UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-Q

(Mark One)

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

For the quarterly period ended January 31, 2005

OR

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

For the transition period from                                         to                                         

Commission File Number 001-32239

COMMERCE ENERGY GROUP, INC.

600 Anton Boulevard, Suite 2000, Costa Mesa, California 92626
(Address of principal executive offices) (Zip Code)

(714) 259-2500
(Registrant’s telephone number, including area code)

Not Applicable
(Former name, former address and former fiscal year, if changed since last report)

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

     Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

     As of March 11, 2005, 30,502,290 shares of the registrant’s common stock were outstanding.

COMMERCE ENERGY GROUP, INC.

Form 10-Q
For the Period Ended January 31, 2005
Index

FORWARD-LOOKING INFORMATION

     A number of the matters and subject areas discussed in this Quarterly Report on Form 10-Q contain forward-looking statements reflecting management’s current expectations. The discussion of such matters and subject areas is qualified by the inherent risks and uncertainties surrounding future expectations generally, and also may differ materially from our actual future experience involving any one or more of such matters and subject areas. We wish to caution readers that all statements other than statements of historical fact included in this Quarterly Report on Form 10-Q regarding our financial position and strategy may constitute forward-looking statements. When used in this document, the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “project,” “plan,” “should,” and similar expressions are intended to be among the statements that identify forward-looking statements. All of these forward-looking statements are based upon estimates and assumptions made by our management, which although believed to be reasonable, are inherently uncertain. Therefore, undue reliance should not be placed on such estimates and statements. No assurance can be given that any of such estimates or statements will be realized and it is likely that actual results will differ materially from those contemplated by such forward-looking statements. Factors that may cause such differences include those set forth in this Quarterly Report on Form 10-Q, as well as the following:

	•	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 to generate and supply to us electricity;
	•	fluctuations in market prices for electricity;
	•	our dependence on the Independent System Operators 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 utilities to transmit and distribute the electricity we sell to our customers.

     We have attempted to identify, in context, certain of the factors that we currently believe may cause actual future experience and results to differ from our current expectations regarding the relevant matter or subject area. In addition to the items specifically discussed above, our business and results of operations are subject to the risks and uncertainties described in this Report in Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and in our Annual Report on Form 10-K for the year ended July 31, 2004 which we filed with the Securities and Exchange Commission on November 15, 2004. In evaluating forward-looking statements, you should consider these risks and uncertainties, together with the other risks described from time to time in our reports and documents filed with the Securities and Exchange Commission, and you should not place undue reliance on these statements. These forward-looking statements speak only as of the date on which the statements were made. We assume no obligation to update the forward-looking information to reflect actual results or changes in the factors affecting such forward-looking information.

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements.

COMMERCE ENERGY GROUP, INC.

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

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COMMERCE ENERGY GROUP, INC.

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

2

COMMERCE ENERGY GROUP, INC.

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

3

COMMERCE ENERGY GROUP, INC.

1. Summary of Significant Accounting Policies

Basis of Presentation

     The condensed consolidated financial statements for the three and six months ended January 31, 2005 include the accounts of Commerce Energy Group, Inc. (the “Company”), its three wholly-owned subsidiaries: Commonwealth Energy Corporation doing business under the brand name electricAmerica, Skipping Stone Inc. (“Skipping Stone”), which was acquired on April 1, 2004, and UtiliHost, Inc. All material intercompany balances and transactions have been eliminated in consolidation.

     At January 31, 2004, the Company’s consolidated financial statements included the accounts of its controlled investment in Summit Energy Ventures, LLC (“Summit”), and its majority ownership in Power Efficiency Corporation (“PEC”). In the fourth quarter of fiscal 2004, the Company terminated its relationship with Summit and its investment in PEC decreased to 39.9% and subsequently, to 36.4% at January 31, 2005. As of July 31, 2004 and as of January 31, 2005, both entities were no longer consolidated. (See Note 4).

Preparation of Interim Condensed Consolidated Financial Statements

     These interim condensed consolidated financial statements have been prepared by the Company’s management, without audit, in accordance with accounting principles generally accepted in the United States. In the opinion of management, these financial statements contain all adjustments (consisting of only normal recurring adjustments) necessary to present fairly the Company’s consolidated financial position, results of operations and cash flows for the periods presented. Certain information and note disclosures normally included in consolidated annual financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted in these consolidated interim financial statements, although the Company believes that the disclosures are adequate to make the information presented not misleading. The condensed consolidated results of operations, financial position, and cash flows for the interim periods presented herein are not necessarily indicative of future financial results. These interim condensed consolidated financial statements should be read in conjunction with the annual consolidated financial statements and the notes thereto included in the Company’s most recent Annual Report on Form 10-K for the year ended July 31, 2004.

