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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Form 10-K

Commission File Number 001-32239

Commerce Energy Group, Inc.

600 Anton Boulevard, Suite 2000, Costa Mesa California 92626

Registrant’s telephone number, including area code

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act:

      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 þ     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 þ

      The aggregate market value of the voting and non-voting common equity held by non-affiliates as of January 31, 2004, the last business day of the registrant’s most recently completed second fiscal quarter, cannot be determined because there was no market for the registrant’s shares at that date.

      As of November 11, 2004, 30,519,290 shares of the Registrant’s common stock were outstanding.

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EXPLANATORY NOTE

      Commerce Energy Group, Inc., a Delaware corporation (the “Registrant”), is the successor to Commonwealth Energy Corporation, a California corporation (the “Predecessor”), following consummation of a reorganization which was undertaken to effect the reorganization of the Predecessor into a Delaware holding company structure whereby the Predecessor became a wholly-owned subsidiary of the Registrant. Upon consummation of the Reorganization, the entire class of common stock, $0.001 par value per share of the Registrant became registered under Section 12(g) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), in accordance with Rule 12g-3(a) thereunder. The Registrant filed a registration statement with the U.S. Securities and Exchange Commission (the “Commission”) with respect to its common stock and related preferred stock purchase rights under Section 12(b) of the Exchange Act on Form 8-A on July 6, 2004, and a new Exchange Act file number (File No. 001-32239) was issued, replacing the Predecessor’s file number (File No. 000-33069), for use in periodic filings required under the Exchange Act and the rules and regulations thereunder.

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FORWARD-LOOKING STATEMENTS

      You should carefully consider the risk factors described below, as well as the other information included in this Annual Report on Form 10-K prior to making a decision to invest in our securities. The risks and uncertainties described below are not the only ones facing our company. Additional risks and uncertainties not presently known or that we currently believe to be less significant may also adversely affect us. Unless the context requires otherwise, references to “the Company,” “we,” “us,” and “our” refer specifically to Commerce Energy Group, Inc. and its subsidiaries.

      On one or more occasions, we may make statements regarding our assumptions, projections, expectations, targets, intentions or beliefs about future events. All statements other than statements of historical facts included in this Annual Report on Form 10-K relating to expectation of future financial performance, continued growth, changes in economic conditions or capital markets and changes in customer usage patterns and preferences, are forward-looking statements.

      Words or phrases such as “anticipates,” “believes,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” “targets,” “will likely result,” “will continue,” “may,” “could” or similar expressions identify forward-looking statements. Forward-looking statements involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed. We caution that while we make such statements in good faith and we believe such statements are based on reasonable assumptions, including without limitation, management’s examination of historical operating trends, data contained in records and other data available from third parties, we cannot assure you that our expectations will be realized.

      In addition to the factors and other matters discussed under the caption “Factors That May Affect Future Results” in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in this Annual Report on Form 10-K, some important factors that could cause actual results or outcomes for Commerce Energy Group, Inc. or our subsidiaries to differ materially from those discussed in forward-looking statements include:

	•	regulatory changes in the states in which we operate that could adversely affect our operations;
	•	our continued ability to obtain and maintain licenses from the states in which we operate;
	•	the competitive restructuring of retail marketing may prevent us from selling electricity in certain states;
	•	our dependence upon a limited number of third parties that generate and supply us electricity;
	•	fluctuations in market prices for electricity;
	•	our dependence on the Independent System Operator in each of the states where we operate, to properly coordinate and manage their electric grids, and to accurately and timely calculate and allocate the charges to the participants for the numerous related services provided;
	•	our ability to obtain credit necessary to support future growth and profitability; and
	•	our dependence upon a limited number of local electric utilities to transmit and distribute the electricity we sell to our customers.

      Any forward-looking statement speaks only as of the date on which such statement is made, and, except as required by law, we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all such factors.

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PART I

Overview

      Commerce Energy Group, Inc., (“Commerce Energy or Commerce”), is a diversified energy services company. We provide retail electric power to our residential, commercial, industrial and institutional customers, provide consulting and technology services to energy-related businesses and provide energy transaction data management services. Commerce Energy is a holding company that operates through its wholly-owned operating subsidiaries: Commonwealth Energy Corporation, doing business as electricAmerica, (“electricAmerica”, “Commonwealth” or “Commonwealth Energy,”) Skipping Stone Inc., (“Skipping Stone,”) and UtiliHost, Inc., (“UtiliHost.”)

      Commerce operates through the following wholly-owned subsidiaries:

      electricAmerica provides electric power to our residential, commercial, industrial and institutional customers in the deregulated California, Pennsylvania, Michigan and New Jersey electricity markets. Commonwealth Energy is licensed by the Federal Energy Regulatory Commission, or FERC, as a power marketer. In addition to the states in which electricAmerica currently operates, Commonwealth Energy is also licensed to supply retail electric power by applicable state agencies in New York, Maryland, Texas and Ohio.

      Skipping Stone, which we acquired in April 2004, provides energy-related consulting services and technologies to utilities, electricity generators, natural gas pipelines, wholesale energy merchants, energy technology providers and investment banks.

      UtiliHost provides managed back office services and energy transaction data management services to electricAmerica.

Company History

      Commerce Energy Group’s predecessor, Commonwealth Energy, was formed in California in August 1997. On July 6, 2004, Commonwealth reorganized into a holding company structure, whereby Commonwealth became a wholly-owned subsidiary of Commerce Energy and the stockholders of Commonwealth became stockholders of Commerce.

      As a result of the reorganization, (a) each issued and outstanding share of common stock of Commonwealth was exchanged, subject to exercise of dissenters’ rights by the Commonwealth’s stockholders, for a share of Common Stock, par value $0.001 per share, of Commerce Energy (“Commerce Common Stock”) and a right to purchase (each, a “Right”) one one-hundredth of a share of Series A Junior Participating Preferred Stock, par value $0.001 per share, of Commerce (“Junior Participating Preferred”) and (b) Commerce assumed the Commonwealth’s 1999 Equity Incentive Plan (the “Plan”), all outstanding obligations to issue common stock under the Plan and all outstanding stock options issued outside the Plan. The stockholders of Commerce hold the same relative percentage of Commerce common stock as they owned of Commonwealth common stock immediately prior to the reorganization, subject to the exercise of dissenters rights.

      Immediately prior to consummation of the reorganization, Commonwealth transferred ownership of the following four subsidiaries to Commerce Energy: Skipping Stone Inc., electricAmerica, Inc., UtiliHost, Inc., and electric.com, Inc. As a result of the transfer, these entities became subsidiaries of Commerce Energy. Commonwealth also contributed its TACT (Trans-Action Control Technology) and TRIUMPH (Total

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      Commerce was incorporated in the State of Delaware on December 18, 2003. Our executive offices are located at 600 Anton Boulevard, Suite 2000, Costa Mesa California 92626. Our telephone number is (714) 259-2500.

Industry Background

      Beginning in 1992, the U.S. electric utility industry began a process of deregulation, which primarily served to unbundle generation, transmission, distribution and ancillary services into separate components. In 1996, some states, and some of the utilities within those states, proceeded to allow their end-use customers direct access to marketers enabling them to purchase electricity from an entity other than the host or local utility in a competitive retail market. These proceedings created a new market participant known as Electricity Service Providers, or ESPs, such as Commerce. Presently, twenty-four states and the District of Columbia have either enacted enabling legislation or issued regulatory orders to proceed with retail access.

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

      The electricity distribution infrastructure in place prior to deregulation remains largely unchanged, with the primary difference being that parties other than the local utility can utilize the delivery infrastructure by paying usage fees. ESPs use this established electricity network for the delivery of energy to their customers.

      Most electricity grids and wholesale market clearing activities are managed by a third party entity known as an Independent System Operator, or ISO, or regional transmission organization. The ISO is responsible for system reliability and ensures that physical electricity transactions between market participants are managed in such a way as to assure proper electricity reserve margins are in place, grid capacity is maintained, and supply and demand are in near perfect balance in real time.

      Retail electric marketers procure power supplies for delivery to end-use customers from a variety of wholesale power producers or merchant generation companies, either through term bilateral contracts or on a spot basis. In addition, short term daily or hourly supply requirements can be purchased or sold though the balancing markets operated by the ISO. The physical distribution of electricity to retail customers remains the responsibility of the local utility, which collects fees for use of its systems. Some states also enable the utility to provide additional services, such as reading meters, generating customer bills, collecting bills and taking requests for service changes or problems, while in other states the utility is not allowed, or chooses not to perform these services.

Core Products and Services

      Our primary business is retail sales of electricity to end-use customers under the brand name electricAmerica through our subsidiary Commonwealth Energy. We also provide consulting and technology professional services to utilities, electricity generators, wholesale energy merchants, and energy technology companies through our subsidiary, Skipping Stone. Additionally, our subsidiary, UtiliHost, offers energy commodity data transaction services utilizing its proprietary technologies and business processes.

      We engage in one industry segment. For information regarding our sales, operating profits and assets, see the financial statements included in Part II, Item 8 of this report, “Financial Statements and Supplementary Data.”

