COMMONWEALTH ENERGY CORP - 10-K Annual Report

Name and Position

Principal Occupation and Other Information

Ian B. Carter
Chairman, President and Chief Executive Officer

Mr. Carter has been our Chairman and Chief Executive Officer since January 2000, and our President since March 2003. During the preceding four month period prior to January 2000, he acted as Interim President. From October 1988 to August 1999, Mr. Carter operated his owned businesses, including a mortgage banking firm and a merchant banking firm. Prior to that, Mr. Carter served as an investment specialist for Coldwell Banker Commercial Brokerage and worked as a Systems Engineer and Salesman with IBM. Mr. Carter also served in the United States Army serving in Vietnam, Europe and the Pentagon. Mr. Carter received his Bachelor of Science degree in Engineering from the United States Military Academy at West Point, New York and his Master in Business Administration in finance from the University of Southern California.

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 at least the past 90 days: Yes x No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this Chapter) is not contained herein, and will not 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 is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes o No x

The aggregate market value of the voting and non-voting common equity held by non-affiliates as of January 31, 2003, the last business day of the registrant’s most recently completed second fiscal quarter, cannot be determined because there is no market for the registrant’s shares.

As of October 15, 2003, 27,644,567 shares of the registrant’s common stock were outstanding.

A number of the matters and subject areas discussed in this Annual Report on Form 10-K contain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended, reflecting management’s current expectations. The discussion of such matters and subject areas is qualified by the inherent risks and uncertainties surrounding future expectations generally, and also may differ materially from our actual future experience involving any one or more of such matters and subject areas. We wish to caution readers that all statements other than statements of historical fact included in this Annual Report on Form 10-K regarding our financial position and strategy may constitute forward-looking statements. For example, statements herein relating to expansion opportunities for our subsidiaries, extension of our business model to new markets and industries, demand in the market for UtiliHost™ services, completion of acquisitions of certain assets, growth of retail energy operations and demand for retail energy outsourcing and back office solutions are all forward-looking statements. When used in this document, the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “project,” “plan,” “should,” and similar expressions are intended to be among the statements that identify forward-looking statements. All of these forward-looking statements are based upon estimates and assumptions made by our management, which although believed to be reasonable, are inherently uncertain. Therefore, undue reliance should not be placed on such estimates and statements. No assurance can be given that any of such estimates or statements will be realized and it is likely that actual results will differ materially from those contemplated by such forward-looking statements. Factors that may cause such differences include: (a) regulatory changes in the states in which we operate that could adversely affect our operations; (b) our continued ability to obtain and maintain licenses from the states in which we operate; (c) the competitive restructuring of retail marketing may prevent us from selling electricity in certain states; (d) our dependence upon a limited number of third parties to generate and supply to us electricity; (e) fluctuations in market prices for electricity; and (f) our dependence upon a limited number of utilities to transmit and distribute the electricity we sell to our customers. We have attempted to identify, in context, certain of the factors that we currently believe may cause actual future experience and results to differ from our current expectations regarding the relevant matter or subject area. In addition to the items specifically discussed above, our business and results of operations are subject to the risks and uncertainties described under the heading “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation — Factors That May Affect Future Results” contained herein; however, the operations and results of our business also may be subject to the effect of other risks and uncertainties. Such risks and uncertainties include, but are not limited to, items described from time to time in our reports filed with the Securities and Exchange Commission. We assume no obligation to update the forward-looking information to reflect actual results or changes in the factors affecting such forward-looking information.

Commonwealth Energy Corporation is an energy services company. We provide retail electric power to our residential, commercial, industrial and governmental customers in the deregulated California, Michigan and Pennsylvania electricity markets. We are licensed by the Federal Energy Regulatory Commission, or FERC, as a power marketer and we are licensed to supply retail electric power by applicable state agencies in California, Pennsylvania, Michigan, New Jersey, New York, Texas and Ohio. As used in this Report, the terms “we,” “us,” “our,” “the Company” and “Commonwealth” refer to Commonwealth Energy Corporation and its wholly-owned subsidiaries.

We do not have our own electricity generation facilities. The power we sell to our customers is purchased from third party power generators. The electric power we sell to our retail customers is delivered to our customers by incumbent electric utilities. The incumbent electric utilities measure electric power usage by our customers and bill most of our customers on our behalf. We plan to enter new deregulated electric power markets and to offer a variety of energy-related products and services in the future. We also sell surplus electric power not needed to meet our retail customers’ requirements in wholesale electricity markets. We only sell this excess power to assist us in balancing our energy supply with the demand of our retail customers. We do not trade in the wholesale electricity markets for speculative purposes.

Commonwealth Energy Corporation has three wholly-owned subsidiaries: electricAmerica, Inc., UtiliHost, Inc. and electric.com, Inc. Each of these subsidiaries is incorporated in the State of Delaware, but as of yet, none of them is operational. We also hold a majority interest in Summit Energy Ventures, LLC (“Summit”), a joint venture that invests in companies that manufacture or market energy efficiency products. The consolidated financial statements of the Company include the accounts of Summit, Power Efficiency Corporation (one of the companies in which Summit has invested) as of May 8, 2003 and the Company’s wholly-owned subsidiaries. Commonwealth Energy Corporation was incorporated in California on August 15, 1997.

Prior to the inception of electricity deregulation in 1998, the retail electric service industry was controlled almost exclusively by utilities. Presently, twenty-four states and the District of Columbia have either enacted enabling legislation or issued a regulatory order to implement retail access. The local utility typically continues to provide transmission and distribution (delivery of energy) services. Retail access allows customers to choose their own supplier of generation energy services, but each state’s retail access schedule varies according to the legislative mandates or regulatory orders.

As in other industries that have deregulated, competition in the electric service industry is intended to provide consumers with a choice of multiple suppliers that is expected to promote product differentiation, lowered costs and enhanced services. To obtain these features, customers may switch electric service from their utility to an alternative supplier.

The electricity distribution infrastructure utilized by utility companies prior to deregulation of the energy industry remains the only current method of distribution to the end-use customer. Retail electricity suppliers use this established electricity network for the delivery of energy to their customers. The utility company is paid a fee for use of its wires. Fees paid to established utility companies for use of their infrastructure are collected by the respective independent system operator, or ISO, or regional transmission organization for a specific region or state. The ISO or regional transmission organization ensures that proper electricity reserve margins are in place at all times, as electricity must have supply and demand in near perfect balance to insure reliable service. These ancillary transmission and reliability services typically run 5% to 10% of prevailing wholesale electricity market prices. We generally pass these costs on to our retail customers.

Electric service providers procure power to deliver to retail customers from a variety of wholesale power producers, either through long term bilateral contracts with the generators or from the ISO on a short term basis. The power inventory obtained from the ISO is purchased and sold by the ISO to balance the market and make sure each corresponding sale of electricity is matched to a buyer of electricity. The function of the ISO is to provide system reliability to the market.

Power purchases in California are facilitated by the California Independent System Operator, or CAISO, a market oversight body. CAISO is responsible for ensuring that all electricity put into the grid has a corresponding exit from the grid and for maintaining system reliability. This matching of power transactions is accomplished in a constant sequence of 15 minute increments. The Pennsylvania marketplace is governed by a similar structure called the PJM interconnection. The PJM is responsible for matching all power transactions among market participants and ensuring system reliability. The Michigan market is governed by a similar structure called the Michigan Independent System Operator.

In addition to basic service of distributing electricity to retail customers, some states allow the utility company to take on additional responsibilities, such as reading meters, generating bills to customers, collecting bills and taking requests for service changes or problems, while in other jurisdictions the utility is not allowed, or chooses not, to perform these services.

On September 20, 2001, the California Public Utilities Commission (the “CPUC”) issued a ruling suspending “direct access.” “Direct access” refers to the right of retail electricity suppliers like us to actively seek new customers in California from incumbent utilities or other electricity service providers. This ruling permits retail electricity suppliers to keep their current customer bases, but prohibits us from signing up new non-direct access customers in California for an undetermined period of time.

Our primary business is retail electricity services. We sell electric power to retail and commercial end-user customers. This electric power is delivered to our customers by the incumbent utility distribution companies, known as UDCs, or electric distribution companies, known as EDCs, depending upon the jurisdiction. They measure electric power usage and bill most of our customers on our behalf. Three UDCs in California, one EDC in Pennsylvania and one UDC in Michigan conduct these activities on our behalf. In California, Pennsylvania and Michigan, the utility companies currently assist us with a portion of the preparation, mailing and collection of our bills to end-use customers. In addition, the utility companies are invoicing and collecting the charges and fees owed by us to them associated with those services as well as the right to use the distribution network.

We offer electric service to customers under month-to-month or longer-term service contracts. The difference between the customers’ list price for energy and the sum of our wholesale electricity purchase cost and ancillary costs provide us a gross profit/loss margin.

Due to the variable electricity usage patterns of our retail customers, we may hold “long” or “short” energy positions. A “long” position occurs when we have committed to purchase through long-term contracts more electricity than our customers need and a short position occurs when our customers’ needs exceed the amount of electricity we have committed to purchase through long-term contracts. In both situations, we utilize the wholesale electricity spot market to sell excess energy when we are “long” and buy additional electricity when we are “short.” In order to better manage and schedule our customers’ electricity load and our wholesale power purchases, we have established a power resources department that buys and sells our electricity in various regional markets. Excess energy is sold to entities short on supply, while additional energy is procured from time to time when required to supply our customers’ usage. This spot market buying and selling is done to balance our energy supply with the demand of our retail customers.

Purchases and sales in the wholesale market are regulated by FERC and reports are made on a regular basis to the U.S. Department of Energy. Typically, electricity is more expensive during peak hours, when demand and usage are highest. Weather, generation capacity, transmission, distribution and other

market issues also are significant factors in determining our wholesale procurement and sale strategies. Because electricity is a “real-time” commodity (as soon as it is produced, it must be delivered into the grid to meet the demand by the end user) and cannot be stored, effective management of our electricity supply and demand is crucial to energy market profitability.

We are working to broaden the scope of the energy-related services we provide to include energy efficiency products, energy management programs and load aggregation. Each of these services are in the development stage and, as yet, have not begun to contribute to our financial results.

We sell energy efficient and emergency preparedness products, such as energy management controllers, compact fluorescent lamps, natural gas shut-off valves and other similar devices. These products are targeted to residential, commercial, industrial and governmental customers. We intend to expand our offerings in this area and market energy efficient products to consumers and businesses throughout North America.

In July 2001, we formed Summit Energy Ventures, LLC, or Summit, a joint venture with Steven Strasser. Summit makes investments in companies that manufacture products that conserve or manage electricity. We made the initial capital contribution of $15 million into Summit, which to date represents the entire capital contribution to Summit.

To date, Summit has invested a total of approximately $8 million in three companies:


	•	Envenergy, Inc. — Envenergy is a developer of software and hardware for energy and facility management. Envenergy’s products provide the infrastructure to collect information from separate facility systems (e.g., building automation, energy, lighting, access control and metering) and assimilate this raw data into useful information from which energy service companies, facility management providers, equipment and building automation system manufacturers and utilities can assess energy usage and costs. Summit currently owns approximately 8.7% of Envenergy.

	•	Turbocor, B.V. — Turbocor, B.V. owns 62.1% of Turbocor, Inc., a manufacturer of energy-efficient compressors for commercial heating, ventilating, air conditioning and refrigeration applications. Summit currently owns approximately 8.8% of Turbocor, B.V., which represents a 5.5% indirect interest in Turbocor, Inc.

	•	Power Efficiency Corporation — Power Efficiency Corporation designs, develops, assembles and markets its own branded solid state electronic products, called “Performance Controllers” that reduce energy consumption in alternating current induction motors. Summit currently owns approximately 53% of Power Efficiency Corporation.

In the fourth quarter of the fiscal year ended July 31, 2003, or fiscal 2003, Summit’s investment in Power Efficiency Corporation became a controlling interest. For purposes of financial reporting, our consolidated financial statements include the accounts of Summit and Power Efficiency Corporation as well as those of our wholly-owned subsidiaries.

Our joint venture partner in Summit, Steven Strasser, is the president and sole shareholder in Northwest Power Management, or NPM, the investment manager of Summit. NPM is responsible for managing the funds that we have invested in Summit. All investments must be approved by Summit’s investment committee, which is comprised of three individuals, all of whom are appointed by Commonwealth. NPM manages the investment until such time as a decision to sell is made. When a sale

of an investment to a third-party buyer is proposed, we have the option to buy out Summit’s interest in a specific investment on the same terms as the third-party buyer. We pay an annual management fee of $700,000 to the investment manager as compensation for its performance of investment management services and administrative services for Summit.

We own 100% of the preferred membership interest of Summit and 60% of the common membership interest. Steven Strasser owns the other 40% of the common membership interest. Our preferred membership interest entitles us to a distribution preference equal to all of our initial invested capital plus an annual 10% preferred return before any funds are distributed to the holders of the common membership interests; net losses are allocated per capital contribution. In addition, as the preferred member, we have a right of first refusal in the event of any issuances of new membership interests. Under the terms of the Summit operating agreement, we have the right to purchase any of the investments acquired by Summit at any time during the agreement on terms mutually agreeable to both NPM and us. We have the choice to pay for the investments in cash or to credit any balance in our capital account in Summit against the purchase price of the investment. If we are unable to reach agreement with NPM with respect to the fair market value of such investment, then NPM is required to obtain a valuation of the investment from a nationally recognized investment bank or appraisal firm which firm shall be approved by Summit’s investment committee; provided, however, that the valuation of the investment shall be the projected value of the investment at the termination of the Summit operating agreement, which is June 2006.

We formed Summit as part of our strategy to diversify our business by marketing energy efficiency products. We believe Summit will provide us with opportunities in the energy efficiency products market, either by acquiring a controlling interest in the companies in which Summit has invested when such companies have developed and distributed successful products, or through marketing and distribution arrangements. We intend to use our ownership interest in these companies to help us enter into preferred marketing agreements and other opportunities with these Summit companies with respect to selling their energy efficiency products.

We have developed software to better manage our electric service customers. TACT^TM (Trans-Action Control Technology) and TRIUMPH^TM (Total Resource Internet Utility Management Power Host) are proprietary software products that we have developed to provide services and manage back office processes associated with our retail customers. TACT^TM acts as a data translator between trading partner transactions, while TRIUMPH^TM is a comprehensive, modular software package that calculates and manages back office processes such as customer enrollment, forecasting, metering, ancillary products, billing, accounts receivable, customer service and settlement. By developing the TRIUMPH^TM system in-house, we have not had to acquire and pay for these services from a third party. We commenced efforts to market our managed back office services to third parties in February 2001 through direct mail, print media and Internet advertising, primarily in deregulated energy markets. We have formed a wholly-owned subsidiary, UtiliHost, Inc., to act as a platform for providing outsourcing services to manage client-related back office processes for third parties, such as municipalities, energy generators and other electric service providers. We have begun to market these services to third parties, but to date, we have not generated any revenues from third parties relating to our managed back office services.

Load aggregation is the process of combining customers with different electricity usage patterns into a portfolio of customers that can be serviced by our purchases of electric supply. We are currently discussing with several generators and utilities a comprehensive solution for cities and major commercial and industrial customers to meet their energy demands. We are able to assist cities to become municipal utilities or by providing them with all required energy procurement, energy management, customer service and back-office services. We also can provide similar services for major commercial and industrial customers to meet their electricity demand requirements. We believe this program will allow us the opportunity to take a diversified approach to aggregating customers to sell them electricity and bill them

In Pennsylvania during fiscal 2003 as part of the PECO Energy Co. 1998 restructuring settlement, we were awarded 49,172 out of a possible 64,000 small commercial customers in the effected territory through a bid process. We received approximately 40,000 of those customers after they were given an opportunity to “opt-out” of the process and remain electric generation customers of PECO. Our award of these customers is an example of our ability to consolidate and service a portfolio of customers. We intend to continue to acquire existing aggregated customer portfolios from utilities and other industry participants.

In September 2002, California passed a law enabling California cities and counties to establish Community Choice Aggregation programs. Such programs allow cities and counties to aggregate residential, commercial, industrial and municipal electric service customers into a portfolio that can be supplied electric generation from ESPs and other non-utility providers. We are marketing services to assist cities and counties in such efforts and intend to provide them with required energy procurement, energy management, customer service and back-office services. While we are in discussions with several cities, to date, we have not entered into any contracts to provide them load aggregation services.

Energy management programs consist of energy curtailment programs and distributed generation programs. Energy curtailment programs permit short-term curtailment or cessation of electric service at the discretion of the distributing company under certain circumstances, as specified in the service contract. These programs provide a win-win proposition for our customers and for us by creating a financial incentive for our customers to lower their electrical usage during certain times of the day. In connection with the reduction in energy usage by our customers, we also benefit because we are able to avoid the purchase of expensive power from other suppliers to meet our customers’ excess energy needs. The resulting savings from these energy management programs are shared between the customer and us. Our sales department markets these programs to commercial, industrial and governmental entities seeking to save energy costs by decreasing their energy usage during peak periods. The availability of curtailment programs is dependent upon the initiatives set by the ISO and/or the local distribution company. We are presently not involved in any energy curtailment programs; however, we will continue to offer this service when ISOs and/or local distribution companies make these programs available.

Distributed generation programs provide customers with on-site electric power generation. We offer to our customers the service of designing and implementing reliable custom energy solutions by equipping them with alternative, cost-effective or renewable sources for seasonal or peak demand power. We are in the process of installing a photo voltaic distributed generation application for a water district in Southern California.

We began providing electric service in April 1998 as one of more than 300 licensed electric service providers, or ESPs, in the state of California by aggregating customers using our contact center. As our customer base grew, we began to develop software solutions to better manage our back office customer service functions associated with servicing electricity accounts. We also began to provide service to larger commercial, industrial and governmental customers. We expanded our retail electricity services to end users in Pennsylvania in January 2000 and in Michigan in August 2002. We have begun to focus on targeting businesses customers rather than residential customers. We use our trade name “electricAmerica” in all markets in which we supply retail electric power. We aggregate residential, commercial, industrial and governmental customers using our contact center. Currently, we sell electric power to approximately 51,000 retail end-use customers in California, approximately 64,000 retail end-use customers in Pennsylvania and approximately 3,000 retail customers in Michigan.

The price of electricity can fluctuate significantly. In an attempt to manage this risk, we enter into long-term wholesale power purchase agreements which allows us to purchase fixed daily quantities of electricity at fixed prices. We purchase electricity from a variety of generators in the wholesale electricity markets under bilateral contracts for terms that vary in length from one month to three years forward. Additionally, we buy and sell incremental volumes of electricity in the short-term or spot wholesale markets as necessary to balance our electricity supply with our customers’ load requirements.

In California, we obtain most of the electricity we sell under contracts with three suppliers. To the extent necessary, we continue to purchase electricity in the wholesale spot market from time-to-time in California.

In Pennsylvania, we obtain most of the electricity we sell pursuant to long-term contracts, approximately 76% of which is with a single energy supplier. To the extent necessary, we also purchase electricity in the wholesale spot market from time-to-time in Pennsylvania.

In Michigan, we obtain most of our power from a single energy generator, pursuant to long-term contracts.

Wholesale electricity is readily available from various sources in each of the states in which we have customers. Based upon current information from our suppliers, we do not anticipate any shortage of supply. In the event that it becomes necessary for us to obtain wholesale electricity from an alternative supplier, we believe that an alternative supplier could be secured within a reasonable period of time. However, there can be no assurance that we would be able to timely secure an alternative supply of electricity at comparable prices to our long-term contracts, and the failure to replace a supplier in a timely manner at comparable prices could materially harm our operations.

We market supplies of electricity to end-user customers in the states of California, Pennsylvania and Michigan as “electricAmerica” through multiple channels. We acquire the vast majority of our customers through our in-house sales group which handles inbound calls from customers and makes outbound calls to targeted customers. We have separated our sales employees into two units. We refer to the larger group as our “contact center.” Our contact center group is responsible for procuring orders from residential or small commercial customers. All customers acquired by the contact center agree to our terms of service through a third party voice log system. This sign-up device simplifies the switching process for these customers and shortens the sales cycle.

Our smaller group of marketers, which we refer to as our commercial and industrial sales, or C&I Sales, group, is responsible for targeting medium and large commercial, industrial and governmental customers through telephone solicitation as well as face to face meetings. Customers acquired by our C&I Sales group enter into individualized written contracts. For this reason, the sales cycle is typically longer because each agreement is usually customized to meet the customer’s needs. The C&I Sales group also works with third party energy consultants or energy service companies which manage the energy expenses for large commercial and industrial companies to acquire customers.

We also use our electricAmerica website, www.electricAmerica.com, as a tool to help acquire customers. The website provides customers with detailed electric supply information in each territory that we serve and enables customers to complete forms online, send us e-mails or find our toll-free telephone number, 1-800-ELECTRIC.

In California, due to the suspension of direct access on September 20, 2001, we are not allowed to acquire customers that were not with a direct access provider as of that date. This has impaired our ability to locate and acquire customers, especially residential and small commercial customers in California. The suspension of direct access in California has impaired our C&I Sales group to a lesser degree because they have been able to acquire a few large customers from other direct access providers.

