
 
 
 
 
 
 
 
 
 
 
Diluted
 
 
95,480,783
 
 
 
91,245,072
 


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

 
29


ENERGYCONNECT GROUP, INC.
CONSOLIDATED STATEMENT OF STOCKHOLDERS EQUITY
FOR THE YEARS ENDED JANUARY 2, 2010 AND JANUARY 3, 2009
 
 
 
Common Stock
 
 
Common Stock Warrants
 
 
Accumulated Deficit
 
 
Total Shareholders’ Equity (Deficit)
 
 
 
Shares
 
 
Amount
 
 
Warrants
 
 
Amount
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance December 19, 2007
 
 
83,569,417
 
 
$
115,776,415
 
 
 
28,549,182
 
 
$
36,178,218
 
 
$
(120,696,679
)
 
$
31,257,954
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common shares issued to outside consultants
 
 
455,438
 
 
 
243,883
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
243,883
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Stock options issued to employees and directors
 
 
 
 
 
 
869,983
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
869,983
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common shares issued  upon conversion of preferred shares
 
 
2,069,329
 
 
 
703,729
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
703,729
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common shares issued upon  exercise of options
 
 
34,467
 
 
 
31,694
 
 
 
(34,467
)
 
 
(17,218
)
 
 
 
 
 
 
14,476
 
                                                 
Common shares and warrants  issued in private placement
 
 
9,051,310
 
 
 
3,256,434
 
 
 
4,665,874
 
 
 
 
 
 
 
 
 
 
 
3,256,434
 
                                                 
Note receivable in exchange for exercise of stock options
 
 
 
 
 
 
(264,384
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(264,384
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expiration and forfeiture of warrants
 
 
 
 
 
 
62,711
 
 
 
(125,534
)
 
 
(62,711
)
 
 
 
 
 
 
-
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Reclassification of  amounts upon sale of Christenson Electric, Inc.
 
 
 
 
 
 
(8,771
)
 
 
 
 
 
 
 
 
 
 
1
 
 
 
(8,770
)
                                                 
Net loss
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(34,077,050
)
 
 
(34,077,050
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance January 3, 2009
 
 
95,179,961
 
 
$
120,671,694
 
 
 
33,055,055
 
 
$
36,098,289
 
 
$
(154,773,728
)
 
$
1,996,255
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common shares issued to directors
 
 
450,000
 
 
 
54,000
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
54,000
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Stock options issued to employees and directors
 
 
 
 
 
 
742,225
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
742,225
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Collection of notes receivable for exercise of stock options
           
5,700
                             
5,700
 
                                                 
Beneficial conversion feature of convertible debt
           
452,381
                             
452,381
 
                                                 
Net loss
                                   
(3,222,021
   
(3,222,021
                                                 
Balance January 2, 2010
   
95,629,961
   
$
121,926,000
     
33,055,055
   
$
36,098,289
    $
(157,995,749
 
$
28,540
 

 
30


ENERGYCONNECT GROUP, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED JANUARY 2, 2010, AND JANUARY 3, 2009

   
January 2, 2010
   
January 3, 2009
 
Cash Flows From Operating Activities:
           
Net loss
  $ (3,222,021 )   $ (34,077,050 )
Add  (deduct):
               
Loss on discontinued operations
    -       11,282  
                 
Loss from continuing operations
    (3,222,021 )     (34,065,768 )
Depreciation of equipment
    140,447       126,028  
Amortization of intangible assets
    239,067       239,067  
Option vesting valuation
    742,225       869,983  
Loss on disposal of fixed assets
    -       3,200  
Amortization of debt discount
    315,318          
Common stock issued for services
    54,000       243,883  
Impairment of intangibles
    -       29,353,527  
                 
Changes in current assets and liabilities:
               