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      We offer electric service to customers under month-to-month, one year, or longer-term service contracts. The difference between the customers’ purchase price for energy and the sum of our wholesale electricity purchase costs and ancillary services costs provide us with a gross margin.

      All of the power we sell to our customers is purchased from third party power generators under long-term contracts and in the spot market. We do not own electricity generation facilities with the exception of small experimental renewable energy assets. The electric power we sell to end-user customers is metered and delivered to our customers by the local incumbent electric Utility Distribution Companies, or UDCs, or local utilities. The UDCs measure electric power usage, bill and collect for their distribution charges, and bill and collect our charges for electric commodity from most of our customers on our behalf. The Company does not have open lines of credit for direct unsecured borrowings or for letters of credit. Credit terms from our suppliers of electricity often require us to post collateral to support our energy purchases and to support our mark-to-market exposure with certain of our suppliers. We currently finance these collateral obligations with our available cash. To enable load shaping and balancing for our retail customer portfolio, we also buy and sell surplus electric power from and to other market participants when necessary.

      Electricity is a real-time commodity. As soon as it is produced, it must be simultaneously delivered into the grid to meet the demand of end users as it cannot be stored. We must effectively manage our purchased electricity supply and our customer demand to maintain profitability. We also manage the load shaping activity required by the variable electricity usage patterns of our retail customers; therefore, we may hold long or short energy positions. A long position occurs when we have committed to purchase 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. In both situations, we utilize the wholesale electricity spot market and ISO clearing markets to sell excess energy when we are long, and buy additional electricity when we are short. It would be impossible to completely hedge every delivery hour for all customers, therefore we will always have some exposure to volatility in wholesale market electric power price movement.

      Purchases and sales in the wholesale market are regulated by FERC, and we report on a regular basis to the U.S. Department of Energy. Weather, generation capacity, transmission, distribution and other market and regulatory issues also are significant factors in determining our wholesale procurement and sale strategies in each of the markets we serve.

      Skipping Stone offers a number of related professional consulting services and technologies to energy companies, such as utilities, electricity generators, natural gas pipelines, wholesale energy merchants, energy technology providers and investment banks. Skipping Stone is focused on assisting clients with business process improvements, market research, training, Sarbanes-Oxley process level implementations, systems design and selection, and strategic and tactical planning for new market or merger activities. Additionally, through Skipping Stone’s technology center, the Company provides natural gas pipeline information to market participants and government customers through its capacitycenter.com service.

      To provide managed back office services and transaction data management, we developed and offer proprietary software and service products TACT^TM (Trans-Action Control Technology) and TRIUMPH^TM (Total Resource Internet Utility Management Power Host). TACT^TM acts as a data translator between trading partners, 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. Currently, UtiliHost is providing services directly to electricAmerica for use in connection with electricAmerica’s electric service business. In the future, UtiliHost also intends to offer services directly to third party customers.

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Investments

      We have investments in three energy technology companies: Encorp Inc. (formerly known as Envenergy, Inc.), Turbocor B.V. and Power Efficiency Corporation.

      Encorp Inc., or Encorp, is a developer of software and hardware for energy and facility management that enables energy usage and cost information to be gathered and disseminated for the benefit of its customers. As of July 31, 2004, we owned approximately 2.3% of Encorp.

      Turbocor B.V., or Turbocor, is a manufacturer of energy efficient compressors for commercial heating, air conditioning, and refrigeration applications. As of July 31, 2004, we owned approximately 9.3% of Turbocor.

      Power Efficiency Corporation, or PEC, markets its own brand of induction motor efficiency products that enhances motor performance and reduces energy consumption. As of July 31, 2004, we owned approximately 39.9% of PEC.

      These investments were originally held by Summit Energy Ventures, LLC, or Summit, which we formed in July 2001. Our initial (and only) capital contribution to Summit was $15 million. In April 2004, we reached an agreement with Summit’s investment manager, Northwest Power Management, or NPM, to terminate our relationship. As a result of the transaction and after April 30, 2004, the Company no longer retained an equity interest in or contractual relationship with Summit. After May 1, 2004, we retained direct ownership in the investments in the three portfolio companies previously held by Summit. Under the terms of the termination agreement, we retained the entire interests in Encorp and Turbocor previously held by Summit, and retained a portion of the interest in PEC that was previously held by Summit and not distributed to NPM in the settlement. We will no longer consolidate the financial results of PEC in our consolidated financial statements due to the reduction in our ownership percentage as part of the termination agreement. (See Note 9 of Notes to Consolidated Financial Statements).

Growth Initiatives

      We are working to broaden the scope of the energy-related products and services we provide to include natural gas, energy efficiency offerings, and additional outsourced services. Additionally, we are evaluating expansion of our core products and services into new deregulated markets and targeted customer classes. We expect to accomplish our growth objectives through a combination of organic growth initiatives, mergers and acquisitions, and joint ventures.

      Currently, we actively market electricity in six UDC markets within California, Pennsylvania, Michigan and New Jersey. There are over twenty additional potential UDC markets that are open for direct access sales to end-use customers for both electricity and natural gas. We are evaluating each market to determine which are most advantageous to enter. We are also exploring opportunities to acquire existing portfolios of customers in targeted markets.

      We are evaluating offering natural gas to our retail electric customers in the markets we currently serve in California, Pennsylvania, Michigan and New Jersey. All of these markets are currently open for direct access purchasing of natural gas from retail marketers. Our intent is either to develop this business organically or acquire an existing natural gas marketing business with infrastructure already in place.

      We plan to offer a variety of energy efficiency products and services to our retail customers to assist them in better managing their energy loads. These offerings may include both hardware and facility management technologies and services. Our intent is to either partner with or acquire companies who are already

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      We began expanding our outsourced services through Commonwealth under the brand name electricAmerica, to target load aggregation opportunities in September 2002, enabling California cities and counties to establish Community Choice Aggregation programs. Such programs allow cities and counties to aggregate their residential, commercial, industrial and municipal electric service customers into portfolios that can be supplied electric generation from ESPs and other non-utility providers. We market 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. We also market similar services for major commercial and industrial customers to meet their electricity demand requirements. The focus of the outsourced services strategy is to both leverage our core skills and technologies, and to diversify along the energy value chain with complimentary product offerings.

Our Customers and Markets

      Currently, electricAmerica is actively selling electricity to customers in California, Pennsylvania, Michigan and New Jersey. We are also licensed to sell electricity in New York, Maryland, Texas and Ohio; however, we are not currently supplying customers in those markets. Our targeted customers include small and medium size businesses. We also serve residential customers in most markets. As of July 31, 2004, we are serving approximately 102,000 customers across all markets. We do not depend upon any one customer or a few major customers.

      Skipping Stone is currently engaged by over 100 clients under master agreements, with approximately 20 active engagements in any given month. Clients include utilities, wholesale energy merchants, natural gas pipelines companies, electricity generators, energy producers, and investment companies. The majority of our clients are based in North America with international clients from Japan, Korea, India, France, Canada and the United Kingdom.

      Currently, UtiliHost does not have any active customers; however, there are several potential opportunities under development. We have realized significant savings by utilizing the UtiliHost technologies in our own operations, which has helped us to avoid large expenditures for third party software and services.

Electricity Supply

      We maintain a balanced portfolio of long term power purchases using industry standard bilateral contracts with a variety of wholesale suppliers ranging from one to two years through May 2006. We do not own generation assets, with the exception of small experimental renewable energy assets. Additionally, we buy and sell incremental volumes of electricity in the short-term or spot wholesale markets as necessary to manage load shaping to balance our electricity supply with our customers’ load requirements. We are not substantially dependent on any one supplier.

      Wholesale electricity is readily available from various sources in each of the markets in which we have customers. Based upon current information from our suppliers, we do not anticipate any shortage of supply. However, in the event of a supply shortage, there can be no assurance that we would be able to timely secure an alternative supply of electricity at prices comparable to our current long-term contracts, and the failure to replace a supplier in a timely manner at comparable prices could materially harm our operations.

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      We employ industry standard risk management policies and procedures to control and monitor the risks associated with volatile commodity markets and to assure a balanced portfolio within tight risk tolerances.

Sales and Marketing

      We market and sell supplies of electricity to end-use customers in the states of California, Pennsylvania, Michigan and New Jersey. A variety of approaches are utilized in acquiring customers, including both inside and outside sales forces, consulting channels, web site enrollments and traditional marketing campaigns.

      The vast majority of our customers are acquired through our inside sales team, or contact center, which handles inbound calls from customers and makes outbound calls to targeted customers. Our contact center is responsible for procuring orders from smaller 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 outside sales team, Commercial and Industrial, or C&I Sales, is responsible for targeting medium and large commercial, industrial and institutional customers. Customers acquired by our C&I Sales enter into individualized written contracts. For this reason, the sales cycle is typically longer because the deal size is large and requires customized proposals to meet the customer’s needs. C&I Sales also works with third party energy consultants who procure energy supplies on behalf of commercial and industrial 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 application forms online, send us automated inquiries or helps customers find our toll-free telephone number, 1-800-ELECTRIC®.