Our retail energy sales depend upon our ability to identify and enter into favorable energy markets and to achieve sufficient customer scale to create a profitable operating cost structure. Currently, we are:


	•	Selectively entering retail energy markets that have rate structures, market rules, consumer demographics, energy consumption patterns, access to favorable electricity supply and risk management profiles that are designed to enable us to provide savings and flexibility to our customers at an acceptable margin.

	•	Capitalizing on the brand recognition of “electric” through our web site at www.electricAmerica.com and through our inbound toll-free number, 1-800-ELECTRIC.

	•	Taking advantage of the increasing consumer acceptance of online commerce, both directly through our web sites (www.electricAmerica.com and www.electric.com) and through traditional channels.

	•	Developing strategic marketing alliances with established power suppliers to offer competitive electric products and services to, and management of, aggregations of customers.

	•	Offering additional products and services to our customers, such as energy efficiency and emergency-preparedness products.

	•	Positioning UtiliHost^TM to be a source for our clients to outsource their energy related customer service management.

We believe that as retail energy markets are opened to new participants and new services, competition will be intense in the markets where frameworks for deregulation create attractive opportunities for new entrants. In general, we believe our principal competitor in each market will be the incumbent utility in that market or an unregulated utility affiliate. Incumbent utilities may have informational advantages, high name recognition in their traditional service territory and long-established customer relationships. In addition to the utilities and their affiliates, we may face competition from a number of other energy service providers, including start-up companies focusing on Internet marketing and online service, other energy industry participants, and possibly other consumer-oriented service providers, any of whom may develop businesses that will compete with us, both in specific markets and nationally. Some of these competitors may be larger and better capitalized than we are.

We generally compete for customers on the basis of price or, when customers demand electricity derived from environmentally-friendly fuel sources, by delivering more environmentally friendly (not derived from fossil-fuel sources) electricity than our competitors.

We face competition in selling energy efficient and emergency preparedness products from many sources, including traditional hardware retailers and online energy product retailers.

We face competition in managing back office services from application service providers, outsourcing vendors, utility billing vendors and large enterprise-wide software and systems integrators.

Our revenues are subject to fluctuations during the year; primarily due to the impact certain seasonal factors have on sales volumes and the wholesale prices of electricity. Electricity sales volumes have been historically higher in the summer months than in the fall and spring months, reflecting increased demand due to increased cooling requirements and higher electricity sales tariffed rates. Additionally, electricity sales volumes are modestly higher in the winter months than in the fall and spring months, due to increased demand for heating and lighting requirements.

In states that have adopted deregulation, state public utility commissions, or PUCs, have authority to license and regulate certain of the activities of electric supply retailers. Accordingly, we are subject to

regulation by the PUC in each state in which we make retail sales of electric power. The requirements for licensing and the level of regulation vary from state to state. We are currently licensed by the applicable PUCs in California, Michigan, New Jersey, New York, Ohio, Pennsylvania, and Texas. These licenses permit us to sell electrical power to commercial, industrial, governmental and residential customers.

We are subject to regulation by various federal, state and local governmental agencies. Our wholesale purchases and sales are subject to the jurisdiction of the FERC under the Federal Power Act. We make wholesale sales of electricity pursuant to a Power Marketer certificate issued by FERC. While FERC does not generally regulate the rates, terms or conditions of these electricity sales, FERC has the authority to institute proceedings to identify transactions involving rates that are not just and reasonable due to market manipulation and to reverse or unwind such transactions to ensure just and reasonable rates.

As of July 31, 2003, we employed 172 full-time employees and 1 part-time employee, including: 27 in corporate administration, 9 in corporate finance, 84 in marketing and sales, and 51 in operations. None of our employees is covered by a collective bargaining agreement or is presently represented by a labor union. We have not experienced any work stoppages and consider our employee relations to be good.

Our strategy for protection of our trademarks is to routinely file U.S. federal and foreign trademark applications for the various word names and logos used to market our technology solutions to licensees and the general public. The duration of the U.S. and foreign registered trademarks can typically be maintained indefinitely, provided proper maintenance fees are paid and trademarks are continually used or licensed by us.

The following table sets forth information regarding our executive officers, including their respective business experience during the last five years and age as of October 15, 2003. Executive officers are elected by, and serve at the pleasure of, the Board of Directors.

Our principal executive office is located in Tustin, California. This facility houses our administrative operations. We lease approximately 33,104 square feet of office space at these premises pursuant to a lease that expires on April 14, 2004. We believe that we will be able to renew or find adequate replacement offices for this lease at comparable costs.

We lease additional office space for our operations in Cherry Hill, New Jersey. This additional space consists of 2,265 square feet pursuant to a lease that expires on June 30, 2005.

We believe that our leased property is in good condition, is well maintained and is adequate for our current and immediately foreseeable operating needs.

On August 16, 2001, Joseph P. Saline, one of our directors, filed an action in California Superior Court for Orange County (Case No. 01CC10657) seeking an order granting him access to all of our documents and records. We filed a cross-petition alleging that Mr. Saline unlawfully disseminated confidential information belonging to us, breached his confidentiality agreement with us, breached his fiduciary duty to us, and illegally tape recorded meetings. Our cross-petition sought, among other things, to limit Mr. Saline’s ability to distribute the corporate documents he was seeking. The trial court issued an order granting Mr. Saline access to certain documents, but prohibited Mr. Saline from disclosing or discussing the documents he requested with anyone other than his attorney and other members of our Board of Directors. We provided Mr. Saline with copies of certain corporate documents under the protection of the court order. Mr. Saline filed an appeal, seeking to reverse the restrictions on his right to

disclose or discuss the documents with third parties and to reverse the trial court’s limits on Mr. Saline’s inspection rights. On July 30, 2002, the California Court of Appeal reversed the order of the Superior Court that limited Mr. Saline’s ability to disseminate the documents. The Court of Appeal further granted Mr. Saline with access to all of our documents and records. The Court of Appeal also ordered that Mr. Saline shall recover the costs of his appeal from us. In March 2003, the court denied our motion for summary judgment with respect to our counter claims. In September 2003, we amended our cross-petition. As amended, our cross-petition alleges that Mr. Saline committed breach of contract (failure to adhere to his confidentiality agreement with us), breached his fiduciary duty (failure to disclose his ownership interest in New World Power Corporation and use of nonpublic information in connection with the purchase of securities), committed libel (making false and misleading statements in proxy materials), violated the California Criminal Code (intentionally tape recording other directors without their consent); committed intentionally inducement of breach of contract, and engaged in unfair business practices (committing unfair, unlawful and fraudulent acts). This case is currently pending.

On October 29, 2001, Mr. Saline filed a civil claim against us in California Superior Court for Orange County (Case No. 01CC13887). Mr. Saline alleges that we breached a contract to sell to Mr. Saline preferred shares, are estopped to deny the rights and privileges of Mr. Saline’s preferred stock, unlawfully denied him his voting rights and committed unfair business practices. In his complaint, Mr. Saline alleged that he is the holder of 352,000 shares of preferred stock, with two-for-one conversion and voting rights that differ from the rights set forth in the Certificate of Determination for our Series A Preferred Stock filed with the California Secretary of State. Mr. Saline also has made claims for damages, including punitive damages. We filed an answer disputing Mr. Saline’s claims and filed a cross-complaint for declaratory relief. Mr. Saline filed a request for a preliminary injunction prior to our 2001 annual meeting of shareholders. On November 14, 2001, the court issued an interim court order prohibiting us from refusing to recognize that Mr. Saline owns 352,000 of our preferred stock, convertible into common stock and entitled to vote on a two-for-one basis, pending final resolution of the case. On November 14, 2002, the court, after making a preliminary finding that the shares were “void” as a matter of law, issued an order dissolving the interim court order. A trial was held in June 2003. On September 24, 2003, the court issued an order prohibiting us from refusing to recognize that Mr. Saline owns 352,000 of preferred stock, convertible into common stock and entitled to vote on a two-for-one basis. We intend to appeal the court’s ruling. Currently, the 352,000 shares of preferred stock have been reflected in our financial statements as “Other convertible preferred stock” and are referenced in the beneficial ownership table set forth in “Item 12 Security Ownership of Certain Beneficial Owners and Management.” A second phase of the trial to consider Mr. Saline’s claims for damages is pending.

On February 23, 2001, several former employees filed a lawsuit against us in the Superior Court of the State of California in the County of Orange Superior Court (case number 01CC02611). The complaint was filed by David James and twelve other former employees who worked with David James in raising investment capital for us. The plaintiffs’ complaint alleged claims for unfair business practices, breach of contract, and fraud and intentional deceit. The plaintiffs alleged, in summary, that they were formerly employed by us and are owed commissions and stock options from us under their alleged employment agreements and based on alleged representations that were made to them by former officers of Company in the course of their employment. We filed a cross-complaint asserting claims for breach of contract; unfair business practices; misappropriation of trade secrets; intentional interference with prospective economic advantage; negligent interference with prospective economic advantage; conversion; slander; prohibitory injunctive relief; mandatory injunctive relief; and declaratory relief, which we dismissed without prejudice. In addition, we filed a first amended cross-complaint that asserted additional cross-claims against plaintiff David James for rescission and restitution, fraud, money had and received, unjust enrichment and declaratory relief. The plaintiffs sought, among other relief, damages in the amount of $10.3 million, plus costs and attorneys’ fees. A jury trial was held in this matter beginning in October 2002. On December 10, 2002, the jury returned a verdict finding for the plaintiffs in the amount of $2.7 million of compensatory damages. During the trial, we voluntarily dismissed our cross-complaint without prejudice. In January 2003, we filed post-trial motions for a new trial and for a judgment notwithstanding the verdict, seeking to have the $2.7 million verdict for the plaintiffs set aside. In March

2003, the court denied the post-trial motions for a new trial and for a judgment notwithstanding the verdict. We filed a notice of appeal in March 2003, seeking reversal of the judgment in favor of the plaintiffs. On June 26, 2003, the court ruled that we were the prevailing party on the contract claims brought by the plaintiffs and that we were entitled to recover attorney’s fees and costs from the plaintiffs totaling approximately $1.1 million. The plaintiffs have appealed the court’s ruling awarding us attorney’s fees. These appeals are currently pending. In order to stay the enforcement of the judgment pending appeal, we initially posted an appellate bond of approximately $4.1 million. In September 2003, the court issued an order permitting us to reduce the bond to $2.6 million.

We filed a complaint in the Orange County Superior Court on February 14, 2003 against Sylvia E. Bates, as Trustee of the Robert M. Bates Family Trust, seeking a judicial declaration invalidating 252,000 shares of our capital stock the defendant claims to hold. Ms. Bates filed and served a general denial to the complaint on April 25, 2003. A mandatory settlement conference has been scheduled for December 12, 2003. This case is currently pending.

We filed a complaint in Orange County Superior Court on February 14, 2003 against Joseph Ogundiji, as Trustee of the Ogundiji Family Holdings Trust, seeking a judicial declaration invaliding 80,000 shares of our capital stock the defendant claims to hold. On April 11, 2003, Mr. Ogundiji filed and served an answer and cross-complaint alleging claims against us for breach of contract, conversion, declaratory relief, promissory estoppel, unlawful denial of voting rights pursuant to California Corporations Code section 709, illegal stock dividend in violation of California Corporations Code section 25120, and unjust enrichment. The cross-complaint seeks an unspecified amount of general and punitive damages. This case is currently pending.

We are currently, and from time to time may become, involved in other litigation concerning claims arising out of our operations in the normal course of business. While we cannot predict the ultimate outcome of our pending matters or how they will affect our results of operations or financial position, management currently does not expect any of the legal proceedings to which we are currently a party, including the legal proceedings described above, individually or in the aggregate, to have a material adverse effect on our results of operations or financial position.

No matters were submitted to a vote of our shareholders during the fourth quarter of fiscal 2003.

There is currently no established public trading market for any class of our equity securities.

As of October 15, 2003, there were 2,927 holders of record of our common stock and 59 holders of record of our Series A Convertible Preferred Stock.

Our Series A Convertible Preferred Stock provides for cumulative dividends that accrue at a rate of 10% per annum. During fiscal 2002 and fiscal 2003, we have declared and paid cash dividends of $30,195 and $92,100, respectively, on our Series A Convertible Preferred Stock. As of July 31, 2003, accrued cumulative unpaid dividends on our Series A Convertible Preferred Stock were $90,548. All accrued dividends on the Series A Preferred must be paid before any dividends are declared or paid on shares of common stock.

In addition, there is a dispute with respect to 352,000 shares of preferred stock that are not currently reflected as outstanding on our shareholder list. The validity of these disputed shares of preferred stock is the subject of pending litigation. See “Item 3. Legal Proceedings.” If these disputed shares of preferred stock are determined to be valid, a portion of such shares would accrue interest at a rate of 12% per annum, while the remainder would accrue interest at a rate of 14% per annum. At July 31, 2003, the amount of such accrued unpaid dividends on these shares would have been $42,240. All accrued dividends on these disputed shares of preferred stock would be required to be paid before any dividends are declared or paid on shares of common stock.

We have not declared or paid a cash dividend on our common stock, and we do not anticipate paying any cash dividend for the foreseeable future. We presently intend to retain earnings to finance future operations, expansion and capital investment.

Information concerning securities authorized for issuance under our equity compensation plans is set forth in “Item 12. Security Ownership of Certain Beneficial Owners and Management — Equity Compensation Plan Information,” and that information is incorporated herein by reference.

The selected financial data in the following tables sets forth (a) balance sheet data as of July 31, 2002 and 2003, and statement of operations data for the fiscal years ended July 31, 2001, 2002 and 2003 derived from our consolidated financial statements audited by Ernst & Young LLP, independent auditors, which are included elsewhere in this filing, and (b) balance sheet data as of July 31, 1999, 2000 and 2001, and statements of operations data for the fiscal years ended July 31, 1999 and 2000, derived from our consolidated financial statements audited by Ernst & Young LLP, which are not included in this filing. The information below should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation” and “Item 8. Financial Statements and Supplementary Data” included elsewhere in this filing.


(2)	No cash dividends have been paid on our common stock. Our Series A convertible preferred stock provide for cumulative dividends, which accrue at the rate of 10% per annum, and are payable at the discretion of our Board of Directors. Such accrued dividends were $84, $84, $81, $70 and $91 in the fiscal years ended July 31, 1999, 2000, 2001, 2002 and 2003, respectively. In addition, we are subject to a court order with respect to disputed shares of preferred stock that are not currently reflected as outstanding on our shareholder list. The validity of these disputed shares of preferred stock is the subject of pending litigation. See “Item 3. Legal Proceedings.” If these disputed shares of preferred stock are determined to be valid, a portion of such shares would accrue dividends at a rate of 12% per annum, while the remainder would accrue interest at a rate of 14% per annum. Such accrued dividends would have been $42 in fiscal year ended July 31, 2003 and are reflected in our accompanying financial statements. See Note 6 of the Notes to Consolidated Financial Statements included elsewhere herein, for the computation of earnings per common share.

(3)	Per share information and weighted average shares outstanding for the years ended July 31, 1999 and 2000 have been restated to reflect the resolution of the status of our common stock issued to our founder as more fully disclosed in Note 14 of the Notes to Consolidated Financial Statements, included elsewhere herein.

(4)	Per share information, weighted average shares outstanding and shareholders equity for the year ended July 31, 2003 reflect the 352 shares of preferred stock, referenced in our financial statements as “Other preferred stock,” related to pending litigation. See “Item 3. Legal Proceedings” and Notes 6, 12 and 14 of the Notes to Consolidated Financial Statements for further details.

Our primary business has been the sale of electric power to retail and commercial end-users in California, Pennsylvania and, beginning in September 2002, in Michigan, and the sale of electric power to wholesale customers in California and Pennsylvania. We are licensed by FERC as a power marketer and by the California, Michigan, Pennsylvania, New Jersey, New York, Texas and Ohio public utilities commissions as an electric services or electric generation supplier.

As of July 31, 2003, we delivered electricity to approximately 118,000 customers in California, Michigan and Pennsylvania. The growth of this business depends upon the deregulated status of each state, the availability of cost-effective energy purchases to us and the acquisition of retail or commercial customers by us.

We do not have our own electricity generation facilities. The power we sell to our customers is purchased from third-party power generators. During fiscal 2000, in both California and Pennsylvania, we purchased electricity both under long-term contracts and in the spot market. By the end of fiscal 2001 and throughout most of fiscal 2002, substantially all of our electricity was purchased under long-term contracts. During fiscal 2003, we purchased electricity both under long-term contracts and in the spot market.

In the following comparative analysis, all percentages are calculated based on dollars in thousands.

Our net revenue for fiscal 2003 was $165.5 million, an increase of $47.7 million, or 40.6%, from $117.8 million in fiscal 2002. Net energy sales were $160.0 million, or 96.6%, of our fiscal 2003 net revenue, as compared to $115.7 million, or 98.3%, of our fiscal 2002 net revenue. Green power credits recognized from the State of California accounted for the balances of our net revenue.

Energy sales to retail customers constituted $153.4 million, or 95.9%, of our net energy sales for fiscal 2003, as compared to $97.0 million, or 83.8%, for fiscal 2002. Sales of excess energy in the wholesale markets constituted $6.5 million, or 4.1%, of our net energy sales for fiscal 2003, as compared to $18.8 million, or 16.2%, for fiscal 2002. Excess energy is sold into the wholesale market after we have supplied the requirements of our retail customers. These sales are a natural by-product of balancing the power load used by our customers against the power we have previously purchased under contracts in anticipation of our forecasted customer demand. Power is also purchased in this balancing process when required.

We sold 1,120.3 million kilowatt-hours (“kWh”) at an average retail price per kWh of $0.077 in California during fiscal 2003, as compared to 775.6 million kWh sold at an average retail price per kWh of $0.085 during fiscal 2002. This increase was due primarily to the acquisition of large commercial customers from other ESPs. The decrease in price is partially attributable to the historical procurement charge in the Southern California Edison territory. For a more complete discussion of the historical procurement charge and related CPUC activities see “Factors That May Affect Future Results — Historical procurement charges and customer rate changes could adversely affect our revenue and cash flows in the Southern California Edison utility district” in this Item 7. We sold 836.5 million kWh at an average retail price per kWh of $0.060 in Pennsylvania during fiscal 2003, as compared to 468.9 million kWh sold at an average retail price per kWh of $0.058 during fiscal 2002. This increase was due primarily to the acquisition of approximately 40,000 customers in Pennsylvania under a bid process that was a part of an electric utility restructuring in Pennsylvania. We sold 230.4 million kWh at an average retail price per kWh of $0.058 in Michigan during fiscal 2003, as compared to no billing during fiscal 2002.

The $56.4 million, or 58.2%, increase in our fiscal 2003 retail energy sales primarily was attributable to an increase in our customer base as we entered the Michigan market and gained market share in Pennsylvania.

We sold 71.4 million kWh at an average wholesale price per kWh of $0.036 in California during fiscal 2003, as compared to 313.8 million kWh sold at an average retail price per kWh of $0.023 during fiscal 2002. We sold 140.1 million kWh at an average wholesale price per kWh of $0.028 in Pennsylvania during fiscal 2003, as compared to 463.2 million kWh sold at an average wholesale price per kWh of $0.025 during fiscal 2002. We did not sell any wholesale energy in Michigan during fiscal 2003, as our Michigan supplier was operating under a load following, full requirements contract. Such contracts provide for all customer power and related expenses at a predetermined price per kWh.

The $12.3 million, or 65.4%, decrease in our fiscal 2003 excess energy sold into the wholesale market was attributable primarily to improved forecasting methods employed by us in California and Pennsylvania, and increased customer load in Pennsylvania which resulted in less excess energy available for sale.

The $3.5 million, or 172.8%, increase in our fiscal 2003 green power credits was attributable primarily to the recognition in the current fiscal year of green power credits for the final seven months of fiscal 2002 and the first eight months of fiscal 2003 due to the reinstatement by the State of California of the Public Purpose Program to provide incentives to suppliers of renewable power to reduce the cost of such power to certain customers. This green power credit program was discontinued for periods after March 2003.

We had approximately 118,000 retail customers at July 31, 2003, an increase of 29,000, or 32.6%, from 89,000 at July 31, 2002. This increase was due primarily to the successful acquisition of approximately 40,000 customers in Pennsylvania under a bid process that was a part of an electric utility restructuring in Pennsylvania. The addition of these customers occurred in May and June 2003. Our customer count, net of the 40,000 additions in Pennsylvania, was reduced due to our focus on increasing our commercial and industrial customer base, which have much higher average electricity usage, while reducing the number of residential customers, which have lower electricity usage.

Direct energy costs which are recognized concurrent with related energy sales, include the cost of purchased electric power, fees incurred from various energy-related service providers and energy-related taxes that cannot be passed through to the customer. Our direct energy costs were $128.2 million for fiscal 2003, an increase of $40.9 million, or 46.8%, from $87.3 million for fiscal 2002. We purchased 1,207.4 million kWh at an average price per kWh of $0.043 in California during fiscal 2003, as compared to 1,184.5 million kWh at an average price per kWh of $0.034 during fiscal 2002. We purchased 1,084.5 million kWh at an average price per kWh of $0.041 in Pennsylvania during fiscal 2003, as compared to 992.9 million kWh at an average price per kWh of $0.039 during fiscal 2002. We purchased 278.0 million kilowatt-hours at an average price per kWh of $0.049 in Michigan during fiscal 2003, as compared no purchases during fiscal 2002, as this was a new market in fiscal 2003. The fiscal 2003 increase in our direct energy costs primarily was attributable to increased kWh purchases to accommodate our entry into the Michigan market and additional customers in Pennsylvania as we gained market share. To a lesser extent, the fiscal 2003 increase was attributable to higher kWh prices paid as a result of increased natural gas prices incurred by our suppliers.