Certificates of deposit
    199,800       (166,600 )
Accounts receivable
    (2,437,677 )     (2,840,975 )
Other current assets
    132,102       (359,248 )
Other assets
    (7,159 )     (27,701 )
Accounts payable
    2,392,265       2,140,448  
Other current liabilities
    197,871       4,364  
                 
Net cash used by continuing operations
    (1,253,762 )     (4,479,792 )
                 
Net cash provided by discontinued operations
    -       379,319  
                 
Net cash used by operating activities
    (1,253,762 )     (4,100,473 )
                 
Cash flows from investing activities:
               
Purchases of fixed assets
    (28,270 )     (226,004 )
Increase in intangible assets
    (4,206 )     -  
             
Net cash used by continuing investing activities
    (32,476 )     (226,004 )
                 
Net cash used by discontinued investing activities
    -       (534,325 )
                 
Net cash used by investing activities
    (32,476 )     (760,329 )
                 
Cash flows from financing activities:
               
Repayments on line of credit
    (117,257 )     (1,198 )
Proceeds from debt financing, net of repayements
    2,050,000          
Collection of notes receivable for exercise of stock options
    5,700       718,205  
Proceeds from private placement, net of direct costs
    -       3,256,434  
                 
Net cash provided by continuing financing activities
    1,938,443       3,973,441  
                 
Net cash provided by discontinued financing activities
    -       539,163  
                 
Net cash provided by financing activities
    1,938,443       4,512,604  
                 
Net increase (decrease) in cash and cash equivalents
    652,205       (348,198 )
                 
Cash and cash equivalents, beginning of period
    410,101       758,299  
Cash and cash equivalents, end of period
  $ 1,062,306     $ 410,101  
                 
                 
Supplemental information on interest and taxes:
               
Interest paid during the year
  $ 427,919     $ 11,538  
Income taxes paid during the year
  $ -     $ -  


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

 
31


ENERGYCONNECT GROUP, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.  Description of the Business

EnergyConnect Group, Inc. is a leading provider of demand response services to the electricity grid.

The consolidated financial statements include the accounts of EnergyConnect and its wholly owned operating subsidiary, EnergyConnect, Inc. (collectively the "Company"). The sale of CEI closed on April 24, 2008 (Note 4).  Therefore, the operations of CEI are presented as discontinued operations in the consolidated financial statements.  All significant inter-company accounts and transactions have been eliminated in consolidation.

The Company was incorporated in October 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.


2.  Summary of Significant Accounting Policies

Fiscal Year

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 2, 2010.  The Company’s last fiscal year was the 53 week period ended January 3, 2009.

Principles of Consolidation

The Consolidated Statements of Operations presented above, contain revenue and expense data of EnergyConnect Group, Inc. for the years ended January 2, 2010, and January, 3 2009.  On October 13, 2005, the Company acquired its wholly-owned subsidiary, EnergyConnect, Inc.  The revenue and expense data of ECI is included in the Consolidated Statement of Operations from the acquisition date to the end of the period presented.  The sale of Christenson Electric, Inc. closed on April 24, 2008 (Note 4).  Therefore, the operations of CEI are presented as discontinued operations.  All significant inter-company accounts and transactions between the Company and its subsidiaries have been eliminated in consolidation.

Cash and Cash Equivalents

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 Costs

Advertising and marketing costs of $0.01 million and $0.5 million were expensed as incurred in each of the years ended January 2, 2010, and January 3, 2009, respectively.

Property and Equipment

Property and equipment are stated at cost less accumulated depreciation and amortization.  Depreciation of computer equipment and software is computed using straight line or accelerated declining balance method over the estimated useful lives of the assets.  Estimated lives of three to five years are used for computer equipment and software.  The Company moved to new office spaces during 2009, and recorded leasehold improvements as a part of the build out of these spaces.  These leasehold improvements are being amortized over the life of the office leases.