      Traditional marketing campaigns, such as direct mail, billboards, trade show participation, and targeted market research are all designed to facilitate customer acquisition. We continually refine our marketing methodologies to target favorable customers based on changes in the electric marketplace.

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

	•	Selectively enter 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.
	•	Capitalize on the brand recognition of electricAmerica through our web site at www.electricAmerica.com and through our inbound toll-free number, 1-800-ELECTRIC.
	•	Take 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.
	•	Develop strategic marketing alliances with established power suppliers to offer competitive electric products and services to targeted markets and customers.
	•	Offer additional products and services to our customers, such as risk management pricing alternatives, outsourced services, consulting services, and, eventually, energy efficiency products and services.

Competition

      In markets that are open to competitive choice of suppliers, there are generally three types of competitors, the local utilities, retail marketers and wholesale merchants. Competition is based primarily on price and customer service.

      In general, we believe our principal competitor in each market is the local utility or unregulated utility affiliate, primarily because the local utilities are usually already serving the customer. Increasing our market

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      Among the retail marketers and wholesale merchants, competition is most intense for the larger volume customers, such as large commercial and industrial accounts. Our target customers are the medium and smaller businesses, in which we rarely experience competition from the wholesale merchants, and in most markets, there are typically only two or three other retail marketers actively targeting the same accounts.

      Most customers who switch from the local utility do so for an economic benefit. Once switched, customer retention is based on continuing competitive pricing, reliability of supply and customer service. Our customer service record has enabled us to maintain a high customer retention rate.

      Some of our competitors, including local utilities, have formed alliances and joint ventures in order to compete in the restructured retail electricity industry. Many customers of these local 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 local utilities and their affiliates for customers who are satisfied with their historical utility provider.

      In addition to competition from the local 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.

      We face competition in selling consulting and outsourced services from a large variety of companies. These competitors may be engaged in the energy business, as we are, or from national and international management and information technologies firms.

Seasonality

      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 are historically higher in the summer months for cooling purposes, followed by the winter months for heating and lighting purposes. Typically, fall and spring months volumes are modest due to the reduced demand for cooling or heating.

Governmental Regulation

      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. We are subject to regulation by the PUC in each state in which we sell 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, Pennsylvania,

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      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.

      On September 20, 2001, the California PUC 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 the local utilities. This ruling permits retail electricity suppliers to keep their current customers and to solicit direct access customers served by other providers, but prohibits us from signing up new non-direct access customers in California for an undetermined period of time.

Employees

      As of July 31, 2004, we employed approximately 173 full-time and 2 part-time employees, including: 32 in administration, 16 in marketing and sales, and 127 in operations. None of our employees are covered by a collective bargaining agreement or are presently represented by a labor union. We have not experienced any work stoppages and consider our employee relations to be good.

Intellectual Property

      Intellectual property assets include our proprietary software and service products (TACT and TRIUMPH), our 1-800-Electric telephone number and rights to our internet domain names (electric.com and electricAmerica.com). Also in fiscal 2004, we acquired Skipping Stone’s customer list, software and website. We believe that each of our intellectual property assets offer us strategic advantages in our operations. Their useful lives range from two to 20 years.

      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 fees are paid and trademarks are continually used or licensed by us.

Information About Our Executive Officers

      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 22, 2004. Executive officers are elected by, and serve at the pleasure of, the Board of Directors.

      On November 11, 2004, a Special Committee of the Board of Directors of Commerce placed Mr. Carter, Chairman of the Board and Chief Executive Officer of Commerce and Commonwealth, on paid administrative leave, which will continue for an indefinite period not to exceed the remainder of the term of Mr. Carter’s employment agreement ending on January 31, 2005. Peter Weigand, President of Commerce and Commonwealth, will assume the duties of the principal executive officer of Commerce and its affiliated entities until the Board of Directors appoints a successor to Mr. Carter, subject to certain limitations imposed by the Special Committee of the Board of Directors. As part of these duties, Mr. Weigand will act as the “principal executive officer” of Commerce for purposes of all filings with the Securities and Exchange Commission under the Securities Act of 1933, as amended, and the Securities Exchange Act of 1934, as amended.

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      Our principal executive office is located in Costa Mesa, California. This facility houses our administration and operations. We lease approximately 38,677 square feet of office space at these premises pursuant to a sub-lease that expires on September 6, 2009.

      We also lease approximately 2,265 square feet of additional office space in Cherry Hill, New Jersey under a lease that expires in August 2005.

      In addition to the Commerce offices, Skipping Stone has offices in Boston, Massachusetts and Houston, Texas. The Boston office consists of approximately 4,200 square feet under a lease that expires in June 2005, and the Houston office consists of approximately 5,600 square feet under a lease that expires in February 2007.

      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 January 15, 2003, we filed a complaint in the United States District Court for the Central District of California entitled Commonwealth Energy Corporation v. Wayne Mosley, et al. (Case number CV03-00402-NM (RNBx)) against several dissident stockholders who we believed had illegally solicited proxies in connection with the annual meeting of stockholders on January 21, 2003. On February 6, 2003, we filed an amended complaint in this lawsuit asking the court to confirm that the Board of Directors had been legally elected by the stockholders and validating the inspector’s determination at the annual meeting that the proxy materials sent by defendants had violated several Securities and Exchange Commission rules and regulations and that the resulting proxies were invalid. On June 10, 2003, the court issued a default judgment against certain defendants, finding (a) we properly conducted the election at our annual meeting and the inspectors of election were correct in rejecting the proxies solicited by the group; (b) the inspectors of election counted the votes and proxies properly (and thus the elections results were validated); and (c) the challenged proxies violated Securities and Exchange Act Section 14(a) and Securities and Exchange Commission Rules 14a-4 and 14a-9, and were therefore invalid. Three members of the group, and all persons acting in concert with them, were ordered by the court to comply with all federal securities laws and Securities and Exchange Commission rules in any future attempts to solicit proxies. However, two additional defendants, who were not subject to the court’s earlier ruling, brought a counterclaim against us on November 14, 2003 alleging that our Board of Directors was not properly elected at the annual meeting. This action is currently pending and seeks an order voiding the results of the Board of Directors election at the 2003 annual meeting and compelling us to seat certain other persons whom they allege should have been elected to the Board. No damages are currently being sought by plaintiffs in this case. Commonwealth intends to defend these counter-claims vigorously.

      On February 14, 2003, we filed a complaint in the Orange County Superior Court against Joseph Ogundiji (Case number 03C03049) seeking a judicial declaration recognizing as invalid 80,000 shares of our capital stock that Mr. Ogundiji 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 dividends in violation of California Corporations Code Section 25120 and unjust enrichment. The cross-complaint seeks an unspecified amount of general and punitive damages. This matter is scheduled for trial on June 20, 2005.

      On November 20, 2003, we filed a Notice of Appeal in the California Court of Appeal’s Fourth Appellate District, Division Three, from a court order dated September 24, 2003 in Saline v. Commonwealth Energy Corp. (Orange County Superior Court case number 01CC13887). The appealed order was entered after the first of two trial phases and requires Commonwealth to recognize the shares of “other convertible preferred stock” held by plaintiff, Joseph Saline, a former director, as valid. A second phase of the trial is scheduled for January 18, 2005, Commonwealth recently prevailed on its motion for summary adjudication of Mr. Saline’s

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      On November 25, 2003, several stockholders filed a lawsuit against us in the United States District Court for the Central District of California entitled Coltrain, et al. v. Commonwealth Energy Corporation, et al. (Case number CV03-8560-FMC (RNBx)). The complaint purports to be a class action against us for violations of section 709 of the California Corporations Code. The plaintiffs allege that we failed to correctly count approximately 39,869,704 votes cast at the 2003 annual meeting and, as a result, the Board of Directors was not properly elected. Instead, the plaintiffs allege that four different persons would have been seated on the Board had the votes been tabulated in the manner advocated by the plaintiffs. This case involves identical issues of law and fact as the counterclaim discussed above in Commonwealth Energy Corporation v. Wayne Moseley, et al. and is currently pending. Commonwealth recently settled with one of the plaintiffs in this case, Coltrain. Commonwealth is vigorously defending this action.

      On April 19, 2004, Mr. Saline and Mr. Ogundiji filed an action in California Superior Court for Orange County (Case No. 04CC05038), alleging that Commonwealth Energy Corporation’s Board of Directors (other than Mr. Saline) breached their fiduciary duties and breached the covenant of good faith and fair dealing by approving and putting to a stockholder vote the recent reorganization plan, which resulted in Commonwealth becoming a wholly-owned subsidiary of Commerce Energy Group, Inc. In addition, they allege that Commonwealth improperly failed to hold an annual meeting within the time limits set by California Corporations Code Section 600, improperly used the reorganization to alter their rights as preferred stockholders, and improperly refused to hold a vote just among preferred stockholders regarding the reorganization. Up to this point in the litigation, Mr. Saline and Mr. Ogundiji have attempted to block the special meeting at which the reorganization was approved, to enjoin the reorganization, to unwind the reorganization and to de-list the shares of common stock of Commerce listed on the AMEX but were not successful. Because our directors are defendants in this case, pursuant to the terms of the indemnification agreements between Commonwealth and its directors, we are required to indemnify the directors to the fullest extent allowed by law. The indemnification agreement covers any expenses and/or liabilities reasonably incurred in connection with the investigation, defense, settlement or appeal of legal proceedings. The obligation to provide indemnification does not apply if the officer or director is found to be liable for fraudulent or criminal conduct. Pursuant to the indemnification agreement, we are currently providing a joint defense with the directors in this action. This matter is scheduled for trial in September 12, 2005 and Commonwealth will defend vigorously.