Our selling and marketing expenses were $4.2 million for fiscal 2003, an increase of $0.7 million, or 20.8%, from $3.5 million for fiscal 2002. The fiscal 2003 increase was primarily attributable to increased marketing efforts associated with our expansion into the Pennsylvania and Michigan markets and further market research conducted on certain states under consideration for future expansion.

Our general and administrative expenses were $20.7 million for fiscal 2003, an increase of $2.3 million, or 12.5%, from $18.4 million for fiscal 2002. The fiscal 2003 increase was primarily attributable to increases in legal expenses incurred in connection with litigation and the proxy contest related to our last annual meeting of shareholders, merit compensation and premiums on directors and officers insurance policies, partially offset by certain cost savings achieved through the internalization of certain previously outsourced information technology capabilities. Our general and administrative expenses for fiscal 2002 were reduced by the $0.07 million reversal of previously recognized stock-based compensation.

Primarily as a result of all of the preceding factors, our income from operations increased $3.9 million, or 45.7%, to $12.4 million for fiscal 2003 from $8.5 million for fiscal 2002.

We incurred a $2.7 million loss on a litigation award during fiscal 2003, in connection with a lawsuit filed by several former employees, of which we had previously accrued $0.5 million, with the remaining $2.2 million balance recognized in fiscal 2003.

We incurred a $0.6 million aggregate loss on equity investments for fiscal 2003, as compared to a $0.2 million aggregate loss for fiscal 2002. The loss on equity investments for fiscal 2003 primarily reflects our proportionate recognition of losses under the equity method of accounting from our consolidation of Summit Energy Ventures, LLC (“Summit”); namely, the losses incurred by Power Efficiency Corporation (“PEC”) through April 30, 2003, and, to a significantly lesser extent, Turbocor BV (“Turbocor”) through January 2003. Effective May 1, 2003, we began consolidating PEC as Summit had obtained a majority ownership position in PEC. Effective February 1, 2003, because Summit’s ownership position in Turbocor had been reduced to a level at which it no longer exercised significant influence, we began accounting for Turbocor under the cost method of accounting, whereby any proportionate losses were excluded from our results of operations. In contrast, fiscal 2002 primarily reflected our proportionate recognition under the equity method of accounting, from our consolidation of Summit, of the losses incurred by Turbocor and PEC from the dates of Summit’s initial equity investments in Turbocor and PEC, in January 2002 and June 2002, respectively.

Minority interest represents that portion of PEC’s post-consolidation losses that are allocable to the non-Summit investors based on their aggregate minority ownership interest in PEC.

Our interest income, net, was $0.7 million for fiscal 2003, a decrease of $0.2 million, or 23.9%, from $0.9 million for fiscal 2002. The fiscal 2003 net decrease resulted from a $0.6 million decrease in interest income, partially offset by a $0.4 million decrease in interest expense. The fiscal 2003 decrease in interest income primarily was attributable to lower yields realized on short-term investments and, to a significantly lesser extent, lower average investment balances. The fiscal 2003 decrease in interest expense primarily was attributable to the non-recurrence of $0.4 million of fiscal 2002 interest expense incurred in connection with borrowings under our then outstanding credit facility, which was terminated in June 2002.

Our income before provision for income taxes was $10.5 million for fiscal 2003, an increase of $1.2 million, or 13.4%, from $9.3 million for fiscal 2002.

Our provision for income taxes was $5.1 million for fiscal 2003, compared to $4.1 million for fiscal 2002. Our effective income tax rate was 48.5% for fiscal 2003, compared to 44.4% for fiscal 2002. The fiscal 2003 increase in our effective income tax rate was attributable primarily to an increase due to the expiration of certain stock options in fiscal 2003, the value of which was charged to expense for financial reporting purposes but not deductible for income tax purposes, partially offset by a decrease in our valuation allowance as a result of our utilization of net operating loss carryforwards for federal income tax purposes.

Our net income was $5.4 million for fiscal 2003, an increase of $0.2 million, or 5%, from $5.2 million for fiscal 2002. Our basic and diluted net income per common share was $0.19 and $0.18, respectively, for fiscal 2003, as compared to $0.19 and $0.16, respectively, for fiscal 2002. The calculation of net income per common share gives effect to 352,000 shares of preferred stock, referenced in our financial statement as “Other convertible preferred stock” related to pending litigation. See “Item 3. Legal Proceedings” and Notes 6, 12 and 14 of the Notes to Consolidated Financial Statements for further details.

Our net revenue for fiscal 2002 was $117.8 million, a decrease $65.5 million, or 35.7%, from $183.3 million in fiscal 2001. Net energy sales were $115.7 million, or 98.3%, of our fiscal 2002 net revenue, as compared to $179.3 million, or 97.8%, of our fiscal 2001 net revenue. Green power credits recognized from the State of California accounted for the balances of our net revenue.

Energy sales to retail customers constituted $97.0 million, or 83.8%, of our net energy sales for fiscal 2002, as compared to $100.0 million, or 55.7%, for fiscal 2001. Sales of excess energy in the wholesale markets constituted $18.8 million, or 16.2%, of our net energy sales for fiscal 2002, as compared to $79.3 million, or 44.2%, for fiscal 2001. The very high level of excess energy sold in the wholesale market in fiscal 2001 was the result of the unprecedented rise in electric power prices in California. These prices already were moving toward normal levels by the fourth quarter of fiscal 2001.

We sold 775.6 million kWh at an average retail price per kWh of $0.085 in California during fiscal 2002, as compared to 563.4 million kWh sold at an average retail price per kWh of $0.145 during fiscal 2001. We sold 468.9 million kWh at an average retail price per kWh of $0.058 in Pennsylvania during fiscal 2002, as compared to 378.6 million kWh sold at an average retail price per kWh of $0.050 during fiscal 2001.

The $3.0 million, or 3.0%, decrease in our fiscal 2002 retail energy sales was attributable primarily to the price decrease realized in California, being substantially offset by the volume increases realized in California and Pennsylvania, and, to a lesser extent, the price increase realized in Pennsylvania. The average retail price per kWh realized in California during fiscal 2002 was representative of normal average price whereas the inflated average retail price realized in California during fiscal 2001 reflected the statewide energy crisis. The volume increases realized were attributable to increases in the number of commercial customers in California and Pennsylvania since October 2001 and June 2002, respectively. The price increase realized in Pennsylvania was primarily due to more energy purchased under fixed price contracts in fiscal 2002 compared to fiscal 2001.

We sold 313.8 million kWh of excess power into the wholesale markets at an average price per kWh of $0.023 in California during fiscal 2002, as compared to 404.7 million kWh sold at an average retail price per kWh of $0.17 during fiscal 2001. We sold 463.2 million kWh at an average wholesale price per kWh of $0.025 in Pennsylvania during fiscal 2002, as compared to 268.3 million kWh sold at an average wholesale price per kWh of $0.032 during fiscal 2001.

The $60.5 million, or 76.3%, decrease in our fiscal 2002 excess energy sold in the wholesale markets primarily was attributable to the price decrease realized in California, and, to a significantly lesser extent, the price decrease realized in Pennsylvania and the volume decrease realized in California. Slightly offsetting the preceding results was the volume increase realized in Pennsylvania. The volume decrease realized in California was attributable primarily to us having lower excess balances available for sale in the wholesale market as a result of our growing retail customer base. The volume increase realized in Pennsylvania was attributable primarily to excess balances being available for sale in the wholesale market as a result of decreased retail demand due to more moderate late summer and winter temperatures than forecast.

The $1.9 million, or 48.5%, decrease in our fiscal 2002 green power credits primarily was attributable to the expiration of the State of California’s green power credit program in December 2001. The California legislature subsequently approved reinstating the green power credit program, however, due to program uncertainty, no revenue from periods subsequent to January 1, 2002 were reflected in fiscal 2002 revenue.

We had approximately 89,000 retail customers at July 31, 2002, an increase of 1,000, or 1.1%, from 88,000 at July 31, 2001.

Our direct energy costs were $87.3 million for fiscal 2002, an increase of $10.0 million, or 13.0%, from $77.3 million for fiscal 2001. We purchased 1,184.5 million kWh at an average price per kWh of $0.034 in California during fiscal 2002, as compared to 980.1 million kWh sold at an average price per kWh of $0.039 during fiscal 2001. We purchased 992.9 million kWh at an average price per kWh of $0.039 in Pennsylvania during fiscal 2002, as compared to 662.5 million kWh sold at an average price per kWh of $0.040 during fiscal 2001.

The fiscal 2002 increase in our direct energy costs primarily was attributable to volume increases in Pennsylvania, and, to a lesser extent, in California, partially offset by the price decrease realized in California. Our increased purchases in California and Pennsylvania were to accommodate added retail customers. The price decrease realized in California primarily was attributable to normalizing energy prices after the energy crisis in fiscal 2001.

Our selling and marketing expenses were $3.5 million for fiscal 2002, a decrease of $0.1 million, or 2.4%, from $3.6 million for fiscal 2001. The fiscal 2002 decrease primarily was attributable to a decrease realized in our payroll expenses, being partially offset by an increase incurred in our consulting expenses. The decrease in our payroll expenses was primarily the result of call center personnel attrition. The increase in our consulting expenses was the result of market research conducted on certain states under consideration for future service expansion.

Our general and administrative expenses were $18.4 million for fiscal 2002, a decrease of $3.2 million, or 14.8%, from $21.6 million for fiscal 2001. The fiscal 2002 decrease primarily was attributable to a $1.8 million variation in stock-based compensation, from a $1.1 million charge in fiscal 2001 to a $0.7 million credit in fiscal 2002. The fiscal 2002 credit resulted from our reversing of a portion of our fiscal 2001 charge due to a subsequent decrease in the value of our common stock against which the value of certain unvested variable stock options are continually reassessed. The balance of the fiscal 2002

decrease primarily was attributable to lower legal, consulting and bad debt expenses, being partially offset by higher payroll and amortization expenses as well as management fees incurred for Summit. The decrease realized in legal expenses for fiscal 2002 primarily was attributable to fiscal 2001 reflecting non-recurring legal costs associated with a dispute settlement reached with our founder. The increase realized in payroll expenses primarily was due to the hiring of software development employees who were formerly engaged as consultants. The increase realized in amortization expense primarily was attributable to previously capitalized software development costs incurred for our TRIUMPH system. The management fees incurred for Summit constitute a new expense in fiscal 2002 that we anticipate will be recurring for the foreseeable future.

Primarily as a result of the preceding factors, our income from operations decreased by $72.3 million, or 89.5%, to $8.5 million for fiscal 2002, from $80.8 million for fiscal 2001.

We incurred a $0.2 million aggregate loss on equity investments for fiscal 2002 as a result of our consolidation of Summit. This loss primarily reflects our proportionate recognition under the equity method of accounting of the losses incurred by Turbocor and PEC from the dates of Summit’s initial equity investments in them during January 2002 and June 2002, respectively.

Our interest income, net, was $0.9 million for fiscal 2002, a decrease of $0.7 million, or 41.0%, from $1.6 million for fiscal 2001. The fiscal 2002 net decrease resulted from a $1.0 million decrease in interest income, partially offset by a $0.4 million decrease in interest expense. The decrease in interest income primarily was attributable to significantly lower average interest rates realized on slightly lower average investment balances. The decrease in interest expense was attributable primarily to lower average outstanding borrowings as a result of our repayment and termination of a line of credit borrowing facility in June 2002.

Our income before provision for income taxes was $9.3 million for fiscal 2002, a decrease of $73.1 million, or 88.7%, from $82.4 million for fiscal 2001.

Our provision for income taxes was $4.1 million for fiscal 2002, a decrease of $17.8 million, or 81.1%, from $21.9 million for fiscal 2001. Our effective income tax rate was 44.4% for fiscal 2002, as compared to 26.6% for fiscal 2001. The fiscal 2002 increase in our effective income tax rate was attributable primarily to the comparative fiscal 2001 period reflecting the favorable impact of our release of our valuation allowance as a result of our utilization of net operating loss carryforwards for federal and state income tax purposes in fiscal 2001 due to our first year of profitability.

Our net income was $5.2 million for fiscal 2002, a decrease of $55.3 million, or 91.5%, from $60.5 million for fiscal 2001. Our basic and diluted net income per common share was $0.19 and $0.16, respectively, for fiscal 2002, as compared to $2.06 and $1.77, respectively, for fiscal 2001.

In recent fiscal years, we have sustained our operations and funded our growth substantially with internally generated cash flows from operations. Based on our planned operations and growth expectations for the foreseeable future, we currently do not anticipate requiring any external sources of financing through at least fiscal 2004, if not beyond.

Our unrestricted cash and cash equivalents decreased by $2.1 million, or 4.9%, to $40.9 at July 31, 2003, as compared with $43.0 million at July 31, 2002. Our working capital decreased by $2.4 million, or 4.1%, to $56.4 million at July 31, 2003, from $58.8 million at July 31, 2002. Our current ratios, which are defined as current assets divided by current liabilities, were 2.76 and 5.43 at July 31, 2003 and 2002, respectively.

With our favorable liquidity position, we elected to allow our previously existing $10.0 million line of credit borrowing facility to expire on June 29, 2002. We currently do not have any established credit facilities in place for future borrowings. We believe that we would be able to establish credit facilities at acceptable rates and terms in the future should it be necessary; although we currently see no need for such facilities through at least fiscal 2004.

Our operating activities provided $5.6 million in cash and cash equivalents during fiscal 2003, an increase of $2.1 million, or 61.6%, from $3.5 million in cash and cash equivalents provided during fiscal 2002. The fiscal 2003 increase primarily reflects the $0.2 million increase in our net income and the positive cash flow effects of increased accounts payable and accrued liabilities. Partially offsetting the increase in cash and cash equivalents was the negative cash flow effects of increased accounts receivable and prepaid expenses and other assets, and the adding back of lower non-cash charges.

Our investing activities utilized $1.5 million in cash and cash equivalents during fiscal 2003, as compared to $9.2 million in cash and cash equivalents utilized during fiscal 2002. The fiscal 2003 decrease principally is attributable to the comparable fiscal 2002 period reflecting substantive initial investments in energy-related companies made through Summit. To a significantly lesser extent, the fiscal 2003 decrease reflects decreased purchases for property and equipment offset by the acquisition of a majority ownership in PEC.

Our financing activities utilized $6.2 million in cash and cash equivalents during fiscal 2003, as compared to $7.7 million in cash and cash equivalents provided by financing activities during fiscal 2002. Financing activities in fiscal 2003 principally reflects the negative cash flow effect of an aggregate increase in our restricted cash and cash equivalents as a result of the letters of credit required in connection with energy purchase agreements and a litigation appeal bond. In contrast, financing activities in fiscal 2002 principally reflected the positive cash flow effect of an aggregate decrease in our restricted cash and cash equivalents as a result of the release of letters of credit upon the expiration of energy purchase agreements and the deployment of cash by Summit into investments in energy-related companies. Partially offsetting this positive cash flow effect in fiscal 2002 were principal repayments of borrowings outstanding under our then existing line of credit facility and repurchases of outstanding common shares.

Our operating activities provided $3.5 million in cash and cash equivalents during fiscal 2002, a decrease of $58.4 million, or 94.4%, from the $61.8 million in cash and cash equivalents provided during fiscal 2001. The fiscal 2002 decrease reflects principally the $55.4 million decrease in our net income. To a

significantly lesser extent, the fiscal 2002 decrease reflects primarily the negative cash flow effects of decreased accounts payable and other current liabilities and increased accounts receivable. Slightly offsetting this decreased was the adding back of increased aggregate non-cash charges.

Our investing activities utilized $9.2 million and $1.2 million in cash and cash equivalents during fiscal 2002 and 2001, respectively. The fiscal 2002 increase primarily reflects substantive initial investments in energy-related companies made through Summit, and, to a significantly lesser extent, increased purchases of property and equipment.

Our financing activities provided $7.7 million in cash and cash equivalents during fiscal 2002, as compared to $23.8 million in cash and cash equivalents utilized by financing activities during fiscal 2001. Financing activities in fiscal 2002 reflected primarily the positive cash flow effect of an aggregate decrease in our restricted cash and cash equivalents as a result of the release of letters of credit upon the expiration of energy purchase agreements and the decrease in Summit’s cash account as a result of their investments during the year, partially offset by the negative cash flow effects of principal repayments of borrowings outstanding under our then existing line of credit facility and repurchases of outstanding common shares held by our founder. Financing activities in fiscal 2001 principally reflected the negative cash flow effect of an aggregate increase in our restricted cash and cash equivalents as a result of our investment in Summit Energy Ventures, and, to a significantly lesser extent, principal repayments of borrowings outstanding our then existing line of credit facility.

As a result of the foregoing, our unrestricted cash and cash equivalents increased by $1.9 million to $43.0 million at July 31, 2002 as compared with $41.1 million at July 31, 2001.

Our planned capital expenditures for the fiscal year ending July 31, 2004 (“fiscal 2004”)are $1.7 million. Planned capital expenditures include computer hardware and software, office equipment and furniture. The expenditures are expected to be pro rata throughout the year and funded out of working capital.

We currently are party to a number of supply contracts requiring us to purchase electrical power covering approximately 81% of the current load servicing requirements. As these contracts contain fixed prices at which we will be required to make such purchases, our future results of operations for the fiscal periods covered by these contracts will be significantly influenced by our then ability to resell this purchased electrical power to our customers at prices sufficient to cover our direct and indirect costs and to realize a profit.

Our most significant operating leases pertain to our corporate facilities. All of our other operating leases pertain to various equipment and technology. Certain of these operating leases are noncancellable and contain rent escalation clauses relating to increases to real property taxes and maintenance costs. We incurred aggregate rent expense under operating leases of $697,000, $704,000, and $742,000 during fiscal 2001, 2002 and 2003, respectively.

We have five executive employment agreements in existence at July 31, 2003 that commit us to pay future base salaries. Under these agreements we may also be required to pay bonuses in the event of a change of control and/or upon early termination of employment. For a description of the change of control and severance bonuses with respect to our Named Executive Officers, see “Item 11. Executive Compensation — Employment Agreements.”

Demand for electrical power is continually influenced, both positively and negatively, by prevailing weather conditions. To the extent that one or more of our markets experiences a prolonged period of unseasonal weather, we will be required to either attempt to procure additional electricity to service our customers or to sell surplus electricity in the open market.

Accounting policies discussed below are those that we consider to be critical to an understanding of our financial statements because their application places the most significant demands on our ability to judge the effect of inherently uncertain matters on our financial results. For all of these policies, we caution that future events rarely develop exactly as forecast, and the best estimates routinely require adjustment.


	•	Independent system operator costs — Included in direct energy costs along with electric power purchased and scheduling coordination costs are the independent system operator (“ISO”) fees. The actual ISO costs are not finalized until a settlement process by the ISO is performed of each day’s activities of all grid participants. Prior to the completion of settlement, we estimate these costs based on historical trends and preliminary settlement information. The historical trends and preliminary information may differ from actual fees resulting in the need to adjust the related costs.

	•	Allowance for doubtful accounts — We maintain allowances for doubtful accounts for estimated losses resulting from non-payment of customer billings. If the financial condition of our customers were to deteriorate, resulting in an impairment of their ability to make payments, additional allowances may be required. In addition, as a result of market conditions in California during fiscal 2001, the creditworthiness of several participants in the marketplace with whom we conduct business has deteriorated significantly. For example, PG&E, which declared bankruptcy, has withheld payments of approximately $1.1 million from their remittances to us. Although we have filed a Proof of Claim in PG&E’s bankruptcy proceedings to recover these amounts, we have established an allowance for doubtful accounts in the amount of these withholdings. If other utilities declare bankruptcy, additional allowances may be required.

	•	Unbilled receivables — Our customers are billed monthly at various dates throughout the month. Unbilled receivables represent the amount of electric power delivered to customers at the end of a period, but not yet billed. Unbilled receivables from sales are estimated by us as the number of kilowatt-hours delivered to the customer times the average current customer sales price per kilowatt-hour.

	•	Legal claims — From time to time, we may be involved in litigation relating to claims arising out of our operations in the normal course of business. We regularly evaluate our exposure to threatened or pending litigation and other business contingencies and accrue for estimated losses on such matters in accordance with Statement of Financial Accounting Standards No. 5, “Accounting for Contingencies.” As a result, we have accrued a total of $2.7 million as of July 31, 2003, for a loss on litigation award in connection with an action brought by former employees. As additional


		information about current or future litigation or other contingencies becomes available, management will assess whether such information warrants the recording of additional expense relating to our contingencies. Such additional expense could potentially have a material impact on our results of operations and financial position. See “Item 3. Legal Proceedings” of this annual report on Form 10-K for a description of our pending legal proceedings.

If competitive restructuring of the electric markets is delayed or does not result in viable competitive market rules, our business will be adversely affected.