Uses of Estimates

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

Reclassifications

     Certain amounts in the condensed consolidated financial statements for the comparative prior fiscal period have been reclassified to be consistent with the current fiscal period’s presentation.

Revenue Recognition

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COMMERCE ENERGY GROUP, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(continued)
(in thousands,except per share and per kWh amounts)

     Energy sales are recognized as the electric power is delivered to customers. The Company’s net revenue is comprised of the following:

     Skipping Stone revenue (which is included in retail energy sales above), after elimination of intercompany transactions, for the three and six months ended January 31, 2005 was $595 and $1,195, respectively, representing approximately 1% of total net revenue for both periods.

Stock-Based Compensation

     The Company accounts for its employee stock options under the recognition and measurement principles of Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees (“APB No. 25”), and related interpretations. Under APB No. 25, no stock-based employee compensation costs are reflected in net income (loss) for the three and six month periods ended January 31, 2005 and 2004, because all options granted under the plans had an exercise price equal to or greater than the market value of the underlying common stock on the date of grant.

     The following table illustrates the effect on net income (loss) as applicable to common stock (see Note 2) and income (loss) per common share if the Company had applied the fair value recognition provisions of Statement of Financial Accounting Standards (“SFAS”) No. 123:

Employee Stock Purchase Plan

     On January 12, 2005, the stockholders of the Company approved the 2005 Employee Stock Purchase Plan (the “ESPP”). The ESPP will allow eligible employees, officers, directors and consultants of the Company and its designated affiliates to purchase, through payroll deductions, shares of the Company’s common stock. As of January 31, 2005, the ESPP had not been implemented.

Segment Reporting

     The Company’s chief operating decision makers consist of members of senior management that work together to allocate resources to, and assess the performance of, the Company’s business. These members of senior

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COMMERCE ENERGY GROUP, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(continued)
(in thousands,except per share and per kWh amounts)

management currently manage the Company’s business, assess its performance, and allocate its resources as a single operating segment. Because the revenue of the Company’s subsidiary, Skipping Stone, which we acquired in fiscal 2004, accounts for approximately 1% of total net revenue (after elimination of intercompany transactions), and geographic information is not relevant, no segment information is provided.

Recent Accounting Standards

     In December 2004, the Financial Accounting Standards Board issued SFAS No. 123 (Revised 2004), Share-Based Payment, (“SFAS No. 123R”), which is a revision to SFAS No. 123 and supersedes APB No. 25 and SFAS No. 148, Accounting for Stock-Based Compensation — Transition and Disclosure. This statement requires that the cost resulting from all share-based payment transactions be recognized in the financial statements. This statement establishes fair value as the measurement objective in accounting for share-based payment arrangements and requires all entities to apply a fair-value based measurement method in accounting for share-based payment transactions with employees except for equity instruments held by employee share ownership plans. SFAS No. 123R applies to all awards granted after the required effective date (the beginning of the first interim or annual reporting period that begins after June 15, 2005) and to awards modified, repurchased, or cancelled after that date. As of the required effective date, all public entities that used the fair-value based method for either recognition or disclosure under SFAS No. 123 will apply this statement using a modified version of prospective application. Under that transition method, compensation costs is recognized on or after the required effective date for the portion of outstanding awards for which the requisite service has not yet been rendered, based on the grant-date fair value of those awards calculated under SFAS No. 123 for either recognition or pro forma disclosures. For periods before the required effective date, those entities may elect to apply a modified version of the retrospective application under which financial statements for prior periods are adjusted on a basis consistent with the pro forma disclosures required for those periods by SFAS No. 123. As a result, beginning in the first quarter of fiscal 2006, the Company will adopt SFAS No. 123R and begin reflecting the stock option expense determined under fair-value based methods in its statement of operations rather than as pro forma disclosure in the notes to the financial statements. The Company has not yet determined whether the adoption of SFAS No. 123R will result in amounts that are similar to the current pro forma disclosures under SFAS No. 123 and it is evaluating the requirements under SFAS No. 123R.