 
32


Concentrations

Financial instruments that potentially subject us to concentrations of credit risk consist primarily of accounts receivable.  During the year ended January 2, 2010, and January 3, 2009, revenue from one market operator, PJM, accounted for approximately $17.6 million and $24.7 million or 88.1% and 95.6% of revenues, respectively.   This revenue is the result of multiple participating electric consumers who each executed myriad energy transactions that were aggregated and billed to the PJM Interconnection, or PJM.  The revenue is dependent on actions taken by these third parties in conjunction with ECI for which PJM remits payment.  The transactions form the basis for our revenue. Of these participants, there were none whose transactions resulted in revenues of 10% or more of our revenue in the twelve months ended January 2, 2010, there was one participant whose revenues resulted in 13% of our revenues for the twelve months ended January 3, 2009.
 
At January 2, 2010 and January 3, 2009, there was one customer whose accounts receivable accounted for 98.0% and 96.0% respectively.  We perform limited credit evaluations of our customers and do not require collateral on accounts receivable balances. We have not experienced any credit losses for the period presented.
 
Revenue Recognition
 
We produce revenue 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 revenue in 2008 and 2009 was processed through the PJM Interconnection. 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 have little risk, if any, from the concentration of revenue through this power grid as it is a not-for-profit organization that exists to act as the market for electrical transactions.

In 2008, we revised our accounting for reserves for collections of revenues. The revision in our reserve accounting is a result of improvements in our ability to accurately estimate collections, which is based upon historical trends and timely and accurate information.   Previously the transactions were recorded as revenue on the settlement date, which typically fall 45-70 days after the transaction date from which the revenue is derived, because management believed that without an established history for this source of revenue, and the potential for disputes, that the settlement date, on which both parties agree to the amount of revenue to recognize, was the most conservative and appropriate date to use.  For periods beginning with the first quarter of 2008 and forward, revenue from these settlements were accrued into the prior month instead of recognizing revenue as the settlement amounts were received.  The record of these settlement amounts being realized over the prior two years had been extremely accurate so that management believed it was appropriate to accrue the settlement amounts into the prior month.  This revision in our reserve accounting resulted in an extra month of revenue being recorded in the first quarter of 2008.  This first quarter of 2008 contained the payment received in January of 2008 (which was not accrued in December) and the settlement amounts from the fifth business day in February, March and April of 2008, each of which was accrued into the prior months of January, February and March of 2008.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 standby, ready 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’re 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.

Purchase Price Allocation and Impairment of Intangible and Long-Lived Assets

Intangible and long-lived assets to be held and used are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts of such assets may not be recoverable. Determination of recoverability is based on an estimate of undiscounted future cash flows resulting from the use of the asset, and its eventual disposition. Measurement of an impairment loss for intangible and long-lived assets that management expects to hold and use is based on the fair value of the asset as estimated using a discounted cash flow model.

 
33


We measure the carrying value of goodwill recorded in connection with the acquisitions for potential impairment in accordance with Accounting Standard Codification (“ASC”) 350 (formerly, Financial Standards Accounting Board “FASB” No. 142, Goodwill and Other Intangible Assets.) To determine whether or not goodwill may be impaired, a test is required at least annually, and more often when there is a change in circumstances that could result in an impairment of goodwill. If the trading of our common stock is below book value for a sustained period, or if other negative trends occur in our results of operations, a goodwill impairment test will be performed by comparing book value to estimated market value. An impairment loss would be recognized if the fair value of the reporting unit is less than the carrying value of the reporting unit’s net assets on the date of the evaluation.

We tested our intangibles for impairment as of the end of fiscal years 2005 through 2008. Goodwill of $106.5 million was recorded upon the acquisition of ECI in October 2005, and represented the excess of the purchase price over the fair value of the net tangible and intangible assets acquired. At December 31, 2005, it was determined in an independent valuation that the goodwill generated in this transaction was impaired. The Company decided to write off approximately $77.2 million of this goodwill.  At January 3, 2009, it was determined that the remaining carrying value of goodwill generated from the 2005 transaction was impaired. The Company decided to write off the remaining carrying value of goodwill of $29.4 million. The write-off of the goodwill and the amortization of the intangible assets are included in operating expenses in the consolidated statements of operations.