The Federal Energy Regulatory Commission (“FERC”) has maintained a strong commitment over the past seven years to the deregulation of electricity markets. This movement would seem to indicate the continuation and growth of a competitive electric retail industry. As of February 2003, 24 states and the District of Columbia have either enacted enabling legislation or issued a regulatory order to implement retail access. In 18 of these states, retail access is either currently available to some or all customers, or will soon be available. However, in many of these markets the market rules adopted have not resulted in energy service providers being able to compete successfully with the incumbent utilities and customer switching rates have been low. Only recently have a small number of markets opened to competition under rules that we believe may offer attractive competitive opportunities. Our business model depends on other favorable markets opening under viable competitive rules in a timely manner. In any particular market, there are a number of rules that will ultimately determine the attractiveness of any market. Markets that we enter may have both favorable and unfavorable rules. If the trend towards competitive restructuring of retail energy markets does not continue or is delayed or reversed, our business prospects and financial condition could be materially adversely impaired.

Retail energy market restructuring has been and will continue to be a complicated regulatory process, with competing interests advanced not only by relevant state and federal utility regulators, but also by state legislators, federal legislators, incumbent utilities, consumer advocacy groups and potential market participants. As a result, the extent to which there are legitimate competitive opportunities for alternative energy suppliers in a given jurisdiction may vary widely and we cannot assure shareholders that regulatory structures will offer us competitive opportunities to sell energy to consumers on a profitable basis. The regulatory process could be negatively impacted by a number of factors, including interruptions of service and significant or rapid price increases. The legislative and regulatory processes in some states take prolonged periods. In a number of jurisdictions, it may be many years from the date legislation is enacted until the retail markets are open for competition.

In addition, although most retail energy market restructuring has been conducted at the state and local levels, bills have been proposed in Congress in the past that would preempt state law concerning the restructuring of the retail energy markets. Although none of these initiatives has been successful, we cannot assure shareholders that federal legislation will not be passed in the future that could materially adversely affect our business.

We face many uncertainties that may cause substantial operating losses and we cannot assure shareholders that we will continue to be profitable.

We have recognized significant revenue and our ability to generate such revenue is subject to uncertainty. In addition, we intend to increase our operating expenses to develop our business, including brand development, marketing and other promotional activities and the continued development of our billing, customer care and power procurement infrastructure. Our ability to sustain profitability will depend on, among other things:


	•	Our ability to attract and to retain a critical mass of customers at a reasonable cost;

	•	Our ability to develop internal corporate organization and systems;


	•	The continued competitive restructuring of retail energy markets with viable competitive market rules; and

	•	Our ability to manage effectively our energy requirements and to sell our energy at a sufficient margin.

We anticipate that we will incur significant costs as we enter new markets and pursue customers by utilizing a variety of marketing methods. In order for us to recover these expenses, we must attract and retain a large number of customers to our service.

We may experience difficulty attracting customers because many customers may be reluctant to switch to a new company for the supply of a commodity as critical to their well-being as electric power. A major focus of our marketing efforts will be to convince customers that we are a reliable provider with sufficient resources to meet our commitments. If our marketing strategy is not successful, our business, results of operations, and financial condition will be materially adversely affected.

We depend upon internally developed systems and processes to provide several critical functions for our business, and the loss of these functions could materially adversely impact our business.

We have developed our own systems and processes to operate our back-office functions, including customer enrollment, metering, forecasting, settlement and billing. Problems that arise with the performance of our back-office functions could result in increased expenditures, delays in the launch of our commercial operations into new markets, or unfavorable customer experiences that could materially adversely affect our business strategy. Also, any interruption of these services could be disruptive to our business.

Substantial fluctuations in electricity prices or the cost of transmitting and distributing electricity could have a material adverse affect on us.

To provide electricity to our customers, we must, from time to time, purchase electricity in the short-term or “spot” wholesale energy markets, which can be highly volatile. In particular, the wholesale electric power market can experience large price fluctuations during peak load periods. Furthermore, to the extent that we enter into contracts with customers that require us to provide electricity at a fixed price over an extended period of time, and to the extent that we have not purchased electricity to cover those commitments, we may incur losses caused by rising wholesale electricity prices. Periods of rising electricity prices may reduce our ability to compete with incumbent utilities because their regulated rates may not immediately increase to reflect these increased costs. Energy Service Providers like us take on the risk of purchasing power for an uncertain load and if the load does not materialize it leaves us in a “long” position that would be resold into the wholesale electricity market. Sales of this surplus electricity may be at prices below our cost. Or, if unanticipated load appears that may result in an insufficient supply of electricity, we would need to purchase the additional supply. These purchases could be at prices that are higher than our sales price to our customers. Either situation could create losses for us as we are exposed to the price volatility of the wholesale spot markets. Any of these contingencies could substantially increase our costs of operation. Such factors could have a material adverse effect on our financial condition.

We are dependent on local utilities for distribution of electricity to our customers over their distribution networks. If these local utilities are unable to properly operate their distribution networks, or if the operation of their distribution networks is interrupted for periods of time, we will be unable to deliver electricity to our customers during those interruptions. This would results in lost revenue to us, which would adversely impact the results of our operations.

Historical procurement charges and customer rate changes in the Southern California Edison utility district could adversely affect our revenue and cash flows.

Under a Settlement agreement with the California Public Utility Commission (“CPUC”), Southern California Edison (“SCE”) was authorized to recoup $3.6 billion in debt incurred during the energy crisis of 2000-2001 from all customers. This debt was to be collected under the Procurement Related Obligations Account (“PROACT”) from bundled (non direct access) customers and under the Historical Procurement Charge (“HPC”) from direct access (“DA”) customers.

In July 2002, the CPUC issued an interim order implementing the HPC sought by SCE. This interim order authorized SCE to collect $391 million in HPC charges from all DA customers by reducing their Procured Energy Credit (“PE Credit”) by $0.027 per kWh beginning July 27, 2002. The lowered PE Credit continued until an exit fee for DA customers was approved by the CPUC. Effective January 1, 2003, it was reduced to $0.01 per kWh. For the fiscal year ended July 31, 2003, we estimate that HPC charges have impacted our sales and pretax earnings by a range of $4.8 million to $6.0 million. We are unable to precisely determine the actual HPC charges applied to our customers by SCE because there are different charges, by customer type, and this charge is only on the electricity usage above the monthly baseline usage allocation.

On September 5, 2003 the CPUC issued Decision 03-09-016 granting SCE’s request to recover additional shortfall and authorizing the HPC balance to be revised to $473 million; however, the $0.01 per kWh monthly charge remained in place. As of August 1, 2003, SCE revised its billing methodology to a “bottoms-up” design effectively doing away with the PE Credit and the net effect of the HPC on our rates. While the HPC no longer impacts our rate calculations going forward, a recent SCE rate reduction includes the impact of the HPC. This rate reduction will impact sales and pretax profit in the SCE district. The rate reduction will be in place in 2004 and will approximate the effect of the HPC dollar impact of 2003.

Recently, SCE acknowledged that the PROACT debt was paid in full by bundled customers at the end of July 2003. As a result, on August 1, 2003, all SCE rates were lowered. As a direct result, to retain our customers in the SCE utility district, we lowered our customer rates proportionately. Our estimate of the annual financial impact of this rate reduction is a decline in sales and pretax profit during fiscal 2004, in the range of $3.0 to $3.5 million. This reduction is separate from, but in addition to, the HPC reduction seen in 2003.

These changes on our customers in the SCE district will continue to cause a significant impact on our revenue and cash flow; however, we do not expect that it will preclude us from participating in the California market.

Some suppliers of electricity have been experiencing deteriorating credit quality.

We continue to actively manage our counterparty credit portfolio to attempt to reduce the impact of a potential counterparty default. As of July 31, 2003, the majority of our courterparties are rated investment grade or above by the major rating agencies. These ratings are subject to change at any time and with no advance warning. This situation could have an adverse impact on the source of our electricity purchases.

If the wholesale price of electricity decreases, we may be required to post letters of credit to secure our obligations under our long term energy contracts.

Since the price of the electricity we purchase under long-term contracts is fixed over the term of the contracts, if the market price of wholesale electricity decreases below the contract price, the power generator may require us to post security in the form of a letter of credit to hedge against our potential default on the contract. If we are required to post such security, a portion of our cash would become restricted, which could adversely affect our liquidity.

We are required to rely on utilities with whom we will be competing to perform some functions for our customers.

Under the regulatory structures adopted in most jurisdictions, we will be required to enter into agreements with local incumbent utilities for use of the local distribution systems, and for the creation and operation of functional interfaces necessary for us to serve our customers. Any delay in these negotiations or our inability to enter into reasonable agreements with those utilities could delay or negatively impact our ability to serve customers in those jurisdictions. This could have a material negative impact on our business, results of operations and financial condition.

We are dependent on local utilities for maintenance of the infrastructure through which electricity is delivered to our customers. We are limited in our ability to control the level of service the utilities provide to our customers. Any infrastructure failure that interrupts or impairs delivery of electricity to our customers could have a negative effect on the satisfaction of our customers with our service, which could have a material adverse effect on our business.

Regulations in many markets require that the services of reading our customers’ energy meters and the billing and collection process be retained by the local utility. In those states, we will be required to rely on the local utility to provide us with our customers’ energy usage data and to pay us for our customers’ usage based on what the local utility collects from our customers. We may be limited in our ability to confirm the accuracy of the information provided by the local utility and we may not be able to control when we receive payment from the local utility. The local utility’s systems and procedures may limit or slow down our ability to create a supplier relationship with our customers that would delay the timing of when we can begin to provide electricity to our new customers. If we do not receive payments from the local utility on a timely basis, our working capital may be impaired.

In some markets, we are required to bear credit risk and billing responsibility for our customers.

In some markets, we are responsible for the billing and collection functions for our customers. In these markets, we may be limited in our ability to terminate service to customers who are delinquent in payment. Even if we terminate service to customers who fail to pay their utility bill in a timely manner, we may remain liable to our suppliers of electricity for the cost of the electricity and to the local utilities for services related to the transmission and distribution of electricity to those customers. The failure of our customers to pay their bills in a timely manner or our failure to maintain adequate billing and collection programs could materially adversely affect our business.

In some markets, our principal competitor may be the local incumbent utility company or unregulated utility affiliates. The incumbent utilities have the advantage of long-standing relationships with their customers and they may have longer operating histories, greater financial and other resources and greater name recognition in their markets than we do. In addition, incumbent utilities have been subject to regulatory oversight and thus have a significant amount of experience regarding the regulators’ policy preferences as well as a critical economic interest in the outcome of proceedings concerning their revenues and terms and conditions of service. Incumbent utilities may seek to decrease their tariffed retail rates to limit or to preclude the opportunities for competitive energy suppliers and otherwise seek to establish rates, terms and conditions to the disadvantage of competitive energy suppliers.

Some of our competitors, including incumbent utilities, have formed alliances and joint ventures in order to compete in the restructured retail electricity industry. Many customers of these incumbent utilities may decide to stay with their long-time energy provider if they have been satisfied with their service in the past. Therefore, it may be difficult for us to compete against incumbent utilities and their affiliates for customers who are satisfied with their historical utility provider.

In addition to competition from the incumbent utilities and their affiliates, we may face competition from a number of other energy service providers, and other energy industry participants who may develop

businesses that will compete with us in both local and national markets. We also may face competition from other nationally branded providers of consumer products and services. Some of these competitors or potential competitors may be larger and better capitalized than us.

Our revenues and results of operations are subject to market risks that are beyond our control.

We sell electricity that we purchase from third-party power generation companies to our retail customers on a contractual basis. We are not guaranteed any rate of return through mandated rates, and our revenues and results of operations are likely to depend, in large part, upon prevailing market prices for electricity in our regional markets and other competitive markets. These market prices may fluctuate substantially over relatively short periods of time. These factors could have an adverse impact on our revenues and results of operations.

Volatility in market prices for electricity results from multiple factors, including:


	•	weather conditions,

	•	seasonality,

	•	unexpected changes in customer usage,

	•	transmission or transportation constraints or inefficiencies,

	•	demand for electricity,

	•	natural gas, crude oil and refined products, and coal supply availability to generators from whom we purchase electricity,

	•	natural disasters, wars, embargoes and other catastrophic events, and

	•	federal, state and foreign energy and environmental regulation and legislation.

Our results of operation and financial condition could be affected by pending and future litigation.

We are currently a defendant in several pending lawsuits. We believe our substantive and procedural defenses in each of these cases are meritorious, but we cannot predict the outcome of any such litigation. In addition, we may become subject to additional lawsuits in the future. If we are held liable for significant damages in any lawsuit, our operations and financial condition may be harmed. In addition, we could incur substantial expenses in connection with any such litigation, including substantial fees for attorneys and other professional advisors. These expenses could adversely affect our operations and cash position if they are material in amount. See “Item 3. Legal Proceedings” for a description of our current material legal proceedings.

We do not have or use any derivative instruments to hedge the financial risks of our investments, nor do we have any plans to enter into such instruments. We generally invest cash equivalents in high-quality, short-term credit instruments consisting primarily of high credit quality money market funds, bankers acceptance notes and government agency securities with maturities of 90 days or less. We do not expect any material loss from our investments and, therefore, believe that our potential interest rate exposure is not material. We do not currently invoice customers in any currency other than the United States dollar and we do not currently incur significant expenses denominated in foreign currencies. Accordingly, we believe that we are not currently subject to significant risk as a result of currency fluctuations.

Since we do not generate any of the electricity that we sell, our business has exposure to market volatility in prices of electricity. To mitigate risks associated with this price volatility, we have entered into a number of fixed-priced contracts for the purchase of electricity through the wholesale electricity market. Nevertheless, to the extent demand from our customers exceeds the supply we have obtained through fixed-price contracts, we are subject to wholesale price volatility risk.

An electricity price change of per $0.01 kWh, has an estimated annual impact on our net revenue of:

As of July 31, 2003, we have not used derivative instruments to hedge any of our exposure to changes in forward electricity prices. Beginning in fiscal 2004, we may open a brokerage account with a futures commission merchant that would allow us to utilize exchange traded futures contracts on electricity as part of our overall strategy with respect to hedging our forward price risk exposure.

Because all of our energy sales and purchases, and substantially all of our other purchases, are transacted or denominated in United States dollars, we currently are not materially susceptible to currency market risks.

Since we had no short or long-term debt outstanding at July 31, 2003, our only exposure to interest rate risks is limited to our investment of excess cash balances in interest-bearing instruments. However, as our practice has been, and currently continues to be, to only invest in high-quality debt instruments with maturities of 90 days or less, we currently are not materially susceptible to interest rate risks.

The financial statement information, including the report of independent auditors, required by this Item 8 is set forth on pages F-1 to F-28 of this annual report on Form 10-K and is hereby incorporated into this Item 8 by reference. The Quarterly Financial Information required by this Item 8 is set forth on page F-28 of this annual report on Form 10-K and is hereby incorporated into this Item 8 by reference.

Our Chairman and Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended) as of the end of the period covered by this annual report on Form 10-K and, based on this evaluation, have concluded that the disclosure controls and procedures are effective.

There have been no changes in our internal control over financial reporting that occurred during our fourth fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

The following table sets forth information regarding our directors, including their age as of October 15, 2003, and business experience during the past five years. Each of our directors has served continuously as one of our directors since the date indicated in his or her biography below, and each is currently serving a one year term expiring at our next annual meeting or until his or her respective successor is elected and qualified.

Our Board of Directors has determined that Robert C. Perkins, who serves as Chairman of the Audit Committee of our Board of Directors, is an Audit Committee Financial Expert. Mr. Perkins is independent, as the term is defined in Section 121(A) of the listing standards of the American Stock Exchange.

Information regarding our executive officers is included in Item 1A of Part I of this annual report on Form 10-K under the caption “Executive Officers of the Registrant,” and is incorporated herein by reference.

Section 16(a) of the Exchange Act requires our directors and executive officers, and persons who beneficially own more than 10% of a registered class of our equity securities, to file with the Securities and Exchange Commission, or the SEC, initial reports of ownership and reports of changes in ownership of our common stock and other equity securities. Officers, directors and greater than 10% shareholders are required by SEC regulations to furnish us with copies of all Section 16(a) forms they file.

To our knowledge, based solely on review of the copies of such reports furnished to us and written representations that no other reports were required during fiscal 2003, and except as disclosed in the following paragraph, our officers, directors and greater-than-ten-percent beneficial owners complied with all Section 16(a) filing requirements during fiscal 2003.

The following persons made late filings of reports under Section 16(a) of the Exchange Act that related to transactions that occurred during fiscal 2003: (a) Mark S. Juergensen, one of our directors, filed a late Form 3 in connection with his initial appointment as a director; (b) Linda Guckert, one of our executive officers, filed a late Form 3 in connection with her initial appointment as a director; and (c) Michael G. Nelson, one of our executive officers, filed a late Form 3 in connection with his initial appointment as an executive officer. In addition, to our knowledge, Joseph P. Saline, Jr., one of our

We have adopted a code of ethics, entitled the “Commonwealth Energy Corporation Code of Business Conduct,” which applies to, among others, our senior officers, including our Chief Executive Officer, our Chief Financial Officer, and our Corporate Controller. A copy of the Commonwealth Energy Corporation Code of Business Conduct is filed as an exhibit to this annual report on Form 10-K. We intend to disclose amendments to or waivers from a required provision of the Commonwealth Energy Corporation Code of Business Conduct by including such information as an exhibit in future filings.

Directors who also are our employees are not paid any fees or remuneration, as such, for their service on the Board of Directors or on any Board committee.

Cash Compensation. During fiscal 2003, each non-employee director was paid a quarterly retainer in the amount of $6,250 and a fee of $500 for each Board meeting which the Board member attends. Directors who served on Board committees (other than the chairman of such committee) were paid $300 for each committee meeting the Board member attends. Committee chairpersons were paid $500 for each committee meeting the chairperson attended.

For fiscal 2004, each non-employee director will be paid a quarterly retainer in the amount of $8,000, a fee of $1,000 for each Board meeting which the Board member attends in person and a fee of $750 for each Board meeting which the Board member attends telephonically. Directors who served on Board committees (other than the chairman of such committee) will be paid $750 for each committee meeting the Board member attends in person and a fee of $500 for each Committee meeting which the Board member attends telephonically. Committee chairpersons will be paid $1,000 for each committee meeting the chairperson attends, whether in person or telephonically. In addition, each non-employee director who resides outside the Southern California area, as defined in the policy, will be entitled to receive reimbursement for reasonable travel expenses in accordance with our travel expense policy.

Stock Options. Each non-employee director is eligible to receive awards under our 1999 Equity Incentive Plan, which we refer to as the Plan, a discretionary stock option plan. We did not grant any stock options to our directors under the Plan in fiscal 2003.

In connection with their service on our Board, we agreed to issue certain stock options to Mr. Perkins, Ms. Jonas, Mr. Goodman and Mr. Juergensen. In August 2003, in fulfillment of these agreements, we granted the following stock options to these directors:

Beginning in fiscal 2004, each non-employee director who first becomes a member of the Board will be granted an option to purchase 50,000 shares of our common stock pursuant to the Plan upon appointment or election to the Board, with the following terms and conditions: (a) the options shall be subject to all terms and conditions of the Plan; (b) the options shall vest quarterly at a rate of 12,500 shares on each three-month anniversary of the date of grant, with any unvested shares being forfeited to us if the Board member’s service is terminated; (c) the options shall have a term of 10 years from the date of grant; and (d) the exercise price shall be the fair market value (as defined in the Plan) of the our common stock on the date of grant.

In addition, each non-employee member of the Board will be granted an option purchase 50,000 shares of our common stock pursuant to the Plan, effective as of the close of business on the date of each annual meeting of shareholders at which such non-employee Director is elected a non-employee Director, with the following terms and conditions: (a) the options shall be subject to all terms and conditions of the Plan; (b) the options shall vest quarterly at a rate of 12,500 shares on each three-month anniversary of the date of grant, with any unvested shares being forfeited to us if the Board member’s service is terminated; (c) the options shall have a term of 10 years from the date of grant; and (d) the exercise price shall be the fair market value (as defined in the Plan) of our common stock on the date of grant.

No stock option grants were made to Joseph P. Saline, Jr., one of our non-employee directors, and no stock option grants will be made to Mr. Saline with respect to the above-referenced fiscal 2004 stock option resolution by the Board, in accordance with the order of the Honorable James M. Brooks of the Superior Court of the State of California for the County of Orange.

We recently entered into a Settlement Agreement and Release with Robert C. Perkins, one of our directors, with respect to a dispute between us and Perkins as to the number and terms of certain options to purchase shares of our common stock that had been promised to Mr. Perkins in 1999, 2001 and 2002. Pursuant to the settlement agreement and release, we granted Mr. Perkins (a) an option to purchase 80,000 shares of our common stock at an exercise price of $1.00 per share; and (b) an option to purchase 20,000 shares of our common stock at an exercise price of $1.86 per share. In exchange, Mr. Perkins released all claims he may have had against us with respect to the past promises to grant options.

We are required by the SEC to disclose compensation paid by us during the last three fiscal years to (a) our Chief Executive Officer; (b) our four most highly compensated executive officers, other than the Chief Executive Officer, who were serving as executive officers at the end of fiscal 2003; and (c) up to two additional individuals for whom such disclosure would have been provided under clause (a) and (b) above but for the fact that the individual was not serving as an executive officer of us at the end of fiscal 2003; provided, however, that no disclosure need be provided for any executive officer, other than the Chief Executive Officer, whose total annual salary and bonus does not exceed $100,000. Accordingly, we are disclosing information regarding compensation paid by us during the last three fiscal years to (a) Ian B. Carter, our Chief Executive Officer; and (b) Richard L. Paulsen, James L. Oliver, John A. Barthrop and Linda Guckert, the four most highly-compensated executive officers, other than the Chief Executive Officer, who were serving as executive officers at the end of fiscal 2003 and whose salary and bonus exceeded $100,000. All of these officers are referred to in this Annual Report as the “Named Executive Officers.”