      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.

      A special meeting of stockholders of Commonwealth Energy was held on May 20, 2004 for the purpose of (a) voting on a proposal, which we refer to as the “reorganization proposal,” to approve the Agreement and Plan of Reorganization by and among Commerce Energy Group, Inc., a wholly-owned subsidiary of Commerce Energy Group, Inc. and Commonwealth Energy Corporation and the merger provided thereby of Commonwealth Energy Corporation with a wholly-owned subsidiary of Commerce Energy Group, Inc., with Commonwealth Energy Corporation surviving as a wholly-owned subsidiary of Commerce Energy Group,

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      The reorganization proposal and the proposal to grant discretionary authority to adjourn or postpone the special meeting for the purpose of soliciting additional proxies were approved at the special meeting. The complete results of the voting at the special meeting has been previously reported in Commonwealth’s Quarterly Report on Form 10-Q for the Quarterly Period Ended April 30, 2004, filed with the Securities and Exchange Commission on June 14, 2004.

      On July 6, 2004, the holders of 411,000 shares of Commonwealth’s 609,000 outstanding shares of Series A Preferred Stock consented in writing to the conversion of their preferred shares into Commonwealth common stock prior to consummation of the reorganization. Pursuant to the Certificate of Designation for Commonwealth’s Series A Preferred Stock, upon the consent of holders of at least 66 2/3% of the Series A Preferred Stock to convert their shares, 100% of the shares of Commonwealth Series A Preferred Stock were converted into shares of Commonwealth common stock.

      On July 1, 2004, Commonwealth, as the sole stockholder of Commerce prior to the reorganization, approved the following by unanimous written consent: (a) the reorganization proposal; (b) the amendment and restatement of Commerce’s Certificate of Incorporation; (c) the amendment and restatement of Commerce’s bylaws; and (d) indemnification agreements for Commerce’s officers and directors.

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PART II

Market Information

      On July 8, 2004, Commerce’s common stock began trading on the American Stock Exchange under the symbol “EGR.” The following table sets forth, the high and low sales price per share of common stock for the periods indicated, as reported on the American Stock Exchange:

      As of November 11, 2004, the last reported sales price on the American Stock Exchange for Commerce’s common stock was $1.05 per share.

      Prior to July 8, 2004, there was no established public trading market for any class of Commerce Energy’s or Commonwealth’s equity securities.

Holders

      As of November 11, 2004, there were 2,419 holders of record of Commerce’s common stock.

Dividend Policy

      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.

      Prior to July 2004, Commonwealth’s Series A convertible preferred stock provided for cumulative dividends that accrued at a rate of 10% per annum. During fiscal 2003 and fiscal 2004, Commonwealth declared and paid cash dividends of $92,100 and $107,568, respectively, on Commonwealth’s Series A convertible preferred stock. As of July 31, 2003, accrued cumulative unpaid dividends on our Series A convertible preferred stock were $90,548. On July 6, 2004, immediately prior to the reorganization, all 609,000 outstanding shares of Commonwealth’s Series A convertible preferred stock were converted to Commonwealth common stock by a vote of Commonwealth’s Series A convertible preferred stockholders. Accordingly, as of July 31, 2004, there were no shares of Commonwealth’s Series A convertible preferred stock outstanding, and no accrued dividends on shares of Series A convertible preferred stock.

      Prior to July 2004, Commonwealth recognized 392,000 shares of Other convertible preferred stock that accrued interest at rates of 12% to 14% per annum. The validity of these shares of preferred stock is the subject of pending litigation. See “Item 3. Legal Proceedings.” During fiscal 2003, Commonwealth did not declare or pay cash dividends on the Other convertible preferred stock. In fiscal 2004, Commonwealth declared and paid cash dividends of $73,507 on Commonwealth’s Other convertible preferred stock. Prior to the reorganization in July 2004, all of the shares Commonwealth’s Other convertible preferred stock were converted to Commerce common stock at the election of the Other convertible preferred stockholders. Accordingly, as of July 31, 2004, there were no shares of Commonwealth’s Other convertible preferred stock outstanding or accrued dividends on shares of Other convertible preferred stock.

Equity Compensation Plan Information

      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.

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Recent Sales of Unregistered Securities

      In March 2004, Commonwealth sold 100,000 shares of common stock to Ian B. Carter, the Company’s Chief Executive Officer, in a private placement pursuant to the exercise of a stock option agreement. The transaction was exempt under Section 4(2) of the Securities Act of 1933 as one not involving any public offering.

      On July 6, 2004, Commonwealth issued 1,393,000 shares of common stock to the former holders of Commonwealth’s Series A convertible preferred stock and Other convertible preferred stock upon conversion of the Series A and Other convertible preferred stock in accordance with their respective terms. The transactions were exempt under Section 3(a)(9) of the Securities Act of 1933 as an exchange of securities with existing security holders. No commission or other remuneration was paid or given directly or indirectly for soliciting the exchange.

Issuer Purchases of Equity Securities

      The following table details our common stock repurchases for the three months ended July 31, 2004:

Issuer Purchases of Equity Securities

(1)	Represents shares repurchased from former stockholders of Commonwealth, pursuant to the exercise of dissenter’s rights in connection with the Company’s reorganization in July 2004.

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      The selected financial data in the following tables sets forth (a) balance sheet data as of July 31, 2003 and 2004, and statement of operations data for the fiscal years ended July 31, 2002, 2003 and 2004 derived from our consolidated financial statements audited by Ernst & Young LLP, independent registered public accounting firm, which are included elsewhere in this filing, and (b) balance sheet data as of July 31, 2000, 2001 and 2002, and statements of operations data for the fiscal years ended July 31, 2000 and 2001, 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.

(1)	Includes stock-based compensation charges (reversals) of $445, $1,080, $(743), $0 and $636 in the fiscal years ended July 31, 2000, 2001, 2002, 2003 and 2004, 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.

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      We are a diversified energy services company. We provide electric power to our residential, commercial, industrial and institutional customers in the deregulated California, Pennsylvania, Michigan and New Jersey electricity markets under the brand name electricAmerica. We are licensed by the Federal Energy Regulatory Commission, or FERC, as a power marketer. In addition to the states in which we currently operate, we are also licensed to supply retail electric power by applicable state agencies in New York, Maryland, Texas and Ohio.

      As of July 31, 2004, we delivered electricity to approximately 102,000 customers in California, Pennsylvania, Michigan and New Jersey. The growth of our business depends upon the degree of deregulation in each state, the availability of energy at competitive prices and credit terms, and our ability to acquire retail or commercial customers.

      Our core business is the retail sale of electricity to end-use customers. All of the power we sell to our customers is purchased from third party power generators under long-term contracts and in the spot market. We do not own electricity generation facilities, with the exception of small experimental renewable energy assets. The electric power we sell is generally metered and delivered to our customers by the local incumbent electric distribution utilities, or local utilities. The local utilities also provide billing and collection services for most of our customers on our behalf. To enable load shaping and balancing for our retail customer portfolio, we also buy and sell surplus electric power from and to other market participants when necessary.

      On April 1, 2004, we acquired Skipping Stone, Inc., or Skipping Stone, an energy consulting and technology firm. The aggregate purchase price for all of the outstanding Skipping Stone securities, which consists of common stock and vested options, was $3.1 million and the assumption of $0.6 million of debt, subject to limited restrictions and true-up provisions. The purchase price was paid through the issuance of Commonwealth common stock, which was valued at $1.92 per share. Skipping Stone’s revenue and operating results were less then 1% of our consolidated totals for the four months since its acquisition.

      On April 30, 2004, we reached an agreement with our investment manager, Northwest Power Management, or NPM, to terminate our relationship with Summit Energy Ventures, LLC, or Summit. As a result of the transaction, we no longer retain an equity interest or contractual relationship with Summit, and we retain and directly own investments in the three portfolio companies previously held by Summit. Under the terms of the agreement, we retain the entire interest in Encorp, Inc., or Encorp, and Turbocor B.V., or Turbocor, previously held by Summit, and we retain a portion of the interest in Power Efficiency, or PEC, that was previously held by Summit and not distributed to NPM in the settlement. We no longer consolidate the financial results of PEC in our consolidated financial statements due to a reduction in our ownership percentage to approximately 40%.