2. Basic and Diluted Income (Loss) per Common Share

     Basic income (loss) per common share was computed by dividing net income (loss) available to common stockholders, after any preferred stock dividends, by the weighted average number of common shares outstanding during the period. Diluted income (loss) per common share reflects the potential dilution that would occur if all outstanding options or other contracts to issue common stock were exercised or converted and was computed by dividing net income (loss) by the weighted average number of common shares plus dilutive common equivalent shares outstanding, unless they were anti-dilutive.

     The following is a reconciliation of the numerator (income or loss) and the denominator (common shares in thousands) used in the computation of basic and diluted income (loss) per common share:

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COMMERCE ENERGY GROUP, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(continued)
(in thousands,except per share and per kWh amounts)

     For the three and six months ended January 31, 2004, the effects of the assumed exercise of all stock options and the assumed conversion of preferred stock into common stock are anti-dilutive; accordingly, such assumed exercises and conversions have been excluded from the calculation of net loss — diluted. If the assumed exercises or conversions had been used, the fully diluted shares outstanding for the three and six months ended January 31, 2004 would have been 29,087 and 29,118, respectively.

3. Market and Regulatory

California

     The 1996 California Assembly Bill (“AB”) 1890 codified the restructuring of the California electric industry and provided for the right of direct access (“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, the Company began supplying customers in California with electricity as an Electric Service Provider (“ESP”).

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

     In July 2002, the CPUC authorized Southern California Edison (“SCE”) to implement a Historical Procurement Charge (“HPC”), to repay debt incurred during the energy crisis. This amount is currently being collected by SCE as a $0.01 per kilowatt-hour (“kWh”) surcharge on the retail electricity bill paid by the Company’s customers. SCE estimates that full payment could be achieved as soon as early 2006. While the HPC does not directly impact the Company’s rate design or revenue, it may affect the Company’s ability to retain existing customers or compete for new customers.

     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 Cost Responsibility Surcharge (the “DA CRS”) is currently fixed at $0.027 per kWh. The 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 who were enrolled in DA prior to February 1, 2001, and are in the SCE service territory continue to pay only the $0.01 HPC. While this charge does not directly impact the Company’s rate design or revenue, it may affect the Company’s ability to retain existing customers or compete for new customers.

     In December 2003, Pacific Gas and Electric (“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 the Company’s 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 the Company.

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COMMERCE ENERGY GROUP, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(continued)
(in thousands, except per share and per kWh amounts)

Pennsylvania

     In 1996, the Electricity Generation Customer Choice and Competition Act was passed. This 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. The Company 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 the Company’s financial results.

Michigan

     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. The Company began marketing in Michigan’s Detroit Edison (“DTE”) service territory in September 2002.

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

     In November 2004, the MPSC issued the final order in the DTE General Rate case making slight changes in the rates originally approved in the interim order issued in February 2004. The final order reinstated a small percentage of savings of large commercial customers who choose an alternative electric supplier, while generally maintaining the charges for smaller commercial customers. More notable changes were made to rules regarding moving between the local utility and alternative suppliers. New customers electing service from alternative providers must remain outside utility service for a minimum of two years. Additionally, the local utility now requires substantial notice prior to returning to their service. Overall rate and rule changes are not expected to have a significant impact to the Company’s ability to retain its existing customers and obtain new 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.

New Jersey

     Deregulation activities began in New Jersey in November 1999 when the Board of Public Utilities, or BPU, approved the implementation plan. The Company 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 the Company’s ability to remain competitive against the comparable utility pricing.

4. Investments

     The Company has three investments in early-stage, energy related entities incurring operating losses, which are expected to continue, at least in the near term: Encorp, Inc. (“Encorp”), Turbocor B.V. (“Turbocor”) and Power Efficiency Corporation (“PEC”). Each company has very limited working capital and as a result, continuing

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COMMERCE ENERGY GROUP, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(continued)
(in thousands, except per share and per kWh amounts)

operations will be dependent upon their securing additional financing to meet their respective immediate capital needs. The Company has no obligation, and currently no intention to invest additional funds into these companies.

     At January 31, 2005, the Company’s ownership interest in Encorp, Turbocor and PEC was 1.9%, 6.5% and 36.4%, respectively. The Company accounts for its investment in Encorp and Turbocor under the cost method of accounting. The Company currently accounts for its investment in PEC (ticker symbol: PEFF) under the equity method of accounting. At January 31, 2004, PEC was consolidated in the Company’s financial statements. In fiscal 2004, these investments were written down to $96. In fiscal 2005, these investments are carried at $91 and have no material impact on our financial statements.