The following table sets forth for each of the past three fiscal years, all compensation received for services rendered in all capacities by the Named Executive Officers.


(1)	Bonus compensation is determined pursuant to employment agreements and/or by the Compensation Committee and is generally based upon performance measured on a calendar year basis.

(2)	For Mr. Carter, the amount attributable to perquisites in fiscal 2003 consists of an automobile allowance of $15,600, and reimbursement for medical expenses of $15,502. The amount attributable to perquisites in fiscal 2002 consists of an automobile allowance of $15,600, and reimbursement for medical expenses (including gross up payments to pay income taxes on reimbursements) of $46,953. The amount attributable to perquisites in fiscal 2001 consists of an automobile allowance of $15,600, and reimbursement for medical expenses (including gross up payments to pay income taxes on reimbursements) of $20,641.

(3)	For Mr. Paulsen, the amount attributable to perquisites in fiscal 2003 consists of an automobile allowance of $8,800, and reimbursement for medical expenses of $15,023. The amount attributable to perquisites in fiscal 2002 consists of an automobile allowance of $9,600, and reimbursement for medical expenses (including gross up payments to pay income taxes on reimbursements) of $12,446. The amount attributable to perquisites in fiscal 2001 consists of an automobile allowance of $2,865, and reimbursement for medical expenses (including gross up payments to pay income taxes on reimbursements) of $2,792.

(4)	For Mr. Barthrop, the amount attributable to perquisites in fiscal 2003 consists of an automobile allowance of $7,200, and reimbursement for medical expenses of $10,932. For Mr. Barthrop, the amount attributable to perquisites in fiscal 2002 consists of an automobile allowance of $7,200, and reimbursement for medical expenses (including gross up payments to pay income taxes on reimbursements) of $9,003. The amount attributable to perquisites in fiscal 2001 consists of an automobile allowance of $4,800, and reimbursement for medical expenses (including gross up payments to pay income taxes on reimbursements) of $5,606.

(5)	Represents the positive difference between the valuation of our common stock as of the date stock options were exercised by Mr. Barthrop and the exercise price of the options.


(6)	For Mr. Oliver, the amount attributable to perquisites in fiscal 2003 consists of an automobile allowance of $7,200, and reimbursement for medical expenses of $10,924. The amount attributable to perquisites in fiscal 2002 consists of an automobile allowance of $8,600, and reimbursement for medical expenses (including gross up payments to pay income taxes on reimbursements) of $11,396. The amount attributable to perquisites in fiscal 2001 consists of an automobile allowance of $4,800, and reimbursement for medical expenses (including gross up payments to pay income taxes on reimbursements) of $7,366.

(7)	For Ms. Guckert, the amount attributable to perquisites in fiscal 2003 consists of reimbursement for medical expenses of $10,878. The amount attributable to perquisites in fiscal 2002 consists of reimbursement for medical expenses (including gross up

No stock options were granted to the Named Executive Officers during fiscal 2003.

The following table shows stock option exercises and the value of unexercised stock options held by the Named Executive Officers during fiscal 2003.


(1)	Represents the positive difference between the valuation of $1.86 per share of common stock as of the date the options were exercised and the exercise price of the options. There is no market value for the common stock. This valuation was made by our board of directors for accounting and financial reporting purposes and does not reflect actual transactions.

(2)	Represents the positive difference between the valuation of $1.92 per share of common stock as of July 31, 2003 and the exercise price of the options. There is no market value for the common stock. This valuation was made by our board of directors for accounting and financial reporting purposes and does not reflect actual transactions.

Ian B. Carter. Mr. Carter serves as our Chairman, Chief Executive Officer and President. We entered into an employment agreement with Mr. Carter on January 1, 2000. Mr. Carter’s employment agreement was amended on November 1, 2000. The agreement provides for Mr. Carter’s employment through January 31, 2005.

Mr. Carter is entitled to a minimum base salary of $275,000 for the first year of his employment, with annual increases of $50,000 per year for each of the first four years, followed by a $75,000 increase for the

fifth year of the contract. In addition, Mr. Carter is entitled to receive a bonus of $100,000 and any additional discretionary cash bonus based on our results of operation. Mr. Carter’s base salary may be increased from time-to-time by the Board of Directors. Pursuant to his employment agreement, we granted to Mr. Carter an option to purchase 700,000 shares of Common Stock at an exercise price of $2.50 per share, expiring on January 1, 2010, with 300,000 options vested immediately and an additional 100,000 options vesting on January 1 annually through 2004. The employment agreement also provides that we will grant Mr. Carter additional options to purchase up to 2,300,000 shares of Common Stock upon the occurrence of the following events (a) completion of the audit of our July 31, 2000 consolidated financial statements — 500,000; (b) settlement of the California Department of Corporations investigation — 250,000; (c) settlement of the California Public Utilities Commission investigation — 500,000; (d) completion of liquidity event — 750,000; and (e) completion of a successful initial public offering — 300,000. Mr. Carter’s employment agreement also provides for the granting of up to 300,000 additional options each January through 2004 if we meet or exceeds financial performance objectives.

If during the term of the employment agreement, Mr. Carter is terminated, leaves, or is replaced as a result of: (a) all or substantially all of our assets or more than fifty percent (50%) of our issued and outstanding voting shares is acquired by any one person or entity not then affiliated with us; (b) a group of shareholders takes control of us when no significant change of ownership has taken place; or (c) a merger, acquisition, strategic alliance or any other event that could bring substantial capital into us, we must pay Mr. Carter an amount equal to eight times Mr. Carter’s then-current base salary plus the amount of taxes payable by Mr. Carter. In such events, Mr. Carter has the right to require us to repurchase all of his stock and all stock options referenced in his employment agreement, whether earned or unearned, at a value two times the then aggregate price value of our common stock.

We may terminate Mr. Carter’s employment upon Mr. Carter’s death, total disability, or for cause. Upon a termination for death or total disability, we will continue to pay Mr. Carter for a period of one year thereafter or until expiration of the term of the employment agreement, whichever occurs first, his then current base salary and bonus. “For cause” is limited to a conviction, entry of plea of guilty or nolo contendere for any felony that would materially and adversely interfere with his ability to perform his services of his employment. In the event of a termination for cause, Mr. Carter is entitled to receive all compensation and benefits payable to him through the date of termination.

Mr. Carter may terminate his employment only upon (a) the sale of all or substantially all of our assets to a person unaffiliated with us or the occurrence of a change of control without Mr. Carter’s consent or (b) our material breach of the employment agreement. In the case of termination due to our material breach of contract, Mr. Carter is entitled to receive a payment equal to the monetary value of all of the compensation and benefits payable to him for the remainder of the term.

If, at the expiration of the term, we have met or exceeded the projections set forth in the business plan, and we do not offer to extend Mr. Carter’s employment on terms no less favorable than those stated in the then current employment agreement, we must pay Mr. Carter a sum of $100,000 for a period of ten years. Mr. Carter will consult to us during that period and be Vice-Chairman of the Board.

Richard L. Paulsen. Mr. Paulsen serves as our Chief Operating Officer. We entered into an employment agreement with Mr. Paulsen on November 1, 2000. The agreement provides for Mr. Paulsen’s employment through December 31, 2004.

Mr. Paulsen will receive a base salary according to the following schedule, subject to increases which the Chief Executive Officer and the Compensation Committee may grant from time to time: $275,000 for the first twelve months of his employment, $325,000 for the second twelve months, $375,000 for the third twelve months and $425,000 per annum thereafter. Mr. Paulsen will be entitled to an annual cash bonus of $75,000 for calendar years 2001 and 2002, and $100,000 thereafter based upon the number of meters then under contract.

If during the term of the employment agreement there is a change of control as defined in the employment agreement, then we will pay Mr. Paulsen a cash bonus equal to the sum of eight times his

then annual base salary plus the amount of certain applicable taxes payable by him. Mr. Paulsen has the right to require us to repurchase all of his stock and all stock options referenced in his employment agreement, whether earned or unearned, at a value two times the then aggregate price value of our common stock, not to exceed $10.00 per share.

The agreement will terminate upon the occurrence of any of the following: Mr. Paulsen’s death, total disability, material breach of the employment agreement or fiduciary duty by Mr. Paulsen or written notice of Mr. Paulsen’s decision to terminate his employment. If Mr. Paulsen’s employment is terminated for any of the reasons noted in this paragraph, he will be entitled to receive the base salary and benefits earned pursuant to his employment agreement through the date of termination. If Mr. Paulsen’s employment is terminated for any other reason, then he will be entitled to receive his base salary and benefits earned pursuant to his employment agreement through the date of termination and an amount equal to one and one-half times his then current annual base salary.

James L. Oliver. Mr. Oliver serves as our Chief Financial Officer. We entered into an employment agreement with Mr. Oliver on November 1, 2000. The agreement provides for Mr. Oliver’s employment through December 31, 2004.

Mr. Oliver will receive a base salary according to the following schedule, subject to increases which the Chief Executive Officer and the Compensation Committee may grant from time to time: $150,000 for the first twelve months of his employment, $180,000 for the second twelve months, $210,000 for the third twelve months and $240,000 per annum thereafter. Mr. Oliver will be paid an annual cash bonus of 30% of his then current annual salary provided that we have met or exceeded the projections in our annual business plan or as the board of directors deems appropriate.

If during the term of the employment agreement there is a change of control as defined in the employment agreement, then we will pay Mr. Oliver a cash bonus equal to the sum of four times Mr. Oliver’s then current annual base salary plus the amount of certain taxes payable by Mr. Oliver. In the event of a sale of assets or any change of control as defined in the employment agreement, Mr. Oliver shall have the right to require us to repurchase all of his stock and stock options, then earned or to be earned, at two times the then aggregate price value of our common stock not to exceed $10.00 per share.

The agreement will terminate upon the occurrence of any of the following: Mr. Oliver’s death, total disability, material breach of the employment agreement or fiduciary duty by Mr. Oliver or written notice of Mr. Oliver’s decision to terminate his employment. If Mr. Oliver’s employment is terminated for any of the reasons noted in this paragraph, he will be entitled to receive the base salary and benefits earned pursuant to his employment agreement through the date of termination. If Mr. Oliver’s employment is terminated for any other reason, then he will be entitled to receive his base salary and benefits earned through the date of termination and an amount equal to one and one-half times his then current annual base salary.

John A. Barthrop. Mr. Barthrop serves as our General Counsel and Secretary. We entered into to an employment agreement with Mr. Barthrop on November 1, 2000. The agreement provides for Mr. Barthrop’s employment through December 31, 2004.

Mr. Barthrop will receive a base salary according to the following schedule, subject to possible increases which the Chief Executive Officer and the Compensation Committee may grant from time to time: $160,000 for the first twelve months of his employment, $185,000 for the second twelve months, $210,000 for the third twelve months and $240,000 per annum thereafter. Mr. Barthrop will be paid an annual cash bonus of 30% of his then current annual salary provided that we have met or exceeded the projections in our annual business plan or as the Board of Directors deems appropriate.

If during the term of the employment agreement there is a change as defined in the employment agreement, then we will pay Mr. Barthrop a cash bonus equal to the sum of four times Mr. Barthrop’s then current annual base salary plus the amount of certain taxes payable by Mr. Barthrop.

The agreement will terminate upon the occurrence of any of the following: Mr. Barthrop’s death, total disability, material breach of the employment agreement or fiduciary duty by Mr. Barthrop or written notice of Mr. Barthrop’s decision to terminate his employment. If Mr. Barthrop’s employment is terminated for any of the reasons noted in this paragraph, he will be entitled to receive his base salary and benefits earned through the date of termination. If Mr. Barthrop’s employment is terminated for any other reason, then he will be entitled to receive the base salary and benefits earned through the date of termination and an amount equal to one and one-half times his then current annual base salary.

Pursuant to the employment agreements dated November 1, 2000, Messrs. Paulsen, Barthrop and Oliver, have been or granted option to purchase an aggregate of 900,000, 500,000 and 500,000 shares, respectively, of our Common Stock. The options will have a three-year vesting period and an exercise price of $2.75 a share. All of the options will expire on November 1, 2007.

Linda Guckert. Ms. Guckert serves as our Vice President of Information Technology. Ms. Guckert is employed on an at-will basis pursuant to a letter agreement dated December 7, 2001. The letter agreement provides that, if Ms. Guckert’s employment with us is terminated within six months of the date that another company acquires 50% or more of our capital stock or control of the Company is taken over by a group of shareholders when no significant change of ownership has taken place, we will pay Ms. Guckert a severance bonus equivalent to six months of her then current base salary.

Executive compensation is determined by a Compensation Committee elected by our Board of Directors. The Compensation Committee is currently comprised of Robert Perkins, Craig Goodman and Junona Jonas. The Compensation Committee meets periodically or on an as needed basis and decides compensation structure and amounts on the basis of comparable executive compensation structures and amounts as established by a peer group of companies, our performance and other factors as may be determined to be useful in making such determination by the Compensation Committee. None of the current Compensation Committee members are or has been an officer or employee of the Company. None of our executive officers serve as members of the board of directors or compensation committee of any entity that has one or more executive officers who serve on our Board of Directors or the Compensation Committee.

The following table contains certain information as of October 15, 2003 regarding all persons who were the beneficial owners of more than 5% of the outstanding shares of Common Stock, each of our directors, each nominee for election to become a director, each of the Named Executive Officers and all directors and executive officers as a group. The persons named hold sole voting and investment power with respect to the shares shown opposite their respective names, unless otherwise indicated. The information with respect to each person specified is as supplied or confirmed by such person, based upon statements filed with the Securities and Exchange Commission, or based upon our actual knowledge.


(1)	Does not include disputed shares of preferred stock that Mr. Saline claims to own, none of which is currently reflected as outstanding on our shareholder list. The Superior Court for the County of Orange has issued an order requiring Commonwealth to recognize Mr. Saline’s ownership of 352,000 shares of preferred stock with the following rights and privileges: (a) each share would be convertible into two shares of common stock; (b) each share would be entitled to two votes; (c) 252,000 of the shares would be entitled to 12% cumulative annual dividends and 100,000 of the shares would be entitled to 14% cumulative annual dividends; (d) we would be required to pay dividends to Mr. Saline before paying dividends to any other shareholders; and each share would have a priority in liquidation to common stock. Mr. Saline would own 100% of the outstanding shares of each of these respective series of preferred stock. We intend to appeal the court’s order. See “Item 3. Legal Proceedings.” Under the rules of the Securities and Exchange Commission, Mr. Saline may be deemed to be the beneficial owner of these shares because, pursuant to the court order, he may have the power to vote these shares.

(2)	Subject to applicable community property and similar statutes.

(3)	Includes shares beneficially owned, whether directly or indirectly, individually or together with associates.


(4)	Represents shares of our common stock issuable upon exercise of stock options or upon conversion of other convertible securities held by such persons that are exercisable within 60 days of October 15, 2003.

(5)	Includes 25,000 shares of common stock issuable upon conversion of shares of Series A Convertible Preferred Stock held by Mr. Perkins at a conversion ratio of one-for-one.

(6)	Represents shares of our common stock issuable upon the disputed shares of preferred stock that Mr. Saline claims to own, assuming a two-for-one conversion ratio. See footnote (1) above. Under the rules of Securities and Exchange Commission, Mr. Saline may be deemed to be the beneficial owner of these shares because, pursuant to the court order, he may have the power to vote these shares.

(7)	Includes the shares of common stock issuable upon conversion of the disputed shares of preferred stock that Mr. Saline claims to own, assuming a two-for-one conversion ratio. See footnote (6) above.

Our 1999 Equity Incentive Plan, or the Plan, has been approved by our shareholders. We do not have any equity compensation plans other than the 1999 Equity Incentive Plan approved by our shareholders, with the exception of one-time grants of warrants or options made by the our Board of Directors from time to time.

The following table sets forth information regarding the number of shares of our common stock that may be issued pursuant to our equity compensation plans or arrangements as of the end of fiscal 2003.

We utilize Technical Service Group, Inc., doing business as Symcas-TSG (“Symcas”) on a limited basis for our IT maintenance. We paid Symcas $577,000 in fiscal 2003 for such services. Linda Guckert, our Vice President of Information Technology, and her husband together own 50% of Symcas.

The following table sets forth the fees billed to us by Ernst & Young LLP, our independent auditor for each of the last two fiscal years.

Audit Fees: This category includes the audit of our annual consolidated financial statements, the review of financial statements included in our quarterly reports on Form 10-Q and services that are normally provided by the independent auditors in connection with statutory and regulatory filings or engagements for those fiscal years.

Audit Related Fees: This category consists of assurance and related services provided by Ernst & Young LLP that were reasonably related to the performance of the audit or review of our financial statements and which are not reported above under “Audit Fees.” Ernst & Young LLP did not bill the Company for any audit-related services for fiscal 2002 or 2003.

Tax Fees. This category consists of professional services rendered by Ernst & Young LLP for tax services, including tax compliance, tax advice and tax planning.

All Other Fees. This category consists of fees for advisory services in relation to the Company’s billing system.

The Audit Committee of our Board of Directors has established a practice that requires the committee to pre-approve any audit or permitted non-audit services to be provided to us by our independent auditor, Ernst & Young LLP, in advance of such services being provided to us.

In fiscal 2002, none of the tax fees were pre-approved by the Audit Committee. In fiscal 2003, all of the tax related fees and the fees included in the category “All Other Fees” were pre-approved by the Audit Committee. Under the SEC rules, subject to certain de minimis criteria, pre-approval is required for all professional services rendered by our principal accountant for all services rendered on or after May 6, 2003. We are in compliance with these SEC rules.

All schedules are omitted as the required information is inapplicable or the information is presented in the consolidated financial statements or related notes.

We filed a Current Report on Form 8-K on June 17, 2003, reporting our operating results for the three and nine months ended April 30, 2003.


(1)	Each of these exhibits is incorporated herein by reference to Commonwealth Energy Corporation’s Form 10 filed with the Securities and Exchange Commission on August 9, 2001 (File No. 000-33069).

(2)	Each of these exhibits is incorporated by reference to Commonwealth Energy Form 10/ A filed with the Securities and Exchange Commission on November 14, 2001 (File No. 000-33069).


(3)	This exhibit is incorporated herein by reference to Commonwealth Energy Corporation’s form 10-Q for the quarterly period ended January 31, 2003.

(4)	This exhibit is incorporated by reference to Commonwealth Energy Corporation’s Registration Statement on Form S-8 (File No. 333-109552) filed with the Securities and Exchange Commission on October 8, 2003.

(5)	Each of these exhibits is incorporated by reference to Commonwealth Energy Form 10-Q filed with the Securities and Exchange Commission on December 17, 2001 (File No. 000-33069).

(6)	Each of these exhibits is incorporated by reference to Commonwealth Energy Form 10/ A filed with the Securities and Exchange Commission on April 3, 2002 (File No. 000-33069).

(7)	Each of these exhibits is incorporated by reference to Commonwealth Energy Corporation’s Form 10-K for the year ended July 31, 2002 filed with the Securities and Exchange Commission on October 29, 2002.

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

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

We have audited the accompanying consolidated balance sheets of Commonwealth Energy Corporation as of July 31, 2002 and 2003, and the related consolidated statements of income, shareholders’ equity and cash flows for each of the three years in the period ended July 31, 2003. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the 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 misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Commonwealth Energy Corporation at July 31, 2002 and 2003, and the consolidated results of its operations and its cash flows for each of the three years in the period ended July 31, 2003, in conformity with accounting principles generally accepted in the United States of America.

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

Commonwealth Energy Corporation (“Commonwealth” or the “Company”) is an energy services company. The Company provides retail electric power to its residential, commercial, industrial and governmental customers in the deregulated California, Michigan and Pennsylvania electricity markets. The Company is licensed by the Federal Energy Regulatory Commission (“FERC”) as a power marketer and is licensed to supply retail electric power by applicable state agencies in California, Pennsylvania, Michigan, New Jersey, New York, Texas and Ohio.

The Company does not have its own electricity generation facilities. The power the Company sells to its customers is purchased from third party power generators. The electric power the Company sells to its retail customers is delivered to its customers by incumbent electric utilities. The incumbent electric utilities measure electric power usage by the Company’s customers and bill most of its customers on its behalf. The Company plans to enter new deregulated electric power markets and to offer a variety of energy-related products and services in the future. The Company also sells surplus electric power not needed to meet its retail customers’ requirements in wholesale electricity markets. The Company only sells this excess power to assist in balancing its energy supply with the demand of its retail customers. The Company does not trade in the wholesale electricity markets for speculative purposes.

Commonwealth has three wholly-owned subsidiaries: electricAmerica, Inc., UtiliHost, Inc. and electric.com, Inc. Each of these subsidiaries is incorporated in the State of Delaware, but as of yet, none of them is operational. The Company also holds a majority interest in Summit Energy Ventures, LLC (“Summit”), a joint venture that invests in companies that manufacture or market energy efficiency products. The consolidated financial statements of the Company include the accounts of Summit and the Company’s wholly-owned subsidiaries.