Market and Regulatory

      The 1996 California Assembly Bill, or AB, 1890 codified the restructuring of the California electric industry and provided for the right of direct access, or DA. DA allowed electricity customers to buy their power from a supplier other than the electric distribution utilities beginning January 1, 1998. On April 1, 1998, we began supplying customers in California with electricity as an Electric Service Provider, or ESP.

      The California Public Utility Commission, or CPUC, issued a ruling on September 20, 2001 suspending direct access. The suspension permitted us to keep current customers and to solicit DA customers served by other providers, but prohibited us from soliciting new non-DA customers for an indefinite period of time.

      In July 2002, the CPUC authorized Southern California Edison, or SCE, to implement a Historical Procurement Charge, or HPC, to repay debt incurred during the energy crisis. This amount is currently being collected by SCE as a $0.01 per kilowatt-hour, or kWh, surcharge on the retail electricity bill paid by our customers. SCE estimates that full payment could be achieved as soon as early 2006. While HPC does not

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      Senate Bill 1078, signed by the governor on September 12, 2002, established a Renewable Portfolio Standard program that requires retail sellers of electricity to increase the renewable energy content of their electricity deliveries, from sources such as small hydro, biomass, geothermal resources, and municipal solid waste conversion technologies. Retail sellers must meet a target of 20 percent renewable content in their electricity portfolio by December 31, 2017. Due to the slow ramp-up of this program, additional costs to us are not expected to be significant in the near future.

      Effective January 1, 2003, the CPUC authorized the electric distribution utilities to charge certain DA customers a surcharge to cover state power contract costs. The Direct Access Customer Responsibility Surcharge, or DA CRS, is currently fixed at $0.027 per kWh. DA CRS is only assessed to those DA customers who enrolled in DA on or after February 1, 2001. In the SCE service territory, the $0.027 DA CRS includes the $0.01 HPC. Those customers enrolled in DA prior to February 1, 2001, in the SCE service territory continue to pay only the $0.01 HPC. While this charge does not directly impact our rate design or revenue, it may affect our ability to retain existing customers or compete for new customers.

      In December 2003, Pacific Gas and Electric, or PG&E, and the CPUC reached a settlement in the PG&E bankruptcy. In February 2004, the CPUC approved a rate settlement agreement, which reduced overall customer rates in the PG&E service territory. DA bills have generally declined in the PG&E service territory and the lower rates have affected our revenue and profitability.

      Currently, four important issues are under review at the CPUC, a Resource Adequacy Requirement, a Renewable Portfolio Standard, Utilities Long Term Procurement Plans and the General Rate Cases of the electric distribution utilities. Additional costs to serve customers in California are anticipated from these proceedings, however, the CPUC decisions will determine the distribution of those costs across all load serving entities and ultimately the financial impact on us.

      In September 2004, AB 2006, which would have impacted DA, was vetoed by the governor. There are no economic impacts to our financial results as a result of that veto.

      In 1996, the Electricity Generation Customer Choice and Competition Act was passed. The law allowed electric customers to choose among competitive power suppliers beginning with one third of the State’s consumers by January 1999, two thirds by January 2000, and all consumers by January 2001. We began serving customers in the Pennsylvania territory in 1999. There are no current rate cases or filings regarding this territory that are anticipated to impact our financial results.

      The Michigan state legislature passed two acts, the Customer Choice Act and Electricity Reliability Act, signed into law on June 3, 2000. Open access, or Choice, became available to all customers of Michigan electric distribution utilities, beginning January 1, 2002. We began marketing in Michigan’s Detroit Edison, or DTE, service territory in September 2002.

      In February 2004, the Michigan Public Service Commission, or MPSC, issued an interim order granting partial but immediate rate relief to DTE, our primary electric distribution utility market in Michigan. The order significantly reduced the savings of commercial customers who choose an alternative electric supplier, such as us. These changes have adversely affected our ability to retain some of our existing customers and obtain new customers, primarily among larger commercial customers.

      The Michigan Senate has energy restructuring language before it in various bills, supported by the electric distribution utilities, which could negatively impact competition in the Michigan electric market. The proposed changes to the Choice market in Michigan would place additional costs and burdens on competitive electricity suppliers, diminish incentives for customers to switch from the electric distribution utilities, and

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      Deregulation activities began in New Jersey in November 1999 when the Board of Public Utilities approved the implementation plan. We began marketing in New Jersey in the Public Service Electric and Gas service territory in December 2003.

      The Basic Generation Service is the comparable utility price for small and large commercial accounts and includes a reconciliation charge which can change on a monthly basis. Reconciliation charge fluctuations can affect our ability to remain competitive against the comparable utility pricing.

Critical Accounting Policies and Estimates

      The following discussion and analysis of our financial condition and operating results are based on our consolidated financial statements. The preparation of this Annual Report on Form 10-K requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of our financial statements, and the reported amount of revenue and expenses during the reporting period. Actual results may differ from those estimates and assumptions. In preparing our financial statements and accounting for the underlying transactions and balances, we apply our accounting policies as disclosed in our notes to the consolidated financial statements. The 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.

	•	Normal purchases and sales accounting — In fiscal 2004, we purchased substantially all of our power under long-term forward physical delivery contracts for supply to our retail electricity customers under long–term and full requirements sales contracts. We apply the normal purchase, normal sale accounting treatment to our forward purchase supply contracts and our customer sales contracts. Accordingly, we record revenue generated from our sales contracts as energy is delivered to our retail customers, and direct energy costs are recorded when the energy under our long-term forward physical delivery contracts is delivered. During fiscal 2004, we also used financial hedging, or derivative instruments, to hedge our commodity risks to a limited degree. At July 31, 2004, we had no positions in derivative instruments, however, we intend to use derivative instruments in the future as an efficient way of assisting in managing our price and volume risk in energy supply procurement for our retail customers. Some derivative instruments may not qualify as normal purchases and sales and may require mark-to-market accounting and the application of the Financial Accounting Standards Board, or FASB, Statement of Financial Accounting Standard No. 133, or SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” in future periods.
	•	Independent system operator costs — Included in direct energy costs, along with electric power that we purchase, are scheduling coordination costs and other independent system operator, or ISO, fees and charges. The actual ISO costs are not finalized until a settlement process by the ISO is performed for each day’s activities for all grid participants. Prior to the completion of settlements (which may take from one to several months), we estimate these costs based on historical trends and preliminary settlement information. The historical trends, current activity levels and preliminary information may differ from actual fees resulting in the need to adjust the previously estimated costs.
	•	Allowance for doubtful accounts — We maintain allowances for doubtful accounts for estimated losses resulting from non-payment of customer billings. If the financial conditions of our customers were to deteriorate, resulting in an impairment of their ability to make payments, additional allowances may be required.

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	•	Unbilled receivables — Our customers are billed monthly at various dates throughout the month. Unbilled receivables represent the amount of electric power delivered to a customer at the end of a reporting period, but not yet billed. Unbilled receivables from sales are estimated by us to be the number of kilowatt-hours delivered, but not yet billed, multiplied by the current customer average sales price per kilowatt-hour.
	•	Legal matters — From time to time, we may be involved in litigation matters. 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 Statements of Financial Accounting Standards No. 5, “Accounting for Contingencies.” 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 adverse impact on our results of operations and financial position.

Results of Operations

      The following table summarizes the results of our operations (dollars in thousands):

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

      Net revenue for fiscal 2004 was $210.6 million, an increase of $45.1 million, or 27%, from $165.5 million in fiscal 2003. Gross profit of $19.4 million for fiscal 2004 declined $17.9 million, or 48%, from $37.3 million in fiscal 2003.

      Our operating results for the year ended July 31, 2004 included a loss from operations of $13.9 million compared to income from operations of $14.6 million for the year ended July 31, 2003. The operating loss in fiscal 2004 was primarily due to the higher cost of electricity per kWh. The higher cost of electricity per kWh has been primarily caused by the substantial increase in natural gas prices, which is a significant influencing factor on electricity prices in the wholesale markets nationally. The higher costs related to serving our customers led to some customer attrition in California and Pennsylvania in the latter part of the fiscal year. Also, in California, demand was less than forecast and as a result, we sold our excess energy at lower prices then we paid, reducing gross margins.

      Net loss for fiscal 2004 was $21.7 million compared to net income of $5.4 million in fiscal 2003. In addition, to the above reasons, in fiscal 2004, we recorded a provision for impairment on investments of $7.1 million for investments previously held by Summit and subsequently, a loss of $1.9 million on the termination of the Summit venture.