5. Commitments and Contingencies

Commitments

Purchase Commitments

     On January 28, 2005, the Company made a strategic decision to discontinue service to certain customers in the Pennsylvania service territory, specifically certain residential and small commercial customers. In connection with that decision, the Company sold back future electricity supply commitments related to serving those customers to its energy supplier. The supply commitments would have provided the Company with electricity to serve the discontinued customers’ electricity requirements through May 2006. The transaction occurred in January 2005 and resulted in a gain on the sale of the supply commitments of $9,301, which has been reflected in the Company’s financial statements for its second fiscal quarter ending January 31, 2005. The Company will continue to serve remaining customers in the Pennsylvania territory from remaining supply contracts with other wholesale suppliers. After giving effect to the supply commitment that was sold in the Pennsylvania territory and any new supply commitments entered into in the second fiscal quarter, the following is a summary of the Company’s commitments to purchase electric power as of January 31, 2005:

Contingencies

Employment Settlements

     As of January 31, 2005, the Company has recorded a $3,600 reserve for potential employment related settlements.

Litigation

     On November 25, 2003, several stockholders filed a lawsuit against the Company entitled Coltrain, et al. v. Commonwealth Energy Corporation, et al. The complaint purported to be a class action against the Company for violations of section 709 of the California Corporations Code. This action was dismissed for lack of prosecution on January 21, 2005.

     On December 23, 2004, the Company entered into a full and comprehensive Settlement Agreement and Mutual General Release (“Settlement Agreement”) with stockholder and former director of Commonwealth Energy

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COMMERCE ENERGY GROUP, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(continued)
(in thousands, except per share and per kWh amounts)

Corporation, Joseph P. Saline, and stockholder Joseph Ogundiji. The Settlement Agreement effectively ended all legal actions between the parties that began in 2001. The Settlement Agreement acknowledges and validates Mr. Saline’s shares of common stock in the Company and provides for a $1,200 settlement payment to Mr. Saline. The Settlement Agreement also provides Mr. Ogundiji with a payment of $222 in settlement of all of his claims and for canceling all of his shares of common stock. In addition, Mr. Saline and Mr. Ogundiji agreed that for the next two years they would submit any future disputes to mediation before commencing litigation or before they take any steps to contact the Company’s stockholders for any reason. The Company accrued $1,200 in October of 2004 for the settlement with Mr. Saline and the $222 settlement for Mr. Ogundiji was recorded as cancellation of stock with no income statement effect.

     On February 18, 2005, the court struck the defendant’s answers and dismissed their counter-claim in Commonwealth Energy Corporation v. Wayne Mosley, et al. for failure to prosecute and failure to comply with orders of the court.

     The Company currently is, and from time to time may become, involved in other litigation concerning claims arising out of the Company’s operations in the normal course of business. While the Company cannot predict the ultimate outcome of its pending matters or how they will affect the Company’s results of operations or financial position, the Company’s management currently does not expect any of the legal proceedings to which the Company is currently a party, including the legal proceedings described above, individually or in the aggregate, to have a material adverse effect on its results of operations or financial position beyond the accruals provided as of January 31, 2005.

6. Derivative Financial Instruments

     The Company’s activities expose it to a variety of market risks, including commodity prices and interest rates. Management has established risk management policies and procedures designed to reduce the potentially adverse effects that the price volatility of these markets may have on its operating results. The Company’s risk management activities, including the use of derivative instruments, are subject to the management, direction and control of an internal risk oversight committee. The Company maintains commodity price risk management strategies that use derivative instruments within strict risk tolerances to minimize significant, unanticipated earnings fluctuations caused by commodity price volatility. Derivative instruments measured at fair market value are recorded on the balance sheet as an asset or liability. Changes in fair market value are recognized currently in earnings unless specific hedge accounting criteria are met.

     Supplying electricity to retail customers requires the Company to match customers’ projected demand with fixed price purchases. The Company primarily uses forward physical energy purchases and to a lesser extent derivative instruments to minimize significant, unanticipated earnings fluctuations caused by commodity price volatility. In certain markets where the Company operates, entering into forward fixed price contracts may be expensive relative to derivative alternatives. Derivative instruments, primarily swaps and futures, are used to hedge the future purchase price of electricity for the applicable forecast usage protecting the Company from significant price volatility. In the first and second fiscal quarters of 2005, certain forward fixed price purchases and swap agreements were designated as cash flow hedges resulting in changes in the hedge value being deferred in other comprehensive income (“OCI”). To the extent that the hedges are not effective, the ineffective portion of the changes in fair market value was recorded in direct energy costs. The Company also entered into transactions that did not qualify as accounting hedges but were designed to take advantage of trends in wholesale power prices to reduce its direct energy costs. In such cases, the changes in the fair value of these transactions are recorded in earnings as a component of direct energy costs. The Company did not engage in trading activities in the wholesale energy market other than to manage its direct energy cost.