The Company’s consolidated financial statements include its wholly-owned subsidiaries and the accounts of its controlled investment in Summit Energy Ventures, LLC (“Summit”) and its majority ownership in Power Efficiency Corporation (“PEC”). All material intercompany balances and transactions have been eliminated in consolidation.

The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make certain estimates and assumptions that affect the reported amounts and timing of revenue and expenses, the reported amounts and classification of assets and liabilities, and the disclosure of contingent assets and liabilities. These estimates and assumptions are based on the Company’s historical experience as well as management’s future expectations. As a result, actual results could differ from management’s estimates and assumptions. The Company’s management believes that its most significant estimates herein relate to revenue and cost recognition, unbilled receivables, the allowance for doubtful accounts and loss contingencies, particularly those associated with litigation.

The Company has reclassified certain prior fiscal year amounts in the accompanying consolidated financial statements to be consistent with the current fiscal year’s presentation. During its fiscal 2003 fourth quarter, the Company deemed it more appropriate to reclassify its Pennsylvania gross receipts taxes

to direct energy costs from general and administrative expenses. Prior year amounts reclassified from general and administrative expenses were $666 and $1,143 for fiscal 2001 and 2002, respectively.

Energy sales are recognized as the electric power is delivered to customers and green power credits are recognized upon the fulfillment by the Company of all related obligations, provided collection is deemed probable.

Direct energy costs, which are recognized concurrent with related energy sales, include the cost of purchased electric power, fees incurred from various energy-related service providers and energy related taxes. Independent system operator (“ISO”) fees are not determinable until the ISO completes a settlement process for each day’s activities. Pending such settlements, the Company estimates and accrues for these ISO fees based on preliminary settlement information.

Two wholesale customers, the State of California’s Department of Water Resources and the California Power Exchange, individually accounted for 22.0% and 10.6% of the Company’s consolidated net revenue in fiscal 2001. No individual customer accounted for ten percent or more of the Company’s consolidated net revenue in fiscal 2002 or 2003.

Selling and marketing expenses principally consist of costs incurred for sales and marketing personnel and promotional and advertising activities. Advertising costs are expensed as incurred and were $253, $129 and $92 for fiscal 2001, 2002 and 2003, respectively.

General and administrative expenses principally consist of costs incurred for all other corporate personnel, rent, utilities, telecommunications, insurance, legal fees, and other miscellaneous corporate costs, including provisions made for uncollectible accounts receivable, and the depreciation and amortization of tangible and intangible assets (see below for details regarding stock-based compensation charges).

Net income per common share — Basic has been computed by dividing net income available to common shareholders, after any preferred stock dividends, by the weighted average number of common shares outstanding during the fiscal year. Net income per common share — Diluted has been computed by giving additional effect in the denominator to the dilution that would have occurred, under the treasury stock and if-converted methods, as applicable, had outstanding stock options, stock purchase warrants and convertible debt been exercised or converted into additional common shares.

As allowed by Statement of Financial Accounting Standards (“SFAS”) No. 123 (“SFAS No. 123”), “Accounting for Stock-Based Compensation”, the Company has elected to retain the compensation measurement principles of Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB No. 25”), and its related interpretations for stock options issued to employees and outside directors. Under APB No. 25, compensation cost is recognized at the measurement date for the amount, if any, that the fair value of the Company’s common stock exceeds the option exercise price. The measurement date is the date at which both the number of options and the exercise price for each option are known. The Company recognized stock-based compensation charges (credits) of $1,080, $(743) and $0 during fiscal 2001, 2002 and 2003, respectively.

On December 31, 2002, the Financial Accounting Standards Board (“FASB”) amended the transition and disclosure requirements of SFAS No. 123 through the issuance of SFAS No. 148 (“SFAS No. 148”), “Accounting for Stock-Based Compensation — Transition and Disclosure”. SFAS No. 148 amends the existing disclosures to make more frequent and prominent disclosure of stock-based compensation expense beginning with financial statements for fiscal years ending after December 15, 2002. The Company has adopted the disclosure provisions of SFAS No. 148.

If the Company had accounted for its stock-based employee and outside directors compensation under the minimum fair value recognition and measurement principles of SFAS No. 123, the Company’s reported net income amounts would have been adjusted to the pro forma net income amounts presented below:

The fair value of each option grant was estimated on the date of grant using the minimum value method with the following weighted average assumptions:

The Company does not include volatility as there is not an active market for the Company’s stock.

The estimated fair values for stock options granted during fiscal 2001, 2002 and 2003 were $3.05, $1.86 and $1.86, respectively.

Cash equivalents consist of highly liquid debt instruments with a maturity date of three months or less at the date of purchase. The Company maintains its cash and cash equivalents with highly rated financial institutions, thereby minimizing any associated credit risks.

The Company’s accounts receivable consist of billed and unbilled receivables from customers and Green Power credits receivable from the State of California. The Company’s customers are billed monthly at various dates throughout the month. Unbilled receivables represent the amount of electric power delivered to customers as of the end of the period, but not yet billed. Unbilled receivables from customers are estimated by the Company to be the number of kilowatt-hours (“kWh”) delivered times the current customer average sales price per kWh.

The Company’s exposure to credit risk concentration is substantially limited to those incumbent utility companies that collect and remit receivables, on a daily basis, from the Company’s individually insignificant and geographically dispersed customers within the states of California, Pennsylvania and Michigan. The Company regularly monitors the financial condition of each such incumbent utility company and currently believes that its susceptibility to any individually significant write-offs as a result of concentrations of customer accounts receivable with incumbent utility companies is remote.

The Company maintains an allowance for doubtful accounts, which represents management’s best estimate of probable losses inherent in the accounts receivable balance. Management determines the allowance based on known troubled accounts, historical experience, and other currently available evidence (see Note 7).

Deferred income tax assets and liabilities are recognized for the expected future income tax benefits or consequences, based on enacted laws, of temporary timing differences between tax and financial statement reporting. If appropriate, deferred tax assets are reduced by a valuation allowance for the amount of any tax benefits that more likely than not, based on current circumstances, are not expected to be realized.

Cash and cash equivalents which the Company currently can not access, as they are pledged as collateral or invested in and held by Summit, are reported as restricted.

Property and equipment are recorded at cost. Maintenance and repairs which do not extend the useful life of the related property or equipment are charged to operations as incurred. Depreciation of property and equipment has been computed using the straight-line method over estimated economic useful lives of five to ten years.

Certain software development costs incurred on significant projects for internal use, primarily consisting of third-party system development costs incurred during the application development stage, are capitalized. These capitalized costs, once placed in service, are amortized using the straight-line method over estimated economic useful lives of three to five years.

Goodwill resulting from Summit’s majority ownership in PEC is not amortized into results of operations but instead is reviewed for impairment, written down, and charged as expense to results of operations in fiscal periods in which the recorded value of goodwill is more than its implied fair value. Estimates of fair value are primarily determined using discounted cash flows and are based on the Company’s best estimate of future revenue and operating costs and general market conditions. This approach uses significant assumptions, including projected amounts and timing of future cash flows, the discount rate reflecting the risk inherent in future cash flows, and the terminal growth rate.

Direct costs incurred in acquiring intangible assets, primarily consisting of the Company’s 1-800-Electric telephone number, rights to eight internet domain names and a covenant not to compete, have been capitalized. Each intangible asset is being subsequently amortized over the shorter of its statutory, contractual or estimated economic useful life, which collectively range from 2 to 20 years. Aggregate amortization expense for these intangible assets was $53, $53 and $238 for fiscal 2001, 2002 and 2003, respectively.

Management, on at least a quarterly basis, evaluates each of the Company’s long-lived assets for impairment by comparing the related estimated future cash flows, on an undiscounted basis, to its net book value. If impairment is indicated, the net book value is reduced to an amount equal to the estimated future cash flows, on an appropriately discounted basis.

The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable, and accounts payable. The carrying amounts of these financial instruments are reflected in the accompanying consolidated balance sheets at amounts considered by management to materially approximate their fair values due to their immediate or short-term nature.

In June 2001, the FASB issued SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS No. 142”), which revises the accounting for purchased goodwill and other intangible assets. Under SFAS No. 142, goodwill and other intangible assets with indefinite lives will no longer be systematically amortized into operating results. Instead, each of these assets will be tested, in the absence of an indicator of possible impairment, at least annually, and upon an indicator of possible impairment, immediately.

In August 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”). SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized

cost is depreciated over the useful life of the related obligation for its recorded amount or incurs a gain or loss upon settlement.

In August 2001, the FASB issued SFAS No. 144, “Accounting for the Impairment or Disposal of Long-lived Assets” (“SFAS No. 144”). SFAS No. 144 was issued to resolve certain implementation issues that had arisen under SFAS No. 121. Under SFAS No. 144, a single uniform accounting model is required to be used for long-lived assets to be disposed of by sale, whether previously held and used or newly acquired, and certain additional disclosures are required.

In April 2002, the FASB issued SFAS No. 145, “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections” (“SFAS No. 145”). SFAS No. 145 updates, clarifies and simplifies existing accounting pronouncements, by rescinding SFAS No. 4, which required all gains and losses from extinguishment of debt to be aggregated and, if material, classified as an extraordinary item, net of related income tax effect. As a result, the criteria in Accounting Principles Board Opinion No. 30 (“APBO No. 30”) will now be used to classify those gains and losses. Additionally, SFAS No. 145 amends SFAS No. 13 to require that certain lease modifications that have economic effects similar to sale-leaseback transactions be accounted for in the same manner as sale-leaseback transactions. Finally, SFAS No. 145 also makes technical corrections to existing pronouncements. While those corrections are not substantive in nature, in some instances, they may change accounting practice.

The Company adopted the provisions of SFAS No. 145 that amended SFAS No. 13, as required, on May 15, 2002, for transactions occurring after such date with no material impact on its consolidated financial statements. The Company adopted SFAS Nos. 142, 143 and 144, as well as the remaining provisions of SFAS No. 145, as required, on August 1, 2002, with no material impact on its accompanying consolidated financial statements.

In June 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities” (“SFAS No. 146”). SFAS No. 146 was issued to address the financial accounting and reporting for costs associated with exit or disposal activities, unless specifically excluded. SFAS No. 146 requires that a liability for a cost associated with a covered exit or disposal activity be recognized and measured initially at its fair value in the period in which the liability is incurred, except for a liability for one-time termination benefits that is incurred over time. If employees are not required to render service until they are terminated in order to receive the one-time termination benefits or if employees will not be retained to render service beyond the minimum retention period (as dictated by existing law, statute or contract, or in the absence thereof, 60 days), a liability for the termination benefits shall be recognized and measured at its fair value at the communication date. If employees are required to render service until they are terminated in order to receive the one-time termination benefits and will be retained to render service beyond the minimum retention period, a liability for the termination benefits shall be measured initially at the communication date based on the fair value of the liability as of the termination date. The liability shall be recognized ratably over the future service period. SFAS No. 146 also dictates that a liability for costs to terminate an operating lease or other contract before the end of its term shall be recognized and measured at its fair value when the entity terminates the contract in accordance with the contract terms. A liability for costs that will continue to be incurred under a contract for its remaining term without economic benefit to the entity is to be recognized and measured at its fair value when the entity ceases using the right conveyed by the contract. SFAS No. 146 further dictates that a liability for other covered costs associated with an exit or disposal activity be recognized and measured at its fair value in the period in which the liability is incurred. The Company adopted SFAS No. 146, as required, on January 1, 2003, with no material impact on its accompanying consolidated financial statements.

In November 2002, the FASB issued FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (“FIN

45”). FIN 45 requires that a liability be recorded in the guarantor’s balance sheet upon issuance of a guarantee. In addition, FIN 45 requires disclosures about the guarantees that an entity has issued, including a reconciliation of changes in the entity’s product warranty liabilities. The initial recognition and measurement provisions of FIN 45 are applicable on a prospective basis to guarantees issued or modified after December 31, 2002, irrespective of the guarantor’s fiscal year-end. The Company adopted FIN 45, as required, on January 1, 2003, with no material impact on its accompanying consolidated financial statements.

In December 2002, the FASB issued SFAS No. 148 “Accounting for Stock-Based Compensation — Transition and Disclosure, an amendment of FASB Statement No. 123” (“SFAS No. 148”). SFAS No. 148 amended SFAS No. 123 “Accounting for Stock-Based Compensation” (“SFAS No. 123”) to provide for alternative methods of transition for an entity that voluntarily changes to the fair value based method of accounting for stock-based employee compensation. SFAS No. 148 further amends the disclosure provisions of SFAS No. 123 and APBO No. 28 to require prominent annual and interim disclosures about the effects on reported net income or loss of an entity’s accounting policy decisions with respect to stock-based employee compensation. As the Company continues to account for stock-based employee compensation under the intrinsic value based method allowed by APBO No. 25, the Company’s adoption of the disclosure provisions of SFAS No. 148, as required, on August 1, 2002 had no impact on its accompanying consolidated financial statements.

In January 2003, the FASB issued FASB Interpretation No. 46, “Consolidation of Variable Interest Entities” (“FIN 46”). This interpretation of Accounting Research Bulletin No. 51, “Consolidated Financial Statements,” addresses consolidation by business enterprises of variable interest entities that possess certain characteristics. FIN 46 requires that if a business enterprise has a controlling financial interest in a variable interest entity, the assets, liabilities, and results of the activities of the variable interest entity must be included in the consolidated financial statements with those of the business enterprise. FIN 46 applies immediately to variable interest entities created after January 31, 2003, and to variable interest entities in which an enterprise obtains an interest after that date. As the Company has not had, and continues not to have, any ownership in variable interest entities, the Company’s adoption of FIN 46, as required, on February 1, 2003, had no impact on its accompanying consolidated financial statements.

In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (“SFAS No. 149”). SFAS No. 149 amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133. SFAS No. 149 requires that contracts with comparable characteristics be accounted for similarly and clarifies when a derivative contains a financing component that warrants special reporting in the statement of cash flows. SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003, except in certain circumstances, and for hedging relationships designated after June 30, 2003. The Company adopted SFAS No. 149, as required, on July 1, 2003 with no impact on its accompanying consolidated financial statements.

In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.” SFAS No. 150 established standards for how an issuer classifies and measures in its statement of financial position certain financial instruments with characteristics of both liabilities and equity. The Company adopted SFAS No. 150, as required, on May 31, 2003 for financial instruments entered into or modified after such date, with no impact on its accompanying consolidated financial statements. The remaining provisions of SFAS No. 150 are effective beginning with the Company’s fiscal 2004 first quarter ending October 31, 2003 and must be applied prospectively by reporting the cumulative effect of a change in an accounting principle for financial instruments created before the issuance date of SFAS No. 150 and still existing at July 1, 2003. The

Company adopted these remaining provisions of SFAS No. 150, as required, on August 1, 2003, with no impact on its accompanying consolidated financial statements.

The Company’s chief operating decision makers consist of members of senior management that work together to allocate resources to, and assess the performance of, the Company’s business. These members of senior management currently manage the Company’s business, assesses its performance, and allocates its resources as a single operating segment.

Due in part to historically extreme highs in electrical prices, on September 20, 2001, the California Public Utilities Commission (“CPUC”) issued a ruling suspending direct access (“DA”) pursuant to legislation by the California state legislature. The suspension of DA means that this ruling permits the Company to keep its current customer base and continue to solicit business from other DA customers served by other providers, but prohibits the Company from signing up new non-direct access customers for an undetermined period of time. The Company is actively seeking relief from this ruling.

Under a settlement agreement with the CPUC, Southern California Edison (“SCE”) was authorized to recoup $3,600,000 in debt incurred during the energy crisis of 2000-2001 from all customers. This debt was to be collected under the Procurement Related Obligations Account (“PROACT”) from bundled (non DA) customers and under the Historical Procurement Charge (“HPC”) from DA customers.

In July 2002, the CPUC issued an interim order implementing the HPC sought by SCE to collect $391,000 in HPC charges from all DA customers by reducing their Procured Energy Credit (“PE Credit”) by $0.027 per kWh beginning July 27, 2002. The lowered PE Credit continued until an exit fee for DA customers was approved by the CPUC. Effective January 1, 2003, it was reduced to $0.01 per kWh. For the fiscal year ended July 31, 2003, the Company estimates that HPC charges have impacted the Company’s sales and pretax earnings by a range of $4,800 to $6,000. The Company is unable to precisely determine the actual HPC charges applied to its customers by SCE because there are different charges by customer type, and this charge is only on the electricity usage above the monthly baseline usage allocation.

On September 5, 2003 the CPUC issued a decision granting SCE’s request to recover additional shortfall and authorizing the HPC balance to be revised to $473,000; however, the $0.01 per kWh monthly charge remained in place. As of August 1, 2003, SCE revised its billing methodology to a “bottoms-up” design effectively doing away with the PE Credit and the net effect of the HPC on the Company’s rates. While the HPC no longer impacts the Company’s rate calculations going forward, a recent SCE rate reduction includes the impact of the HPC. This rate reduction will impact sales and pretax profit in the SCE district. The rate reduction will be place in 2004 and will approximate the effect of the HPC dollar impact of 2003.

Recently, SCE acknowledged that the PROACT debt was paid in full by bundled customers at the end of July 2003. As a result, on August 1, 2003, all SCE rates were lowered. As a direct result, to retain the Company’s customers in the SCE utility district, the Company lowered its customer rates proportionately. The Company’s estimates of the annual financial impact of this rate reduction is a decline in sales and pretax profit during fiscal 2004, in the range of $3,000 to $3,500. This reduction is separate from, but in addition to, the HPC reduction seen in 2003.

These changes on the Company’s customers in the SCE district will continue to cause a significant impact on the Company’s revenue and cash flow; however, the Company does not expect that it will preclude the Company from participating in the California market.

In accordance with its standard customer contract in Pennsylvania, the Company may only charge certain maximum rates for its sales of electric power which, at times, could be less than the Company’s costs of acquiring, distributing and scheduling such electric power. Energy capacity charges for servicing electric power in the Pennsylvania market varies significantly from month to month and can affect gross profit margins.

The State of California enacted a Public Purpose Program (“Program”) to provide incentives to suppliers of renewable power (produced with at least 50% renewable energy resources), to reduce the cost of such power to certain consumers by $0.01 per kWh ($0.015 per kWh prior to January 1, 2002). The Company received regular green power credit payments totaling $2,051 during fiscal 2002, which were included in the Company’s net revenue during that period. The benefit of these anticipated credits was reflected in the form of discounted electricity rates charged to the Company’s customers. This phase of the Program expired for service periods ending December 31, 2001. The Company continued to sell electricity to these customers at discounted rates. The Program was then subsequently extended for service periods from January 1, 2002 through March 30, 2003. The credits of approximately $5,600 received by the Company for this period is reflected in the three month period ended July 31, 2003, when it became apparent that the funds would be received. Recognition was previously deferred because of the uncertainty of receipt caused by both the State budget turmoil in California, and the indecisive progress this Program made to reach final enactment and settlement as follows: in September 2002, a State law was passed that required the Energy Commission to report to the Governor on whether the Program should be extended. The submitted report was approved on April 2, 2003, and only “recommended” extending the Program through service periods ending on March 31, 2003. The recommendations were eventually accepted, and payment was received in October 2003, and as a result the anticipated payment was shown as a receivable at July 31, 2003.

A reconciliation of the federal statutory income tax rates to the Company’s effective income tax rates follows:

During fiscal 2001, the valuation allowance increased by $362 as a result of an increase in the federal statutory income tax rate being applied to the Company’s temporary differences and decreased by $13,595 for the release of a portion of the valuation allowance due to the Company’s profitable operations for the year. During fiscal 2002, the valuation allowance decreased by $23 which reflected the uncertainty of the deferred tax asset related to the net operating loss carryforward, the use of which became limited as described below. During 2003, the valuation allowance decreased by $155 and reflected the utilization of net operating loss carryforwards for federal income tax purposes.

At July 31, 2003, the Company had net operating loss carryforwards of approximately $1,818 and $2,072 for federal and state income tax purposes, respectively, that begin to expire in years 2018 and 2008, respectively. The timing of the utilization of federal net operating loss carryforwards is subject to an annual limitation due to the “change of ownership” provision of the Tax Reform Act of 1986. As a result of this annual limitation, a portion of these carryforwards may expire before ultimately becoming available to reduce future income tax liabilities.

On September 11, 2002, the Governor of California signed into law new tax legislation that suspended the use of net operating loss carryforwards into tax years beginning on or after January 1, 2002 and 2003. Should the Company have taxable income for the fiscal year ending July 31, 2004, it may not look to California net operating losses generated in prior fiscal years to offset taxable income. This suspension will not apply to tax years beginning on or after 2004.

For fiscal 2001, 2002 and 2003, 243, 6,943, and 6,860 common shares attributable to outstanding stock options and warrants were excluded from the calculation of diluted earnings per share because the effect of their inclusion would be anti-dilutive.

The following schedules set forth the activity in the Company’s allowance for doubtful accounts for the reported periods:

The Company’s fiscal 2001 provision for doubtful accounts includes $1,604 to fully reserve for withheld customer remittances due from Pacific Gas and Electric (“PG&E”) which filed for bankruptcy protection in April 2001. The Company views PG&E’s filing for bankruptcy protection as the result of an unforeseeable convergence of a number of unusual events that gave rise to the then California energy crisis. The Company has filed a Proof of Claim with the bankruptcy court but any recovery remains uncertain.