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      The increase of $45.1 million in net revenue compared to the prior fiscal year resulted primarily from increased energy sales of $27.6 million in Pennsylvania, primarily due to increasing our customer base early in the fiscal year, and $25.4 million in Michigan due to increasing our customer sales base in fiscal 2004; and a $1.0 million increase due to entering the New Jersey market in fiscal 2004; offset by a decrease of $9.9 million in energy sales in California, primarily due to the price per kWh decline in fiscal 2004 and the absence of green power credits in fiscal 2004. In Pennsylvania, we sold 1,316 million kWh at an average price of $0.064 in the fiscal year ended July 31, 2004, as compared to 976 million kWh sold at an average price of $0.058 in the fiscal year ended July 31, 2003. The volume increase was primarily due to the acquisition of commercial customers towards the end of fiscal 2003. The price increase is primarily attributed to our targeting new commercial customers with higher average rates and a reduced number of residential customers in fiscal 2004. In Michigan, we sold 709 million kWh at an average price per kWh of $0.058 in fiscal 2004, as compared to 230 million kWh at an average retail price per kWh of $0.069 in the same period last year. Our volume increased as a result of our sales operations. In California, we sold 1,219 million kWh at an average price of $0.068 in fiscal 2004, as compared to 1,191 million kWh sold at an average price of $0.073 in fiscal 2003. In New Jersey, we sold 16 million kWh at an average price of $0.069 in fiscal 2004 compared to no sales in fiscal 2003, as we began to offer electric service in New Jersey in December 2003.

      The $5.6 million green power credits in fiscal 2003 represents the recovery from the reinstatement by the State of California 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 102,000 retail customers at July 31, 2004, a decrease of 16,000, or 14%, from 118,000 at July 31, 2003. Customer attrition was 11% and 21% in California and Pennsylvania, respectively, from the prior fiscal year. These declines primarily are the result of our customer focus on increasing our commercial and industrial base, which have much higher average electricity usage and generally higher rates, while reducing the number of residential customers, which have much lower average usage and generally lower rates. The decline in our customer base is also partially attributed to increased energy costs to serve our customers.

      Direct energy costs, which are recognized concurrently with related energy sales, include the aggregated cost of purchased electric power, fees incurred from various energy-related service providers, and energy-related taxes that cannot be passed directly through to the customer.

      Our direct energy costs increased to $191.2 million for fiscal 2004, an increase of $63.0 million, or 49%, from $128.2 million for fiscal 2003. The significant increase in direct energy costs per retail kWh delivered occurred in all states, primarily due to the increase of natural gas costs which is a significant factor influencing electricity costs in our markets. The increase in our customer base was also a contributing factor to the absolute increase in direct energy costs. In Pennsylvania, the average cost per kWh was $0.063 for the fiscal year ended July 31, 2004, as compared to an average cost per kWh of $0.059 for fiscal 2003. In Michigan, the average cost per kWh was $0.051 for the fiscal year ended July 31, 2004, as compared to an average cost per kWh of $0.059 for fiscal 2003. In California, the average cost per kWh was $0.058 for fiscal 2004, as compared to an average cost per kWh of $0.048 for fiscal 2003. In New Jersey, our new market in fiscal 2004, the average cost per kWh was $0.049 for fiscal 2004.

      Our selling and marketing expenses were $4.1 million for fiscal 2004, a decrease of $0.1 million, or 4%, from $4.2 million for fiscal 2003. Selling and marketing expenses for fiscal 2004 primarily represent marketing efforts associated with our expansion into the New Jersey market, including radio and newspaper advertising and further market research conducted on certain states under consideration for future expansion. As part of

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      Our general and administrative expenses were $25.9 million for fiscal 2004, an increase of $7.4 million, or 40%, from $18.5 million for fiscal 2003. The increase in fiscal 2004 was primarily due from the consolidation of PEC of $2.1 million through the third quarter of fiscal 2004; severance payments totaling $1.9 million related to the settlement of the employment contracts of our former Chief Operating and Chief Financial Officers; stock based compensation expense of $0.6 million for fully vested options that were granted in fiscal 2004 with an exercise price below fair market value on the grant date; relocation expenses of $0.5 million for our new officers; additional bad debt expense of $0.7 million and insurance costs of $0.6 million.

      We incurred $3.4 million in fiscal 2004 of costs related to our reorganization into a Delaware holding company structure and the initial public listing of our common stock on the American Stock Exchange. Management believes it is appropriate to classify these costs as separately identified operating expenses. These general and administrative expenses incurred in connection with the reorganization included legal of $1.5 million, insurance of $0.9 million, consulting of $0.5 million, and printing and reproduction fees of $0.4 million, and accounting and auditing of $0.1 million.

      In fiscal 2004, we incurred $1.6 million of initial formation litigation costs related to our formation compared to $4.4 million of such costs incurred during fiscal 2003. Initial formation litigation expenses include legal and litigation costs associated with the initial capital raising efforts by former employees, and the legal complications arising from those matters. The fiscal 2003 expense includes $2.2 million which was accrued in connection with a lawsuit filed by several former employees, who were employed during 1998 and 1999, exclusively to raise capital for us from outside investors. In fiscal 2004, we settled this litigation and the settlement resulted in a reduction of the accrual of $0.5 million after final settlement payments were made to the plaintiffs.

      In fiscal 2004, we recorded a provision for impairment of $7.1 million on investments previously held by Summit, to reflect our percentage ownership in the net equity reflected in the financial statements of each investment entity. The impairments reflected continuing operating losses, liquidity and future funding uncertainties on all three investments. For Encorp, we recorded a $1.9 million provision for impairment with a remaining investment basis of $0.1 million in our consolidated financial statements. For Turbocor, we recorded a $4.1 million provision for impairment with no remaining investment basis in our consolidated financial statements. For PEC, we recorded a $1.1 million provision for impairment with no remaining investment basis after the provision for termination below to reflect our reduced investment ownership percentage in PEC shares. See Note 9 of Notes to Consolidated Financial Statements.

      In fiscal 2004, we recorded a loss on the termination of Summit of $1.9 million. The loss included contractually owed management fees and transaction costs of $1.6 million and a reduction of our ownership interest from 75.9% to 39.9% in PEC to reflect settlement and the termination of Summit. See Note 9 of Notes to Consolidated Financial Statements.

      In fiscal 2003, we incurred a $0.6 million aggregate loss on equity investments which reflected our proportionate recognition of losses under the equity method of accounting relating to PEC and, to a lesser

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      Minority interest share of loss represents that portion of PEC’s post-consolidation losses that were allocated to the non-Summit investors based on their aggregate minority ownership interest in PEC. For the fiscal year ended July 31, 2004 and 2003, the minority interest share of loss was $1.2 million and $0.2 million, respectively.

      Our interest income, net was $0.5 million for fiscal 2004, a decrease of $0.2 million, or 23%, from $0.7 million in fiscal 2003. The decrease in interest income was primarily due to lower market yields realized on short-term investments.

      The benefit from income taxes was $1.0 million for fiscal 2004, compared to the provision for income taxes of $5.1 million for fiscal 2003. In fiscal 2004, the benefit from income taxes was comprised of a write-down of deferred tax assets for $2.5 million offset by operating loss carrybacks of $3.5 million. Our effective income tax benefit rate was 4.5% for fiscal 2004, compared to an effective income tax rate of 48.5% for fiscal 2003. The decrease in the effective tax rate was primarily due to the increase in the valuation allowance for deferred tax assets.

      Our net revenue for fiscal 2003 was $165.5 million, an increase of $47.7 million, or 41%, from $117.8 million in fiscal 2002. The increase is primarily due to increased energy sales in California of $10.4 million, Pennsylvania of $17.8 million and Michigan of $16.0 million, with the remaining increase due to higher green power credits by $3.5 million.

      We sold 1,191 million kWh at an average price per kWh of $0.073 in California during fiscal 2003, as compared to 1,111 million kWh sold at an average price per kWh of $0.069 during fiscal 2002. This increase in volume was due primarily to the acquisition of large commercial customers from other ESPs. The increase in price is primarily attributed to the higher price per kWh for excess energy in fiscal 2003 compared to fiscal 2002 partially offset by 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 976 million kWh at an average price per kWh of $0.058 in Pennsylvania during fiscal 2003, as compared to 938 million kWh sold at an average price per kWh of $0.042 during fiscal 2002. This slight increase was due primarily to the acquisition of approximately 40,000 customers in Pennsylvania under a bid process that was a part of a regulatory electric utility restructuring in Pennsylvania. We sold 230 million kWh at an average price per kWh of $0.069 in Michigan during fiscal 2003, as compared to no sales during fiscal 2002.

      The increases in Michigan and Pennsylvania was primarily due to our increased customer base as we entered the Michigan market and gained market share in Pennsylvania.

      The $3.5 million, or 173%, increase in our fiscal 2003 green power credits was attributable primarily to the recognition in fiscal 2003 of green power credits for the final seven months of fiscal 2002 and the first eight

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      We had approximately 118,000 retail customers at July 31, 2003, an increase of 29,000, or 33%, 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. 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 average electricity usage.

      Direct energy costs, which are recognized concurrently with related energy sales, include the aggregated cost of purchased electric power, fees incurred from various energy-related service providers and related taxes that cannot be passed directly through to the customer. Our direct energy costs were $128.2 million for fiscal 2003, an increase of $40.9 million, or 47%, from $87.3 million for fiscal 2002. In California, the average cost per kWh sold was $0.048 during fiscal 2003, as compared to an average cost per kWh sold of $0.036 during fiscal 2002. In Pennsylvania, the average cost per kWh sold was $0.059 during fiscal 2003, as compared to an average cost per kWh sold of $0.050 during fiscal 2002. In Michigan, the average cost per kWh sold was $0.059 during fiscal 2003. Michigan was a new market for us in fiscal 2003. The fiscal 2003 increase in our direct energy costs was primarily attributable to increased kWh purchases to accommodate our entry into the Michigan market and additional customer deliveries 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 21%, 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.