Income Taxes

The Company accounts for income taxes using the asset and liability approach in accordance with ASC 740 (formerly, FASB No. 109, Accounting for Income Taxes.)  The asset and liability approach 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.  Due to recurring losses, there has been no provision for income taxes in the periods presented.
 
In June 2006, the FASB issued FASB ASC 740-10-25  prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. ASC 740-10-25 also provides guidance on recognition, classification, treatment of interest and penalties, and disclosure of such positions. Effective January 1, 2007, the Company adopted the provisions of ASC 740-10-25, as required. As a result of implementing ASC 740-10-25, there has been no adjustment to the Company’s financial statements and the adoption of ASC 740-10-25 did not have a material effect on the Company’s consolidated financial statements for the years ended December 31, 2009, and 2008.

Computation of Net Income (Loss) per Share

Basic earnings (loss) per common share is computed using the weighted-average number of common shares outstanding during the period.  During the years ended January 2, 2010, and January 3, 2009, common stock equivalents are not considered in the calculation of the weighted average number of common shares outstanding because they would be anti-dilutive, thereby decreasing the net loss per common share.

 
34


Pension Plan Contributions

The Company made quarterly matching payments to its 401(k) Retirement plan during the first quarter of 2009 and all of 2008.  These payments totaled approximately $27,000 and $194,000, respectively.

The Company, through the discontinued operating subsidiary, CEI, contributed to several Multi-Employer Pension Benefit Plans on behalf of its employees covered by a collective bargaining agreement.  During the years ended January 2, 2010 and January 3, 2009, the Company contributed $0 and approximately $1.3 million to these plans, respectively, which was expensed as incurred.

Stock Based Compensation

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.

We are using the Black-Scholes option-pricing model as its method of valuation for share-based awards.  Our determination of fair value of share-based payment awards on the date of grant using an option-pricing model is affected by our stock price as well as assumptions regarding a number of highly complex and subjective variables. These variables include, but are not limited to our expected stock price volatility over the term of the awards, and certain other market variables such as the risk free interest rate.

Stock-based compensation expense recognized for the twelve months ended January 2, 2010, and January 3, 2009, was approximately $ 0.8 million and $0.9 million, respectively.

Comprehensive Income

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.

Use of Estimates

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 goodwill and 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.

Research and Development

The Company accounts for research and development costs in accordance with ASC 730 (formerly FASB No. 2, Accounting for Research and Development Costs.)  Under ASC 730, all research and development costs must be charged to expense as incurred. Accordingly, internal research and development costs are expensed as incurred.  Third-party research and developments costs are expensed when the contracted work has been performed or as milestone results have been achieved.  Research and development costs related to both present and future products are expensed in the period incurred.  The Company incurred approximately $0.8 million and $1.7 million of expenditures on research and development for the years ended January 2, 2010, and January 3, 2009, respectively.

Segment Information

ASC 280 (formerly FASB No. 131, Disclosures about Segments of an Enterprise and Related Information) establishes standards for reporting information regarding operating segments in annual financial statements and requires selected information for those segments to be presented in interim financial reports issued to stockholders. It also establishes standards for related disclosures about products and services and geographic areas. Operating segments are identified as components of an enterprise about which separate discrete financial information is available for evaluation by the chief operating decision maker, or decision-making group, in making decisions how to allocate resources and assess performance. The information disclosed herein materially represents all of the financial information related to the Company's one principal operating segment.