In July 2001, the Company formed Summit as a vehicle through which it could invest in entities that develop and market products that conserve or manage electricity. The Company’s initial $15,000 capital contribution in Summit, which constitutes its entire investment to date, entitled it to a 100% preferred

membership interest and a 60% common membership interest. The Company has the right to invest additional amounts under certain conditions. Additionally, should Summit propose to issue additional ownership interests or to sell any investment held by it, the Company has first rights of refusal at equivalent terms.

All investments made by Summit must be approved by its investment committee, which is comprised of three individuals appointed by the Company. Summit’s investment committee has appointed Northwest Power Management (“NPM”) as its investment manager, for which it receives a $700 annual fee.

Any investment returns realized by Summit are allocated initially to the repayment of all capital contributions by the Company, and a 10% annual preferred return thereon, with any remaining profits allocated 60% to the Company and 40% to NPM. Any cumulative net losses incurred by Summit are allocated 100% to the Company as the sole contributor of capital. Summit’s Limited Liability Company (“LLC”) agreement sets forth that it will cease to exist as a legal entity in June 2006, although its life may be extended for up to two additional one year periods if so chosen by NPM. Upon its legal dissolution, Summit will make distributions in accordance with the terms of the LLC agreement as stated above.

At July 31, 2003, Summit had investments in three energy related companies as follows:

On May 8, 2003, Summit provided a $1,000 revolving line of credit to PEC. Any advances are secured by all of PEC’s tangible and intangible assets and accrue interest at a rate of 15% per annum. The line of credit expires on December 31, 2003 with any outstanding advances and accrued interest becoming due and payable. Prior to extending this revolving line of credit, Summit’s convertible preferred stock holding in PEC entitled it to cast shareholder votes not to exceed 28% of PEC’s outstanding common shares. Upon providing PEC with the revolving line of credit, Summit became entitled to cast shareholder votes equivalent to that number of common shares in PEC into which its convertible preferred shares was convertible. Subsequently, as a result of periodic issuances of additional common shares by PEC and an anti-dilution guarantee held by Summit, the number of common shares that Summit was entitled to convert its convertible preferred stock holding into and vote increased to as much as 56%. Subsequent PEC stock sales have reduced Summit’s investment to 52.8% at July 31, 2003.

Summit has consistently accounted for its investment in Envenergy, Inc. under the cost method of accounting. The Company accounted for its investment in Turbocor, LLC under the equity method of accounting whereby it recognized its proportionate share of income and losses until January 31, 2003, when its ownership percentage was reduced. Summit then accounted for its investment in Turbocor, BV (Turbocor, LLC was collapsed, and Summit’s equivalent investment in Turbocor, Inc., the operating entity, is now held directly through Turbocor BV) under the cost method of accounting. Prior to May 8, 2003, Summit accounted for its investment in PEC using the equity method of accounting, but based on Summit’s recently increased ownership percentage, after May 8, 2003, Summit is consolidating its investment in PEC.

Condensed balance sheet information for Summit at July 31, 2002 and 2003 is as follows:

Summit, since its inception in fiscal 2001, has been consolidated into the Company’s financial statements as the Company exercises, or has the ability to exercise, directly or indirectly, legal, financial and operational control. The effects of Summit’s results of operations on the Company’s consolidated results of operations were net losses of $803 and $1,472 for fiscal 2002 and 2003, respectively.

Each share of the Company’s outstanding Series A convertible preferred stock (i) has the same voting rights as one share of the Company’s common stock into which it is convertible at the shareholder’s discretion, (ii) accrues cumulative dividends at an annual rate of 10% which are payable at the Company’s discretion, and (iii) has a preferential liquidation right in the amount of $1 per share plus any declared but unpaid dividends. On December 20, 2002, the Company paid a cash dividend of $0.15 per share to holders of record as of December 16, 2002. Cumulative unpaid dividends were $91 as of July 31, 2003.

During fiscal 2001, the Company offered all Series A preferred shareholders the option to rescind their purchase at the initial offering price of $1 per share. Pursuant to this offer, the Company subsequently repurchased 164 preferred shares in fiscal 2001 and 2002.

Pursuant to a September 2003 court ruling (see Note 14), the Company has reflected shares of Other convertible preferred stock in the accompanying financial statements. If the court’s ruling were to stand, each share of this Other convertible preferred stock would (i) have the same voting rights as two shares of the Company’s common stock into which it is convertible at the shareholder’s discretion, (ii) accrue cumulative dividends at an annual rate of 12% to 14%, and (iii) have a preferential liquidation right to the Company’s common stock. No dividends have been declared on these shares as of July 31, 2003. Cumulative unpaid dividends were $42 at July 31, 2003.

All sales of the Company’s common stock to date have been through private placements.

At July 31, 2003, the Company has reserved the following shares of its common stock:

Adjustment of Number of Outstanding shares of Series A Preferred and Common Stock

In December 2002, the Company determined that 166 shares of Series A Convertible Preferred Stock and 166 shares of Common Stock that had previously been treated as outstanding had not been validly issued. As a result, these shares were removed from the records of the Company and the Company has determined that such shares shall no longer be treated as issued and outstanding for any purpose. Accordingly, the Company has corrected its current years’ financial statements to reflect the cancellation of these shares. The correction did not impact the Company’s reported earnings per common share amounts.

In January 2002, the Company adopted a Stockholder Rights Plan that is triggered whenever an Acquiring Person accumulates 15% or more of the Company’s stock or if an Adverse Person acquires 10% or more of the Company’s stock and intends to implement measures which the Board of Directors believes to be adverse to the Company’s interests. An Acquiring Person is a person or group, together with the person’s or group’s affiliates, that has acquired, or obtained the right to acquire, beneficial ownership of 15% or more of the outstanding shares of the Company’s Common Stock. An Adverse person is a person, alone or with affiliates, that has become the beneficial owner of more than 10% of the outstanding shares of Common Stock and (i) such beneficial ownership is intended to cause the Company to repurchase the Common Stock owned by such person or pressure the Company to take action or enter into transactions intended to provide such person with short-term financial gain under circumstances where the Company’s Board of Directors determine that the Company’s best long-term interests would not be served by taking such action or entering into such transactions or (ii) such beneficial ownership is causing or reasonably likely to cause a material adverse impact on the Company’s business or prospects, provided, however, that the Company’s Board of Directors does not have the right to declare a person to be an Adverse Person if such person has reported or is required to report its ownership of the Company’s Common Stock on Schedule 13G under Securities Exchange Act of 1934, as amended, or on Schedule 13D if that schedule does not state any intention to, or reserve the right to, control or influence the Company or engage in certain other actions, so long as such person neither reports nor is required to report such ownership. Once the rights vest, shareholders other than the Acquiring Person or Adverse person will be able to purchase at a predetermined price two shares of Common Stock for the price of one share of Common Stock.

All unexercised stock options granted prior to December 1999 expired in December 2002. Stock options granted after December 1999 will expire in December 2004 through 2010. As of July 31, 2003, 7,489 stock options remained unexercised and outstanding.

The Company’s 1999 Equity Incentive Plan (“Plan”), which was approved by the Company’s shareholders, provides for the granting of up to an aggregate of 7,000 common shares. In addition, the Company’s Board of Directors has from time to time made individual grants of warrants or options outside the Plan. At July 31, 2003, the Company had 2,927 and 4,562 stock options unexercised and outstanding that were granted under and outside the Plan, respectively.


(1)	Options with exercise prices less than the fair value of the Company’s common stock at respective dates of grant.

(2)	Options with exercise prices equal to the fair value of the Company’s common stock at respective dates of grant.

The weighted average characteristics of stock options outstanding as of July 31, 2003 were as follows:

Stock Options Granted to the Company’s Chairman and Chief Executive Officer and Related Stock-based Compensation

As part of an employment agreement with a term expiring January 31, 2005, the Company has granted 4,200 stock options to the Company’s Chairman and Chief Executive Officer which have an exercise price of $2.50 per share and expire on January 1, 2010. As of January 1, 2000, 300 of the options were vested and 100 options vest annually on January 1 of each year from 2001 through 2004, for a total of 700. The remaining 3,500 options are performance-based and vest upon the occurrence of certain events as detailed below.

Performance criteria which were met as of July 31, 2003, the number of related stock options vested and those not earned, and stock-based compensation recognized during the years ended July 31, 2002 and 2001 are as follows (no stock-based compensation was recognized in the year ended July 31, 2003, as the exercise price of the stock options was above the current fair market value of the Company’s common stock):

If during the term of the employment agreement, the Company makes a public offering of its shares or if the Company supports any other form of liquidity event, then all stock options related to this employment agreement, whether earned or not, shall be considered vested concurrent to such event.

The employment agreement also provides that in the event the Company terminates the agreement early or a change in control of the Company occurs, the Company’s Chairman and Chief Executive Officer has the right to require the Company to repurchase all of his capital stock and stock options, then earned or to be earned, at a repurchase price equal to two times the then value of the Company’s common stock.

In June 2000, the Company granted a lender in connection with a line of credit agreement, which subsequently expired in June 2002, stock purchase warrants enabling the lender to purchase 100 shares of the Company’s common stock at an exercise price of $5.50 per share. These warrants, which had a nominal value as of the grant date, expired unexercised in June 2003.

The Company has entered into a series of electricity supply contracts to purchase electricity energy covering approximately 81% of the current load servicing requirements.

The following is a summary of the Company’s commitments to purchase electric power by state as of July 31, 2003:

For the Michigan market, the Company has entered into several forward energy supply contracts with a major energy generator to purchase the full requirements service product to service the Company’s customer load. These full requirement service contracts include energy and all scheduling costs. These contracts require the generator to sell the Company power, however, the Company is not required to take delivery.

Since the price at which the Company can purchase electric power is fixed during the terms of the contracts, if the price at which the Company can resell this electric power falls below the contract purchase price plus distribution and scheduling costs, the Company would incur operating losses during such periods.

The Company leases its corporate facilities as well as certain equipment under operating leases. Certain of these operating leases are noncancellable and contain rent escalation clauses relating to any increases to real property taxes and maintenance costs. The Company incurred aggregate rent expense under operating leases of $697, $704 and $742 in fiscal 2001, 2002 and 2003, respectively.

The future aggregate minimum lease payments under operating lease agreements in existence at July 31, 2003 are as follows:

The Company has five executive employment agreements in existence at July 31, 2003 that provide for future aggregate base salaries as follows:

Under these agreements, the Company may also be required to pay bonuses in the event of a change in control and/or upon early termination of employment.

The Company’s corporate records state 8,000 shares of the Company’s common stock were issued to its founder on August 15, 1997 in exchange for $140 in the form of cash payments totaling $90 and personal property having a fair value of $50; however, the Company was unable to verify that all of this consideration was actually paid to the Company. Accordingly, on February 23, 2001, the Company’s Board of Directors instructed the Company’s management to reflect on the corporate stock records that only a portion of the shares issued the founder be recognized as validly issued.

Previously, at the time the Company entered into the severance agreement with the founder, the founder and the Company entered into an Accommodation Agreement pursuant to which 1,200 of the founders’ common shares were placed into an escrow account for a period of three years from which the Company could use shares to settle claims of former employees of the Company. At the end of the three year period, any shares remaining in the escrow account were to be released to the founder.

Subsequent to the actions described above, claims and counterclaims were filed by the Company and the founder. In August 2001, a settlement was reached with the founder and approved by the court having jurisdiction over the case. The material terms of the settlement provided that the Company pay the founder $4,790 in damages and an additional $2,400 to purchase 1,175 shares of the Company’s common stock claimed to be held by the founder. The settlement agreement also provided that the remaining 4,720 shares of the Company’s common stock claimed to be held by the founder were void. The Founder also agreed to release his claims to the shares of the Company’s common stock held by the Company pursuant to the Accommodation Agreement and to the Company’s obligation to him under a severance agreement. The founder also agreed that he would have no future ownership in the Company. The loss on the settlement of $4,790, which is net of the previously accrued severance payable to the founder of $928, was recorded as of July 31, 2001 and is included in general and administrative expenses for the year then ended.

In August 2001, Joseph P. Saline, one of the Company’s directors, filed a suit seeking access to all of the Company’s documents and records. The Company filed a cross-petition alleging that Mr. Saline unlawfully disseminated confidential information belonging to the Company, breached his confidentiality agreement with the Company, breached his fiduciary duty to the Company, and illegally tape recorded meetings and seeking, among other things, to limit Mr. Saline’s ability to distribute the corporate documents he was seeking. The trial court issued an order granting Mr. Saline access to certain documents, but prohibited Mr. Saline from disclosing or discussing the documents he requested with

anyone other than his attorney and other members of the Company’s Board of Directors. The Company provided Mr. Saline with copies of certain corporate documents under the protection of the court order. Mr. Saline filed an appeal, seeking to reverse the restrictions on his right to disclose or discuss the documents with third parties and to reverse the trial court’s limits on his inspection rights. On July 30, 2002, the California Court of Appeals reversed the order of the Superior Court that limited Mr. Saline’s ability to disseminate the documents. The Court of Appeals further granted Mr. Saline with access to all of the Company’s documents and records. The Court of Appeals also ordered that Mr. Saline shall recover the costs of his appeal from the Company. In March 2003, the court denied the Company’s motion for summary judgment with respect to the Company’s counter claims. In September 2003, the Company amended its cross-petition to add claims alleging that Mr. Saline committed libel and committed unfair business practices. These claims are based upon certain alleged actions by Mr. Saline in connection with certain purchases of the Company’s securities and statements Mr. Saline made regarding the proxy contest with respect to the Company’s 2001 annual meeting of shareholders. This case is currently pending.

In October 2001, Mr. Saline filed a civil claim against the Company alleging that the Company breached its contract to sell Mr. Saline preferred shares, is estopped to deny the rights and privileges of his preferred stock, unlawfully denied him his voting rights and committed unfair business practices. In his complaint, Mr. Saline alleged that he is the holder of 352 shares of preferred stock, with two-for-one conversion and voting rights that differ from the rights set forth in the Certificate of Determination for the Company’s Series A Preferred Stock filed with the California Secretary of State. Mr. Saline also has made claims for damages, including punitive damages. The Company filed an answer disputing Mr. Saline’s claims and filed a cross-complaint for declaratory relief. A trial was held in June 2003. On September 24, 2003, the court issued an order prohibiting the Company from refusing to recognize that Mr. Saline owns 352 of preferred stock, convertible into common stock and entitled to vote on a two-for-one basis. As a result, all such shares have been reflected in these financial statements as “Other convertible preferred stock”. The Company intends to appeal the court’s ruling. A second phase of the trial to consider Mr. Saline’s claims for damages is pending.

In February 2001, several former employees filed a lawsuit against the Company. The complaint was filed by David James and twelve other former employees who worked with David James in raising investment capital. The plaintiffs’ complaint had alleged claims for unfair business practices, breach of contract, and fraud and intentional deceit. The plaintiffs allege, in summary, that they were formerly employed by the Company and are owed commissions and stock options from the Company under their alleged employment agreements and based on alleged representations that were made to them by former Officers of Company in the course of their employment. The Company filed a cross-complaint asserting claims for breach of contract; unfair business practices; misappropriation of trade secrets; intentional interference with prospective economic advantage; negligent interference with prospective economic advantage; conversion; slander; prohibitory injunctive relief; mandatory injunctive relief; and declaratory relief which the Company dismissed without prejudice. In addition, the Company filed a first amended cross-complaint that asserted additional cross-claims against plaintiff David James for rescission and restitution, fraud, money had and received, unjust enrichment and declaratory relief. The plaintiffs sought, among other relief, damages in the amount of up to $10,000, plus costs and attorney fees. A jury trial was held in this matter beginning in October 2002. On December 10, 2002, the jury returned a verdict finding for the plaintiffs in the amount of $2,700 (accrued as of July 31, 2003) of compensatory damages. During trial, the Company voluntarily dismissed the Company’s cross-complaint without prejudice. In January 2003, the Company filed post-trial motions in the lawsuit filed against the Company by several former employees for a new trial and for a judgment notwithstanding the verdict, seeking to have the $2,700 verdict for the plaintiffs set aside. In March 2003, the court denied the Company’s post-trial motions for a new trial and for a judgment notwithstanding the verdict in the lawsuit filed against the Company by

several former employees. The Company filed a notice of appeal in March 2003, seeking reversal of the judgment in favor of the plaintiffs. On June 26, 2003, the court ruled that the Company was the prevailing party on the contract claims brought by the plaintiffs and that the Company was entitled to recover attorney’s fees and costs from the plaintiffs totaling approximately $1,100. The Company’s appeal is currently pending. The plaintiffs have also appealed the Court’s ruling awarding the Company attorney’s fees. In order to stay the enforcement of the judgment pending appeal, the Company posted an appellate bond of approximately $4,100. This bond was outstanding at July 31, 2003. In September 2003, a court ruling permitted the reduction of the bond to $2,600.

The Company currently is, and from time to time may become, involved in other litigation concerning claims arising out of the Company’s operations in the normal course of business. While the Company cannot predict the ultimate outcome of its pending matters or how they will affect the Company’s results of operations or financial position, the Company’s management currently does not expect any of the legal proceedings to which the Company is currently a party, including the legal proceedings described above, individually or in the aggregate, to have a material adverse effect on our results of operations or financial position beyond the accruals provided as of July 31, 2003.

On November 9, 2001, the Company purchased certain rights to hire employees and contractors of their primary information technology vendor, Symcas. Additionally, as part of the same agreement, Symcas transferred interest in and to all of the software that Symcas has developed for us. The purchase agreement contained a covenant not to compete prohibiting the principals of Symcas from competing with the Company’s software product or directly or indirectly assisting others to develop a software product similar to the Company’s software product for a period of two years. Symcas previously performed substantially all of the Company’s software development information technology support and maintenance, and procurement of hardware and software. On December 15, 2001, after the close of the agreement with Symcas, the Company hired Linda Guckert, an employee and officer of Symcas, to be the Company’s Vice President of Information Technology. Ms. Guckert and her husband continue to own a significant interest in Symcas. The Company continues to utilize Symcas on a limited basis for its information technology maintenance. The Company paid Symcas $2,091 and $577 in fiscal 2002 and 2003, respectively.

(1)

In the fourth quarter of fiscal 2003, the Company reclassified costs associated with the Pennsylvania gross receipts taxes which the Company deemed appropriate to reclassify to direct energy costs from general and administrative expenses. For the four quarters of fiscal 2002, the reclassifications were $105, $256, $328 and $454, respectively and in the first three quarters of fiscal 2003, the reclassifications were $726, $628 and $530, respectively.


(1)	Each of these exhibits is incorporated herein by reference to Commonwealth Energy Corporation’s Form 10 filed with the Securities and Exchange Commission on August 9, 2001 (File No. 000-33069).

(2)	Each of these exhibits is incorporated by reference to Commonwealth Energy Form 10/ A filed with the Securities and Exchange Commission on November 14, 2001 (File No. 000-33069).

(3)	This exhibit is incorporated herein by reference to Commonwealth Energy Corporation’s form 10-Q for the quarterly period ended January 31, 2003.

(4)	This exhibit is incorporated by reference to Commonwealth Energy Corporation’s Registration Statement on Form S-8 (File No. 333-109552) filed with the Securities and Exchange Commission on October 8, 2003.

(5)	Each of these exhibits is incorporated by reference to Commonwealth Energy Form 10-Q filed with the Securities and Exchange Commission on December 17, 2001 (File No. 000-33069).

(6)	Each of these exhibits is incorporated by reference to Commonwealth Energy Form 10/ A filed with the Securities and Exchange Commission on April 3, 2002 (File No. 000-33069).

(7)	Each of these exhibits is incorporated by reference to Commonwealth Energy Corporation’s Form 10-K for the year ended July 31, 2002 filed with the Securities and Exchange Commission on October 29, 2002.


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

For the fiscal year ended July 31, 2003

or

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

For the transition period from to


California		33-0769555
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)


PART I
	Item 1. Business.
	Item 1A.Executive Officers of the Registrant.
	Item 2.Properties.
	Item 3.Legal Proceedings.
	Item 4.Submission of Matters to a Vote of Security Holders.
PART II
	Item 5.Market for Registrant’s Common Equity and Related Stockholder Matters.
	Item 6.Selected Financial Data.
	Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operation.
	Item 7A.Quantitative and Qualitative Disclosures About Market Risk.
	Item 8.Financial Statements and Supplementary Data.
	Item 9.Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.
	Item 9A.Controls and Procedures.
PART III
	Item 10.Directors and Executive Officers of the Registrant.
	Item 11.Executive Compensation.
	Item 12.Security Ownership of Certain Beneficial Owners and Management.
	Item 13.Certain Relationships and Related Transactions.
	Item 14.Principal Accounting Fees and Services.
PART IV
	Item 15.Exhibits, Financial Statement Schedules and Reports on Form 8-K.
SIGNATURES
EXHIBIT 10.6
EXHIBIT 10.7
EXHIBIT 10.20
EXHIBIT 10.21
EXHIBIT 10.22
EXHIBIT 10.23
EXHIBIT 14.1
EXHIBIT 23.1
EXHIBIT 31.1
EXHIBIT 31.2
EXHIBIT 32.1
EXHIBIT 32.2


		Page

PART I
Item 1.	Business		1
Item 1A.	Executive Officers of the Registrant		8
Item 2.	Properties		10
Item 3.	Legal Proceedings		10
Item 4.	Submission of Matters to a Vote of Security Holders		12
PART II
Item 5.	Market for Registrant’s Common Equity and Related Stockholder Matters		12
Item 6.	Selected Financial Data		14
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operation		16
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		29
Item 8.	Financial Statements and Supplementary Data		30
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosures		30
Item 9A.	Controls and Procedures		30
PART III
Item 10.	Directors and Executive Officers of the Registrant		31
Item 11.	Executive Compensation		33
Item 12.	Security Ownership of Certain Beneficial Owners and Management		40
Item 13.	Certain Relationships and Related Transactions		41
Item 14.	Principal Accounting Fees and Services		42
PART IV
Item 15.	Exhibits, Financial Statement and Reports on Form 8-K		43
	Signatures		46


Item 5.	Market for Registrant’s Common Equity and Related Stockholder Matters.