      Our general and administrative expenses were $18.5 million for fiscal 2003, an increase of $1.8 million, or 10%, from $16.7 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 stockholders, merit compensation increases, and increased premiums on directors and officers insurance, 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 also reduced by a $0.7 million reversal of previously recognized stock-based compensation.

      In fiscal 2003, we incurred $4.4 million of initial formation litigation costs related to our formation compared to $1.7 million of such costs incurred in fiscal 2002. The increase of $2.7 is primarily attributed to $2.2 million which were accrued in connection with a lawsuit filed by several former employees, who were employed during 1998 and 1999, exclusively to raise capital for us from outside investors.

      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; namely, the losses incurred by PEC through April 30, 2003, and, to a significantly lesser extent, Turbocor through January 2003. Effective May 1, 2003, we began consolidating PEC as Summit had obtained a

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      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 24%, 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 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 49% for fiscal 2003, compared to 44% 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 carry forwards for federal income tax purposes.

Liquidity and Capital Resources

      We have sustained our operations and funded our growth substantially with our working capital and internally generated cash flows from operations. Based upon our current plans, level of operations and business conditions, we believe that our cash and cash equivalents, and cash generated from our operations will be sufficient to meet our capital requirements and working capital needs for the foreseeable future. However, there can be no assurance that we will not be required to seek other financing in the future or that such financing, if required, will be available on terms satisfactory to us.

      We do not have open lines of credit for direct unsecured borrowings or for letters of credit. Credit terms from our suppliers of electricity often require us to post collateral against our energy purchases and against our mark-to-market exposure with certain of our suppliers. We currently finance these collateral obligations with our available cash. As of July 31, 2004, we had $4.0 million in restricted cash and cash equivalents to secure letters of credit required by our suppliers and $5.1 million in deposits pledged as collateral in connection with energy purchase agreements. We have granted a security interest in our Michigan accounts receivable as security for payment of energy purchases from an affiliate of the local utility. If our collateral needs increase, we will need to either increase the portion of our cash which will be restricted or find alternative means to finance our obligations, which may have an adverse effect on our liquidity.

      Our unrestricted cash and cash equivalents increased by $13.2 million, or 32%, to $54.1 at July 31, 2004, as compared with $40.9 million at July 31, 2003. Our working capital increased by $1.7 million, or 3%, to $58.1 million at July 31, 2004, from $56.4 million at July 31, 2003.

      Cash provided by operating activities for fiscal 2004 was $0.3 million, compared to $5.6 million in the prior year. In fiscal 2004, cash was provided primarily by a decrease in accounts receivable primarily due to the

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      Cash used in investing activities was $1.1 million in fiscal 2004, as compared to $1.5 million in fiscal 2003. Cash used in investments for the current fiscal year consisted of higher capital expenditures and in the prior year primarily due to the acquisition of the majority ownership of PEC and Summit investments.

      Cash provided by financing activities during fiscal 2004 was $14.0 million, as compared to cash used in financing activities of $6.3 million during fiscal 2003. In the current fiscal year, restricted cash and cash equivalents decreased by $15.0 million was primarily due to the cancellation of the fiscal 2003 required security for an appeals bond of $4.1 million related to a settled litigation, the $7.7 million net reduction of the required letters of credit secured by cash related to energy suppliers in fiscal 2003, and the remaining decrease was due to the use of Summit’s restricted cash for operations and termination of our relationship with Summit.

      Our planned capital expenditures for the fiscal year ending July 31, 2005 (“fiscal 2005”) 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 have no off-balance sheet arrangements and have no transactions involving unconsolidated, limited purpose entities.

      We currently are party to a number of supply contracts requiring us to purchase electrical power covering approximately 74% of our customers’ load servicing requirements for fiscal 2005 based on our forecast. 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 ability to then 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 lease pertains to our corporate office facilities. All of our other operating leases pertain to various equipment and technology. Certain of these operating leases are non-cancelable and contain clauses that pass through increases in building operating expenses. We incurred aggregate rent expense under operating leases of $704,000, $742,000, and $931,000 during fiscal 2002, 2003 and 2004, respectively.

      We have four executive employment agreements in existence at July 31, 2004 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.”

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      The following table shows our contractual commitments as of July 31, 2004:

      Demand for electrical power is continually influenced, by both seasonal and abnormal weather patterns. To the extent that one or more of our markets experiences a period of unexpected weather, we may be required to either attempt to procure additional electricity to service our customers or to sell surplus electricity in the open market.

Factors That May Affect Future Results

      The Federal Energy Regulatory Commission, or 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. Twenty-four 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 local 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, local 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 stockholders 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 of time. 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 stockholders that federal legislation will not be passed in the future that could materially adversely affect our business.

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      We intend to increase our operating expenses to develop and expand 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 operate profitably 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 continue to develop and maintain internal corporate organization and systems;
	•	The continued competitive restructuring of retail energy markets with viable competitive market rules; and
	•	Our ability to effectively manage our energy procurement and shaping requirements, and to sell our energy at a sufficient profit 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 supplier for 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 could be materially adversely affected.

      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.

      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 local 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 as forecast, it leaves us in a long position that would be resold into the wholesale electricity market. Sales of this surplus electricity could be at prices below our cost. Conversely, 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 if 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.

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      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 could be unable to deliver electricity to our customers during those interruptions. This would results in lost revenue to us, which could adversely impact the results of our operations.

      Under a Settlement agreement with the California PUC, 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, or PROACT, from bundled (non direct access) customers and under the HPC from DA customers.

      In July 2002, the California PUC 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, or 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 discretely impacts our rate calculations, a recent SCE rate reduction includes the former 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, and in addition to, the HPC related reduction in 2003.

      These changes in the SCE service territory will continue to cause a significant impact on our revenue and cash flow; however, we currently do not expect they will preclude us from continuing to participate in the SCE market.

      We continue to monitor our suppliers’ credit quality to attempt to reduce the impact of any potential counterparty default. As of July 31, 2004, the majority of our counterparties are rated investment grade or above by the major rating agencies. These ratings are subject to change at any time with no advance warning. A deterioration in the credit quality of our suppliers could have an adverse impact on our sources of electricity purchases.

      As 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 margin in the form of a letter of credit, or other collateral, to protect themselves against

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      Under the regulatory structures adopted in most jurisdictions, we will be required to enter into agreements with local 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 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.

      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 regulated 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. 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, including hydrological conditions such as precipitation, snow pack and streamflow,
	•	seasonality,
	•	unexpected changes in customer usage,
	•	transmission or transportation constraints or inefficiencies,
	•	planned and unplanned plant or transmission line outages,
	•	demand for electricity,

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	•	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.

      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.

      Effective internal controls are necessary for us to provide reliable financial reports and effectively prevent fraud. If we cannot provide reliable financial reports or prevent fraud, our operating results could be harmed. We have in the past discovered, and may in the future discover, areas of our internal controls that need improvement. For example, in our preparation for our 2004 audit, we discovered an unreconciled energy accounting issue that caused us to restate our second and third quarter reported results. Our external auditor identified this issue as a reportable condition and a material weakness, which means that this was an issue that in the auditor’s judgment could adversely affect our ability to record, process, summarize and report financial data consistent with the assertions of management in the financial statements. In 2004, we devoted resources to remediate and improve our internal controls. Although we believe that these efforts have strengthened our internal controls and addressed the concerns that gave rise to the reportable condition and material weakness in 2004, we are continuing to work to improve our internal controls, including in the area of energy accounting. We cannot be certain that these measures will ensure that we implement and maintain adequate controls over our financial processes and reporting in the future. Any failure to implement required new or improved controls, or difficulties encountered in their implementation, could harm our operating results or cause us to fail to meet our reporting obligations. Inferior internal controls could also cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our stock.

      As directed by Section 404 of the Sarbanes-Oxley Act of 2002, the Securities and Exchange Commission adopted rules requiring public companies to include a report of management on our internal controls over financial reporting in our Annual Reports on Form 10-K that contains an assessment by management of the effectiveness of our internal controls over financial reporting. In addition, our independent auditors must attest to and report on management’s assessment of the effectiveness of our internal controls over financial reporting. This requirement will first apply to our Annual Report on Form 10-K for the fiscal year ending July 31, 2005. How companies should be implementing these new requirements including internal control reforms, if any, to comply with Section 404’s requirements, and how independent auditors will apply these new requirements and test companies’ internal controls, are subject to uncertainty. Although we are diligently and vigorously reviewing our internal controls over financial reporting in order to ensure compliance with the new Section 404 requirements, if our independent auditors are not satisfied with our internal controls over financial reporting or the level at which these controls are documented, designed, operated or reviewed, or if the independent auditors interpret the requirements, rules or regulations differently than we do, then they may decline to attest to management’s assessment or may issue a report that is qualified. This could result in an adverse reaction in

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      We have initiated a company-wide review of our internal controls over financial reporting as part of the process of preparing for compliance with Section 404 of the Sarbanes-Oxley Act of 2002 and as a complement to our existing overall program of internal controls over financial reporting. As a result of this on-going review, we have made numerous improvements to the design and effectiveness of our internal controls over financial reporting through the period ended July 31, 2004. We anticipate that improvements will continue to be made.