 
35


Reclassification

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

Fair Value Measurement

We adopted the provisions of ASC 820 (formerly, FASB No. 157, Fair Value Measurements and Disclosures) on December 30, 2007, the beginning of our 2008 fiscal year. ASC 820 clarifies the principle that fair value should be based on the assumptions market participants would use when pricing an asset or liability and establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. Under the standard, fair value measurements are separately disclosed by level within the fair value hierarchy. As originally issued, it was effective for fiscal years beginning after November 15, 2007, with early adoption permitted. It does not require any new fair value measurements. It only applies to accounting pronouncements that already require or permit fair value measures, except for standards that relate to share-based payments.

On February 12, 2008, the FASB allowed deferral of the effective date of ASC 820 for one year, as it relates to nonfinancial assets and liabilities. Accordingly, our adoption related only to financial assets and liabilities.

Upon adoption ASC 820, there was no cumulative effect adjustment to beginning retained earnings and no impact on the consolidated financial statements.

Valuation techniques considered under ASC 820 techniques are based on observable and unobservable inputs. The Standard classifies these inputs into the following hierarchy:

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 includes 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, credits 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.

In October 2008, the FASB clarified the application of ASC 820 in determining the fair value of a financial asset when the market for that financial asset is not active.

We adopted the provisions of ASC 825 (formerly, SFAS No. 159, The Fair Value Option for Financial Assets and Liabilities – Including an Amendment of FASB Statement No. 115) on December 30, 2007, the beginning of our 2008 fiscal year. ASC 825 permits us to choose to measure certain financial assets and liabilities at fair value that are not currently required to be measured at fair value (the “Fair Value Option”). Election of the Fair Value Option is made on an instrument-by-instrument basis and is irrevocable. At the adoption date, unrealized gains and losses on financial assets and liabilities for which the Fair Value Option has been elected are reported as a cumulative adjustment to beginning retained earnings. Our debt obligation is treated as a Level 3 input and is fairly presented throughout our consolidated financial statements.

Recent Accounting Pronouncements
 
In January 2010, the FASB issued FASB ASU 2010-06, “Improving Disclosures about Fair Value Measurements”, which clarifies certain existing disclosure requirements in ASC 820 as well as requires disclosures related to significant transfers between each level and additional information about Level 3 activity. FASB ASU 2010-06 begins phasing in the first fiscal period after December 15, 2009. The Company is currently assessing the impact on its consolidated results of operations and financial condition.
 
In January 2010, the FASB issued Update No. 2010-05 “Compensation—Stock Compensation—Escrowed Share Arrangements and Presumption of Compensation” (“2010-05”). 2010-05 re-asserts that the Staff of the Securities Exchange Commission (the “SEC Staff”) has stated the presumption that for certain shareholders escrowed share represent a compensatory arrangement. 2010-05 further clarifies the criteria required to be met to establish a position different from the SEC Staff’s position. The Company does not have any escrowed shares held at this time. As such, the Company does not believe this pronouncement will have any material impact on its financial position, results of operations or cash flows.

 
36


In January 2010, the FASB issued Update No. 2010-04 “Accounting for Various Topics—Technical Corrections to SEC Paragraphs” (“2010-04”). 2010-04 represents technical corrections to SEC paragraphs within various sections of the Codification. Management is currently evaluating whether these changes will have any material impact on its financial position, results of operations or cash flows.

In January 2010, the FASB issued Update No. 2010-02 “Accounting and Reporting for Decreases in Ownership of a Subsidiary—a Scope Clarification” (“2010-02”) an update of ASC 810 “Consolidation.” 2010-02 clarifies the scope of ASC 810 with respect to decreases in ownership in a subsidiary to those of a: subsidiary or group of assets that are a business or nonprofit, a subsidiary that is transferred to an equity method investee or joint venture, and an exchange of a group of assets that constitutes a business or nonprofit activity to a non-controlling interest including an equity method investee or a joint venture. Management, does not expect adoption of this standard to have any material impact on its financial position, results of operations or operating cash flows. Management does not intend to decrease its ownership in any of its wholly-owned subsidiaries.