		Fiscal Year Ended July 31

		1999			2000			2001		2002			2003


		(Amounts in thousands except per share information)
Consolidated Statement of Operations Data:
Net revenue		$	39,124		$	99,624		$	183,264	$	117,768		$	165,526
Direct energy costs			38,729			86,732			77,281		87,340			128,179

Gross profit			395			12,892			105,983		30,428			37,347
Other expenses(1)			18,518			21,921			25,195		21,918			24,947

Income (loss) from operations			(18,123	)		(9,029	)		80,788		8,510			12,400
Loss on litigation awards			(422	)		(116	)		—		—			(2,200	)
Loss on equity investments			—			—			—		(160	)		(567	)
Minority interest			—			—			—		—			187
Interest income, net			123			499			1,593		939			715

Income (loss) before provision for income taxes			(18,422	)		(8,646	)		82,381		9,289			10,535
Provision for income taxes			—			—			21,852		4,125			5,113

Net income (loss)(2)		$	(18,422	)	$	(8,646	)	$	60,529	$	5,164		$	5,422

Net income (loss) per common share(3)(4):
	Basic	$	(.84	)	$	(.30	)	$	2.06	$	.19		$	.19

	Diluted	$	(.84	)	$	(.30	)	$	1.77	$	.16		$	.18

Weighted-average shares outstanding(3)(4):
	Basic		21,905			28,795			29,385		27,482			27,424

	Diluted		21,905			28,795			34,152		31,536			30,236


(1)	Includes stock-based compensation charges (credits) of $5,718, $445, $1,080, $(743) and $0 in the fiscal years ended July 31, 1999, 2000, 2001, 2002 and 2003, respectively. See “Management’s Discussion and Analysis of Financial Condition and Results of Operation — Results of Operations” and Note 2 of the Notes to Consolidated Financial Statements, for further details.


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



			Payments due by period

			Less than				More than
Contractual Obligations	Total		1 year		1-3 years		3 years


	(dollars in thousands)
Electricity purchase contracts	$	154,079	$	90,022	$	64,057		—
Operating leases		862		693		169		—
Employment Agreements		2,408		1,491		917		—

Total	$	157,349	$	92,206	$	65,143		—



California	$	11.8 million
Pennsylvania	$	16.3 million
Michigan	$	9.3 million


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


Item 10.	Directors and Executive Officers of the Registrant.


			Director
Name	Age		Since		Principal Occupation and Other Information

Ian B. Carter		65		1999	Mr. Carter has been our Chairman and Chief Executive Officer since January 2000, and as our President since March 2003. During the preceding four month period prior to January 2000, he acted as Interim President. From October 1988 to August 1999, Mr. Carter operated his owned businesses, including a mortgage banking firm and a merchant banking firm. Prior to that, Mr. Carter served as an investment specialist for Coldwell Banker Commercial Brokerage and worked as a Systems Engineer and Salesman with IBM. Mr. Carter also served in the United States Army serving in Vietnam, Europe and the Pentagon. Mr. Carter received his Bachelor of Science degree in Engineering from the United States Military Academy at West Point, New York and his Master in Business Administration in finance from the University of Southern California.
Craig G. Goodman		53		2000	Mr. Goodman has served as the Chief Executive Officer of the National Energy Marketers Association, a national non-profit association representing a regionally diverse cross-section of wholesale and retail marketers of natural gas, electricity and energy-related products, services, information and technology, since October 1997. Mr. Goodman received his bachelor’s degree in economics with honors from the University of Maryland and a juris doctorate degree with a concentration in international corporate law and economics from the University of Miami School of Law.
Junona A. Jonas		59		2001	Ms. Jonas has been the General Manager of Alameda Power & Telecom, a municipal utility, since December 2000. From March 2000 to August 2000, she served as Chief Executive Officer of vetmedcenter.com, an online resource for veterinary information and services. From February 1999 to January 2000, Ms. Jonas was President and Chief Operating Officer of utility.com, an internet provider of energy and energy services to retail customers in states that have deregulated their electric industry. From July 1978 to February 1999, she served in various capacities at Pacific Gas & Electric (PG&E), a public utility, including serving as the first President and Chief Operating Officer of PG&E’s retail energy services subsidiary, Vantus Energy Corporation, and as Vice President, Gas and Electricity Supply. Ms. Jonas has a Bachelors degree from Santa Clara University and a Masters degree from Stanford and Cal State University Hayward.


	Number of
	Shares
	Underlying
	Options				Expiration
Name	Granted		Exercise Price		Date

Robert Perkins		100,000	$	2.75		8/29/2013
		50,000	$	2.75		8/29/2013
		50,000	$	1.86		8/29/2013
Craig Goodman		50,000	$	2.50		8/29/2013
		50,000	$	2.75		8/29/2013
		50,000	$	1.86		8/29/2013
Junona Jonas		50,000	$	2.50		8/29/2013
		50,000	$	2.75		8/29/2013
		50,000	$	1.86		8/29/2013
Mark Juergensen		37,250	$	1.86		8/29/2013


Item 2.	Properties.


Item 3.	Legal Proceedings.


	1999		2000		2001		2002		2003

Consolidated Balance Sheet Data:
Working capital	$	12,428	$	12,803	$	50,184	$	58,841	$	56,411
Total assets		27,858		35,444		107,016		101,229		125,870
Shareholders’ equity(4)		19,900		24,236		86,037		87,952		93,017


Item 9A.	Controls and Procedures.



											Long Term Compensation


		Annual Compensation									Awards		Payouts

								Other					Securities				All
								Annual			Restricted		Underlying				Other
		Fiscal						Compen-			Stock		Options/		LTIP		Compen-
Name and Principal Position		Year		Salary		Bonus(1)		sation			Award(s)		SARs		Payouts		sation

Ian B. Carter			2003	$	402,062	$	100,000	$	31,102	(2)		—		—		—		—
	Chief Executive Officer,		2002		314,988		495,000		62,553	(2)		—		3,800,000		—		—
	President and Chairman		2001		297,975		100,000		36,241	(2)		—		400,000		—		—
	of the Board
Richard L. Paulsen			2003		360,066		75,000		23,823	(3)		—		—		—		—
	Chief Operating Officer		2002		310,000		140,000		22,046	(3)		—		900,000		—		—
			2001		245,534		50,000		5,647	(3)		—		—		—		—
John A. Barthrop			2003		202,527		55,500		18,132	(4)		—		—		—	$	86,880	(5)
	General Counsel and Secretary		2002		182,016		55,500		16,203	(4)		—		500,000		—		—
			2001		145,366		40,000		10,406	(4)		—		—		—		—
James L. Oliver			2003		201,088		55,500		18,124	(6)		—		—		—		—
	Chief Financial Officer		2002		171,000		89,813		19,996	(6)		—		500,000		—		—
			2001		138,208		40,000		12,166	(6)		—		—		—		—
Linda L. Guckert			2003		153,642		20,000		10,878	(7)		—		—		—		—
	Vice President of Information		2002		89,410		—		3,331	(7)		—		—		—		—
	Technology		2001		—		—		—			—		—		—		—



					Number of Securities				Value of Unexercised
					Underlying Unexercised				In-the-Money
					Options/SARs at				Options/SARs at
			Value		Fiscal Year-End(#)				Fiscal Year-End($)(2)
	Shares Acquired		Realized
Name	on Exercise(#)		($)(1)		Exercisable		Unexercisable		Exercisable		Unexercisable

Ian B. Carter		—		—		2,750,000		1,450,000	$	142,000		—
Richard L. Paulsen		—		—		675,000		225,000		—		—
John A. Barthrop		48,000	$	86,880		375,000		125,000		—		—
James L. Oliver		—		—		375,000		125,000		—		—
Linda Guckert		—		—		—		—		—		—


Item 12.	Security Ownership of Certain Beneficial Owners and Management.



		Common Stock								Series A Convertible Preferred Stock(1)


		Amount and Nature of								Amount and Nature of
		Beneficial Ownership(2)								Beneficial Ownership(2)

		Number of								Number of
		Shares		Right to			Percent of			Shares		Right to		Percent of
Name		Owned(3)		Acquire(4)			Class			Owned(3)		Acquire		Class

Principal Stockholders:
	Ian B. Carter		50,000		2,750,000			9.2	%		—		—		—
Directors and Named Executive Officers:
	Ian B. Carter		50,000		2,750,000			9.2	%		—		—		—
	Craig G. Goodman		—		137,500			*			—		—		—
	Junona A. Jonas		—		137,500			*			—		—		—
	Robert C. Perkins		177,000		337,500	(5)		1.8	%		25,000		—		4.1	%
	Joseph P. Saline, Jr.		—		704,000	(6)		2.5	%		—		—		—
	Mark S. Juergensen		—		25,000			*			—		—		—
	Richard L. Paulsen		—		675,000			2.4	%		—		—		—
	John A. Barthrop		50,000		375,000			1.5	%		—		—		—
	James L. Oliver		—		375,000			1.3	%		—		—		—
	Linda Guckert		5,000		25,000			*			—		—		—
All Directors and Executive Officers as a group (13 persons)			282,000		5,829,000	(7)		18.3	%		25,000		—		4.1	%


*	Indicates beneficial ownership of less than 1% of the issued and outstanding class of securities.


(1)	Represents shares of common stock that may be issued pursuant to outstanding options granted under the 1999 Equity Incentive Plan.

(2)	Represents shares of common stock that may be issued pursuant to options available for future grant under the 1999 Equity Incentive Plan.

(3)	Represents stock options granted by our Board of Directors to various employees, directors and consultants pursuant to stand-alone agreements and not pursuant to any plan.



	Fiscal Year

	2002		2003

Audit Fees	$	300,420	$	326,898
Audit-Related Fees		—		—
Tax Fees		93,900		130,263
All Other Fees		—		22,594

	$	394,320	$	479,755


Item 15.	Exhibits, Financial Statement Schedules and Reports on Form 8-K.


Report of Ernst & Young LLP, independent auditors		F-1
Consolidated statements of income for the three years in the period ended July 31, 2003		F-2
Consolidated balance sheets at July 31, 2002 and 2003		F-3
Consolidated statements of shareholders’ equity for the three years in the period ended July 31, 2003		F-4
Consolidated statements of cash flows for the three years in the period ended July 31, 2003		F-5
Notes to consolidated financial statements		F-6


Exhibit
Number		Title of Exhibit

	3.1	Articles of Incorporation of Commonwealth Energy Corporation dated August 14, 1997 and filed with the Secretary of State of the State of California on August 15, 1997(1)
	3.2	Certificate of Amendment of Articles of Incorporation of Commonwealth Energy Corporation dated December 31, 1998 and filed with the Secretary of State of the State of California on February 19, 1999(1)
	3.3	Certificate of Determination of Commonwealth Energy Corporation dated September 22, 1997 and filed with the Secretary of State of California on March 13, 1998(2)
	3.4	Bylaws of Commonwealth Energy Corporation, as amended(3)
Material Contracts Relating to Management Compensation Plans or Arrangements
	10.1	Employment Agreement dated January 1, 2000, between Commonwealth Energy Corporation and Ian B. Carter, as modified by an Addendum to Employment Agreement dated as of November 1, 2000(1)
	10.2	Employment Agreement dated November 1, 2000, between Commonwealth Energy Corporation and Richard L. Paulsen(2)
	10.3	Employment Agreement dated November 1, 2000, between Commonwealth Energy Corporation and James L. Oliver(2)
	10.4	Employment Agreement dated November 1, 2000, between Commonwealth Energy Corporation and John A. Barthrop(2)
	10.5	Commonwealth Energy Corporation 1999 Equity Incentive Plan(4)
	10.6	Employment Letter dated December 7, 2001 for Linda Guckert
	10.7	Employment Agreement dated between Commonwealth Energy Corporation and Michael G. Nelson



Dated: October 29, 2003	COMMONWEALTH ENERGY CORPORATION
	By:	/s/ IAN B. CARTER

		Ian B. Carter
		Chairman of the Board, President and Chief Executive Officer



Signature	Title	Date



/s/ IAN B. CARTER Ian B. Carter	Chairman of the Board, President, Chief Executive Officer and a Director (Principal Executive Officer)	October 29, 2003


/s/ JAMES L. OLIVER James L. Oliver	Chief Financial Officer (Principal Financial Officer)	October 29, 2003


/s/ KENNETH L. ROBINSON Kenneth L. Robinson	Vice President — Finance and Controller (Principal Accounting Officer)	October 29, 2003

/s/ CRAIG G. GOODMAN Craig G. Goodman	Director	October 29, 2003

/s/ MARK S. JUERGENSEN Mark S. Juergensen	Director	October 29, 2003

/s/ JUNONA A. JONAS Junona A. Jonas	Director	October 29, 2003

/s/ ROBERT C. PERKINS Robert C. Perkins	Director	October 29, 2003

Joseph P. Saline, Jr.	Director



		Fiscal Year Ended July 31,

		2001		2002			2003

Net revenue		$	183,264	$	117,768		$	165,526
Direct energy costs			77,281		87,340			128,179

Gross profit			105,983		30,428			37,347
Selling and marketing expenses			3,597		3,510			4,240
General and administrative expenses			21,598		18,408			20,707

Income from operations			80,788		8,510			12,400
Loss on litigation award			—		—			(2,200	)
Loss on equity investments			—		(160	)		(567	)
Minority interest			—		—			187
Interest income, net			1,593		939			715

Income before provision for income taxes			82,381		9,289			10,535
Provision for income taxes			21,852		4,125			5,113

Net income		$	60,529	$	5,164		$	5,422

Earnings per common share:
	Basic	$	2.06	$	0.19		$	0.19

	Diluted	$	1.77	$	0.16		$	0.18



			July 31,

			2002		2003

Current assets:
	Cash and cash equivalents		$	43,042	$	40,921
	Accounts receivable, net			21,340		37,861
	Prepaid income taxes			1,921		—
	Deferred income tax asset			1,850		2,772
	Prepaid expenses and other current assets			3,965		6,920

		Total current assets		72,118		88,474
Restricted cash and cash equivalents				14,186		20,773
Investments				7,453		5,362
Deposits				371		4,207
Property and equipment, net				3,912		2,984
Goodwill				—		3,007
Intangible assets				1,070		1,063
Deferred income tax assets				2,119		—

		Total assets	$	101,229	$	125,870

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
	Accounts payable		$	8,969	$	24,936
	Accrued liabilities			4,308		7,127

		Total current liabilities		13,277		32,063
Deferred income tax liabilities				—		187

		Total liabilities		13,277		32,250
Minority interest				—		603
Shareholders’ equity:
	Series A convertible preferred stock — 10,000 shares authorized with no par value; 775 and 609 shares issued and outstanding in 2002 and 2003, respectively			820		700
	Other convertible preferred stock — 352 shares reflected as outstanding in 2003			—		155
	Common stock — 50,000 shares authorized with no par value; 27,334 and 27,645 shares issued and outstanding in 2002 and 2003, respectively			57,148		56,853
	Retained earnings			29,984		35,309

		Total shareholders’ equity		87,952		93,017

		Total liabilities and shareholders’ equity	$	101,229	$	125,870



							Series A						Other
							Convertible						Convertible				Retained
	Common Stock						Preferred Stock						Preferred Stock				Earnings
																	(Accumulated
	Shares			Amount			Shares			Amount			Shares		Amount		Deficit)			Total

Balance at July 31, 2000		29,333		$	58,740			939		$	1,054			—		—	$	(35,558	)	$	24,236
Exercise of stock options		103			6			—			—			—		—		—			6
Compensation charge related to settlement of employee stock option disputes		—			140			—			—			—		—		—			140
Compensation charge related to performance-based stock options		—			1,080			—			—			—		—		—			1,080
Income tax benefits arising from exercise of stock options		—			339			—			—			—		—		—			339
Cumulative unpaid dividends on convertible preferred stock		—			—			—			81			—		—		(81	)		—
Payment of dividends on preferred stock		—			—			—			(217	)		—		—		—			(217	)
Repurchase of preferred stock		(76	)		—			(76	)		(76	)		—		—		—			(76	)
Net income and comprehensive income		—			—			—			—			—		—		60,529			60,529

Balance at July 31, 2001		29,360			60,305			863			842			—		—		24,890			86,037
Exercise of stock options		65			27			—			—			—		—		—			27
Compensation charge related to settlement of employee stock option disputes		—			2			—			—			—		—		—			2
Compensation charge related to performance-based stock options		—			(743	)		—			—			—		—		—			(743	)
Repurchase of founder’s shares		(1,175	)		(2,400	)		—			—			—		—		—			(2,400	)
Cancellation and return of founder’s accommodation shares		(828	)		—			—			—			—		—		—			—
Income tax benefits arising from exercise of stock options		—			(43	)		—			—			—		—		—			(43	)
Cumulative unpaid dividends on convertible preferred stock		—			—			—			70			—		—		(70	)		—
Payment of dividends on preferred stock		—			—			—			(30	)		—		—		—			(30	)
Repurchase of preferred stock		(88	)		—			(88	)		(62	)		—		—		—			(62	)
Net income and comprehensive income		—			—			—			—			—		—		5,164			5,164

Balance at July 31, 2002		27,334			57,148			775			820			—		—		29,984			87,952
Exercise of stock options		483			15			—			—			—		—		—			15
Cancellation of common shares		(6	)		(14	)		—			—			—		—		—			(14	)
Income tax benefits arising from exercise of stock options		—			363			—			—			—		—		—			363
Reversal of income tax benefit due to expiration of stock options		—			(659	)		—			—			—		—		—			(659	)
Cumulative unpaid dividends on convertible preferred stock		—			—			—			55			—		42		(97	)		—
Payment of dividends on Series A convertible preferred stock		—			—			—			(92	)		—		—		—			(92	)
Reflection of — Other convertible preferred stock(a)		—			—			—			—			352		113		—			113
Cancellation of Series A convertible preferred stock		(166	)		—			(166	)		(83	)		—		—		—			(83	)
Net income and comprehensive income		—			—			—			—			—		—		5,422			5,422

Balance at July 31, 2003		27,645		$	56,853			609		$	700			352	$	155	$	35,309		$	93,017


(a)	Reflects 352 shares of Other convertible preferred stock recognized pursuant to court order. See Notes 12 and 14.


		Date of	Current		Current
		Initial	Investment		Ownership
Investee		Investment	Basis		Percentage

Envenergy, Inc.		October 2001	$	2,030		8.68%
Turbocor, BV		January 2002		3,332		8.76%
Power Efficiency Corporation		June 2002		—		52.8%

	Total investments		$	5,362


Reserved for potential conversion of outstanding Series A convertible preferred stock			609
Reserved for potential conversion of deemed outstanding other convertible preferred stock			704
Reserved for potential exercise of outstanding stock options			7,489

			8,802



		Options Outstanding

									Weighted-
									Average
							Weighted-		Fair Value
		Number of			Exercise Price		Average		of Common
		Shares			Per Share		Exercise Price		Stock

Balance at July 31, 2000.			9,250			$0.01 - $3.75	$	1.47
Options granted:
	Employee performance-based(1)		300			2.50		2.50	$	2.75
	Other employees(2)		2,500			2.75		2.75	$	2.75
	Outside directors(2)		150			2.75		2.75	$	2.75
Options exercised			(67	)		0.01 - 1.00		0.07
Options cancelled			(1,850	)		0.01 - 3.75		1.72

Balance at July 31, 2001.			10,283			0.01 - 3.75		1.79
Options granted:
	Other employees(1)		5			1.00 - 3.75		2.22	$	3.13
	Employee performance-based(2)		300			2.50		2.50	$	2.38
Options exercised			(52	)		0.01 - 1.00		0.50
Options cancelled			(46	)		0.05 - 3.75		1.04

Balance at July 31, 2002.			10,490			0.01 - 3.75		1.82
Options granted:
	Employee performance-based		300			2.50		2.50	$	2.50
	Other employees(2)		325			1.86 - 3.05		1.93	$	1.86
Options exercised			(482	)		0.01 - 1.00		0.03
Options cancelled			(403	)		2.50 - 2.75		2.50
Options expired			(2,741	)		0.01 - 1.00		0.22

Balance at July 31, 2003.			7,489			$0.50 - $3.75	$	2.55


			Average
Range of	Number of		Remaining				Weighted
Exercise	Shares		Contractual		Shares		Average
Prices	Outstanding		Life (Years)		Exercisable		Exercise Price

$0.01 - $0.5		0 100		0.4		100	$	0.50
$1.00 - $1.8		6 429		7.1		279		1.48
$2.50 - $3.7		5 6,960		4.7		4,865		2.66

Total		7,489		4.8		5,244	$	2.55