Recent Accounting Standards

      In October 2004, the FASB concluded that SFAS No. 123R, “Share-Based Payment”, which would require all companies to measure compensation cost for all share-based payments (including employee stock options) at fair value, would be effective for public companies (except small business issuer as defined in SEC Regulation S-B) for interim or annual periods beginning after June 15, 2005. We will adopt SFAS No. 123R on July 1, 2005 and we do not believe the adoption will have a material impact on our consolidated financial statements.

      For our investments, we do not have or use any derivative instruments to hedge the financial risks, 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, short-term money market funds and insured, remarketable government agency securities with interest rate reset maturities of 90 days or less. We do not expect any material loss from our investments. We invest in short term instruments and 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. We believe that we are not currently subject to any 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.

      Based on fiscal 2004 kWh sold, an electricity price change of $0.01 per kWh, would have an estimated annual impact on our net revenue of:

      In fiscal 2004, we purchased substantially all of our power under long-term forward physical delivery contracts for supply to our retail electricity customers under long-term and full requirements sales contracts. We apply the normal purchase, normal sale accounting treatment to our forward purchase supply contracts and our customer sales contracts. Accordingly, we record revenue generated from our sales contracts as energy is delivered to our retail customers, and direct energy costs are recorded when the energy under our long-term forward physical delivery contracts is delivered. During fiscal 2004, we also used financial hedging, or derivative instruments, to hedge our commodity risks to a limited degree. At July 31, 2004, we had no positions in derivative instruments, however, we intend to use derivative instruments in the future as an efficient way of assisting in managing our price and volume risk in energy supply procurement for our retail customers. Some derivative instruments may not qualify as normal purchases and sales and may require mark-to-market accounting and the application of SFAS No. 133 in future periods.

      Since we had no short or long-term debt outstanding at July 31, 2004, 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

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      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-27 of this Annual Report on Form 10-K and is hereby incorporated into this Item 8 by reference.

      None.

      Evaluation of Disclosure Controls and Procedures. Our President, who has assumed the duties and responsibilities of the principal executive officer during the time that Mr. Carter is on administrative leave, 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. As a result of this evaluation which was conducted in the course of preparing our financial statements for the year ended July 31, 2004, and in connection with the corresponding audit by our independent auditors, Ernst & Young LLP, management has determined that our internal controls have not met our expectations.

      We have advised the Audit Committee of our Board of Directors that, in the course of preparing our year-end 2004 financial statements, we noted deficiencies in internal controls relating to the timely reconciliation of energy purchases and related sales.

      Our independent auditors, Ernst & Young LLP, have advised the Audit Committee that these internal control deficiencies constitute a reportable condition and a material weakness as defined in Statement on Auditing Standards No. 60. Immediately prior to the filing of this Annual Report on Form 10-K, we filed amended Quarterly Reports on Form 10-Q/ A for the periods ended January 31, 2004 and April 30, 2004. The amended Quarterly Reports principally restate prior reported results and include additional disclosures in the appropriate period as a result of finding the foregoing weakness in our internal controls.

      With the assistance of our advisors, we continue to evaluate and implement methods to improve our internal controls and procedures. We have taken the following corrective actions, some of which we began to implement as early as May 2004:

	•	Established an energy accounting department to focus on reconciling the physical energy supply and delivery;
	•	Established a risk management oversight committee to assure compliance with our risk management control objectives;
	•	Hired a Director of Internal Audit, reporting directly to our Audit Committee, to monitor and review of adequacy of our internal controls;
	•	Adopted improved accounting policies, procedures and internal controls for the periodic consolidated financial closing process including closer management review of physical energy reconciliations;
	•	Improved the communication between operating, financial and management functions, and expanded our risk management reporting procedures; and
	•	Upgraded our technology in risk management, energy accounting and risk management reporting.

      We have also designed and executed additional procedures to ensure that these disclosure and internal control deficiencies will not result in material misstatements in our consolidated financial statements contained

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      Changes in Internal Control over Fincial Reporting. Other than as described above, there have been no material changes in our internal controls or in other factors that have materially affected or is reasonably likely to materially affect, internal controls subsequent to the date we carried out our evaluation.

      None.

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PART III

Information About Our Directors

      The Company’s Certificate of Incorporation and Bylaws, provide for a “classified” Board of Directors. The number of authorized directors is currently five. Currently, there is one Class I director, whose term expires at the first annual meeting of stockholders to be held after the completion of fiscal 2004; two Class II directors, whose terms expires at the second annual meeting of stockholders to be held after the completion of fiscal 2004; and two Class III directors, whose terms expire at the third annual meeting of stockholders to be held after the completion of fiscal 2004. The following table sets forth information regarding our directors, including their age as of October 22, 2004, 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 the biography below.

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Audit Committee Financial Expert

      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 with Respect to Our Executive Officers

      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) Beneficial Ownership Reporting Compliance

      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% stockholders are required by SEC regulations to furnish us with copies of all Section 16(a) forms they file.

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      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 2004, 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 2004.

      The following persons made late filings of reports under Section 16(a) of the Exchange Act that related to transactions that occurred during fiscal 2004: (a) Ian B. Carter, one of our directors and executive officers, filed late Forms 4 in connection with the exercise of an option to purchase shares of Commonwealth common stock in March 2004 and in connection with the grant of an employee stock option in August 2003; (b) Robert C. Perkins, one of our directors, filed late Forms 4 in connection with the grant of stock options in August 2003 and the conversion of shares of Commonwealth Series A Preferred Stock into Commonwealth Common Stock in July 2004; (c) Craig G. Goodman, one of our directors, filed a late Form 4 in connection with two purchases of Commerce common stock in September 2004; (d) Kenneth L. Robinson, our Corporate Controller, filed a late Form 3 in connection with his initial appointment and filed a late Form 4 in connection the grant of an employee stock option in August 2003; (e) Michael G. Nelson, at the time an executive officer of Commonwealth, filed a late Form 4 in connection with the grant of an employee stock option in December 2003; (f) Linda Guckert, at the time an executive officer of Commonwealth, filed a late Form 4 in connection with the grant of an employee stock option in August 2003; (g) Robert Gunnin, at the time an executive officer of Commonwealth, filed a late Form 3 in connection with his initial appointment; (h) Mark S. Juergensen, one of our directors, filed a late Form 4 in connection with the grant of a stock option in August 2003. In addition, to our knowledge, Joseph P. Saline, Jr., one of Commonwealth’s directors during fiscal 2004, has yet to file a Form 3 in connection with his initial appointment as a director and has not filed any Forms 4 with respect to any purchases or sales of our securities.

Code of Ethics

      We have adopted a code of ethics, entitled the “Commerce Energy Group, Inc. Code of Business Conduct and Ethics,” which applies to, among others, our directors, our principal executive officer, our principal financial officer, our principal accounting officer and all of our other officers and employees. A copy of the Commerce Energy Group, Inc. Code of Business Conduct and Ethics 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 Commerce Energy Group, Inc. Code of Business Conduct and Ethics by including such information as an exhibit in future filings.

Compensation of Our Directors

      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. Each non-employee director is 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) is 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 are 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 is entitled to receive reimbursement for reasonable travel expenses in accordance with our travel expense policy, with respect to each Board or Board Committee meeting that such non-employee director attends in person.

      Stock Options. Prior to fiscal 2004, stock options were awarded to non-employee directors on a case-by-case basis as determined by the Board of Directors. In recognition of their service on Commonwealth’s Board from fiscal 2000 through fiscal 2003, Commonwealth agreed to issue certain stock options to Junona A. Jonas,

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(1)	Represents stock options issued to Mr. Perkins in connection with a Settlement Agreement and Release entered into between Mr. Perkins and Commonwealth in August 2003 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.

      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 if the Board member’s service is terminated; (c) the options shall have a term of 10 years from the date of grant; (d) any vested options may be exercised, during the time the Board member is serving as a director or after such person ceases to be a director, prior to the expiration of the term of the option; and (e) 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 to 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 stockholders 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 if the Board member’s service is terminated; (c) the options shall have a term of 10 years from the date of grant; (d) any vested options may be exercised, during the time the Board member is serving as a director or after such person ceases to be a director, prior to the expiration of the term of the option; and (e) the exercise price shall be the fair market value (as defined in the Plan) of our common stock on the date of grant.

      Each non-employee director is also eligible to receive awards under our 1999 Equity Incentive Plan, which we refer to as the Plan, a discretionary stock option plan. Except as described above, no stock options were issued to our directors for services under the Plan during fiscal 2004.

Compensation of Our Executive Officers

      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

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      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.