In January 2010 the FASB issued Update No. 2010-01 “Accounting for Distributions to Shareholders with Components of Stock and Cash—a consensus of the FASB Emerging Issues Task Force” (“2010-03”) an update of ASC 505 “Equity.” 2010-03 clarifies the treatment of stock distributions as dividends to shareholders and their affect on the computation of earnings per shares. The Company has not and does not intend to declare dividends for preferred to common stock holders. Management, does not expect adoption of this standard to have any material impact on its financial position, results of operations or operating cash flows.

FASB ASC TOPIC 860 - "Accounting for Transfer of Financial Assets and Extinguishment of Liabilities." In June 2009, the FASB issued additional guidance under Topic 860 which improves the relevance, representational faithfulness, and comparability of the information that a reporting entity provides in its financial statements about a transfer of financial assets; the effects of a transfer on its financial position, financial performance, and cash flows; and a transferor's continuing involvement, if any, in transferred financial assets. This additional guidance requires that a transferor recognize and initially measure at fair value all assets obtained (including a transferor's beneficial interest) and liabilities incurred as a result of a transfer of financial assets accounted for as a sale. Enhanced disclosures are required to provide financial statement users with greater transparency about transfers of financial assets and a transferor's continuing involvement with transferred financial assets. This additional guidance must be applied as of the beginning of each reporting entity's first annual reporting period that begins after November 15, 2009, for interim periods within that first annual reporting period and for interim and annual reporting periods thereafter. Earlier application is prohibited. This additional guidance must be applied to transfers occurring on or after the effective date. The adoption of this Topic is not expected to have a material impact on the Company's financial statements and disclosures.

In October 2009, the FASB issued FASB ASU No. 2009-13, Revenue Recognition (Topic 605): “Multiple Deliverable Revenue Arrangements – A Consensus of the FASB Emerging Issues Task Force.” This standard provides application guidance on whether multiple deliverables exist, how the deliverables should be separated and how the consideration should be allocated to one or more units of accounting. This update establishes a selling price hierarchy for determining the selling price of a deliverable. The selling price used for each deliverable will be based on vendor-specific objective evidence, if available, third-party evidence if vendor-specific objective evidence is not available, or estimated selling price if neither vendor-specific or third-party evidence is available. ASU 2009-13 may be applied retrospectively or prospectively for new or materially modified arrangements in fiscal years beginning on or after June 15, 2010, with early adoption permitted.  The Company is currently assessing the impact on its consolidated financial position and results of operations
 
In October 2009, the FASB issued ASC 985-605, “Software Revenue Recognition.” This ASC changes the accounting model for revenue arrangements that include both tangible products and software elements that are “essential to the functionality,” and scopes these products out of current software revenue guidance. The new guidance will include factors to help companies determine what software elements are considered “essential to the functionality.” The amendments will now subject software-enabled products to other revenue guidance and disclosure requirements, such as guidance surrounding revenue arrangements with multiple-deliverables. The amendments in this ASC are effective prospectively for revenue arrangements entered into or materially modified in the fiscal years beginning on or after June 15, 2010. Early application is permitted. The Company is currently assessing the impact on its consolidated financial position and results of operations
 
In February 2010, the FASB issued FASB ASU 2010-09, Subsequent Events, Amendments to Certain Recognition and Disclosure Requirements, which clarifies certain existing evaluation and disclosure requirements in ASC 855 related to subsequent events. FASB ASU 2010-09 requires SEC filers to evaluate subsequent events through the date in which the financial statements are issued and is effectively immediately. The new guidance does not have an effect on its consolidated results of operations and financial condition.
 
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.
 
 
37


3.  Property and Equipment

Property and equipment consist of the following:

 
 
January 2, 2010
 
 
January 3, 2009
 
 
 
 
 
 
 
 
Furniture and fixtures
 
$
79,688
 
 
$
68,371
 
Leasehold improvements
 
 
48,173
 
 
 
40,809
 
Software and computer equipment