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COMMERCE ENERGY GROUP, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(continued)
(in thousands, except per share and per kWh amounts)

     The amounts recorded in OCI at January 31, 2005 related to cash flow hedges are summarized in the following table:

7. Subsequent Event

     On February 9, 2005, the Company and its wholly-owned subsidiary, Commonwealth Energy Corporation, entered into an agreement with American Communications Network, Inc. (“ACN”), and several of its subsidiaries, ACN Utility Services, Inc., ACN Energy, Inc. and ACN Power, Inc. (collectively the “Sellers”) to purchase certain assets of the Sellers, retail electric power and natural gas sales business, and assume specified liabilities. The Sellers sell retail electric power in Texas and Pennsylvania and sell retail natural gas in California, Ohio, Georgia, New York, Pennsylvania and Maryland. The assets acquired include equipment, gas inventory associated with utility and pipeline storage and transportation agreements and electricity supply, scheduling and capacity contracts, software and other infrastructure plus approximately 80 residential and small commercial customers. The initial consideration paid by the Company was (a) $6,500 in cash, plus (b) 930 shares of the Company’s common stock, valued at $2,000, based upon the market price for the Company’s common stock as of February 8, 2005, the date immediately prior to the closing date. The shares of the Company’s common stock will initially be placed in escrow and released upon satisfaction of certain performance targets related to customer growth. ACN was also paid at closing an estimated prepayment amount of approximately $5,500 as payment for certain working capital and prepayment items relating to the assets being acquired, and are subject to final adjustment and settlement. The Company has sufficient cash to cover the needs of this acquisition.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Overview

     We are a diversified energy services company. We provide electric power to our residential, commercial, industrial and institutional customers in the California, Pennsylvania, Michigan and New Jersey electricity markets. We are licensed by the Federal Energy Regulatory Commission, or FERC, as a power marketer. In addition to the state agencies in which we currently operate, we are also licensed to supply retail electric power by applicable state agencies in New York, Maryland, Texas, Ohio and Virginia. Unless otherwise noted, as used herein, “the Company,” “we,” “us,” and “our” mean Commerce Energy Group, Inc. and its three wholly-owned subsidiaries: Commonwealth Energy Corporation, doing business under the brand name electricAmerica, Skipping Stone Inc. or Skipping Stone, and UtiliHost, Inc.

     As of January 31, 2005, we delivered electricity to approximately 94,000 customers in California, Pennsylvania, Michigan and New Jersey. The growth of this business depends upon the degree of deregulation in each state, the availability of energy at competitive prices, 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 renewal energy assets. The electric power we sell is generally metered and delivered to our customers by 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 facilitate 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.

     We buy electricity in the wholesale market in blocks of time-related quantities usually at fixed prices. We sell electricity in the real time market based on the demand from our customers at contracted prices. We manage the inherent mismatch between our block purchases and our sales by buying and selling in the spot market. In addition, the independent system operators (“ISO”), the entities which manage each of the electric grids in which we operate, perform real time load balancing. We are charged or credited for electricity purchased and sold for our account by the ISO.

     There are inherent risks and uncertainties in our core business operations. These include: regulatory uncertainty, timing differences between our purchases and sales of electricity, forecasting error between our estimated customer usage and the customer’s actual usage, weather related changes in quantities demanded by our customers, customer attrition, spread changes between on-peak and off-peak power pricing and seasonal differences between summer and winter demand, and spring and fall demand seasons, unexpected factors in the wholesale power markets such as regional power plant outages, volatile fuel prices (used to generate the electricity that we buy), transmission congestion or system failure, and credit related counter-party risk for us or within the grid system generally. Accordingly, these uncertainties may produce results that may differ from our internal forecasts. For a discussion of other risks related to the operation of our business, see the discussion herein under the caption “Factors That May Affect Future Results.”

     Skipping Stone, which we acquired in April 2004, provides energy-related consulting and technologies to utilities, electricity generators, natural gas pipelines, wholesale energy merchants, energy technology providers and investment banks. Skipping Stone’s revenue (after elimination of intercompany transactions) was approximately 1% of our consolidated net revenue for the three and six months ended January 31, 2005.

     In fiscal 2004, we consolidated Summit Energy Ventures, or Summit, and its majority interest in Power Efficiency Corporation, or PEC, into our financial results. In the third fiscal quarter of 2004, we terminated our relationship with Summit. We no longer consolidate Summit and PEC in our current fiscal year financial results as we retained a 39.9% interest in PEC. At January 31, 2005, our ownership interest was diluted to 36.4% as a result of

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an equity linked financing by PEC. Although we currently account for our investment in PEC under the equity method of accounting, in fiscal 2004, we recorded a loss sufficient to reduce our investment basis in PEC to zero and, therefore, it will have no negative impact on our financial results in fiscal 2005 or in the future.

     The information in this Item 2, should be read in conjunction with the audited consolidated financial statements and notes thereto and Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in the Company’s Annual Report on Form 10-K for the year ended July 31, 2004, and the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report.

Market and Regulatory

California

     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 the HPC does not directly impact our rate design or revenue, it may affect our ability to retain existing customers or compete for new customers.

     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 Cost Responsibility Surcharge, or the DA CRS, is currently fixed at $0.027 per kWh. The 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 who were enrolled in DA prior to February 1, 2001, and are 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.

Pennsylvania

     In 1996, the Electricity Generation Customer Choice and Competition Act was passed. This 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

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Pennsylvania territory in 1999. There are no current rate cases or filings regarding this territory that are anticipated to impact our financial results.

Michigan

     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.

     In November 2004, the MPSC issued the final order in the DTE General Rate case making slight changes in the rates originally approved in the interim order issued in February 2004. The final order reinstated a small percentage of savings of large commercial customers who choose an alternative electric supplier, while generally maintaining the charges for smaller commercial customers. More notable changes were made to rules regarding moving between the local utility and alternative suppliers. New customers electing service from alternative providers must remain outside utility service for a minimum of two years. Additionally, the local utility now requires substantial notice prior to returning to their service. Overall rate and rule changes are not expected to have a significant impact to our ability to retain our existing customers and obtain new 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.

New Jersey

     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 Form 10-Q requires us to make estimates and assumptions that affect the reported amount 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 condensed 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.

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	•	Purchase and sale accounting — In fiscal 2004 and 2005, we purchased substantially all of our power under long-term forward physical delivery contracts for supply to our retail electricity customers. 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. In the first and second quarters of fiscal 2005, we also employed financial hedges using derivative instruments, to hedge our commodity price risks. In the first fiscal quarter of 2005, certain forward fixed price purchases and swap agreements were designated as cash flow hedges resulting in changes in the hedge value being recorded as other comprehensive income, or OCI. To the extent that the hedges are not effective, the ineffective portion of the changes in fair market value is recorded currently in direct energy costs. We intend to use derivative instruments as an efficient way of assisting in managing our price and volume risk in energy supply procurement for our retail customers. Certain derivative instrument treatment may not qualify for hedge treatment and require mark-to-market accounting in accordance with the Financial Accounting Standards Board, or FASB, Statement of Financial Accounting Standard, or SFAS, No. 133, “Accounting for Derivative Instruments and Hedging Activities”.
	•	Independent system operator costs — Included in direct energy costs, along with electric power that we purchase, are scheduling coordination costs and other 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 settlement (which may take from one to several months), we estimate these costs based on historical trends and preliminary settlement information. The historical trends and preliminary information may differ from actual fees resulting in the need to adjust the 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 condition of our customers were to deteriorate, resulting in an impairment of their ability to make payments, additional allowances may be required.
	•	Unbilled receivables — Our customers are billed monthly at various dates throughout the month. Unbilled receivables represent the amount of electric power delivered to customers at the end of a 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 SFAS 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

     In the following comparative analysis, all percentages are calculated based on dollars in thousands. The states of Pennsylvania and New Jersey are within the same ISO territory and procurement of power is not managed separately, therefore, they are referred to as the Pennsylvania market below.

Three months ended January 31, 2005 compared to three months ended January 31, 2004.

     Net revenue of $61.0 million increased by $14.0 million, or 30%, for the three months ended January 31, 2005 compared to the three months ended January 31, 2004. Gross profit increased $8.8 million to $12.1 million for the three months ended January 31, 2005 compared to $3.3 million for the same prior year period. The revenue and gross profit improvement in the three months ended January 31, 2005 was primarily due to the sale of a portion of

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our Pennsylvania energy supply for $9.3 million and an increase in excess energy sales of $5.9 million. On January 28, 2005, we made a strategic decision to discontinue service to certain residential and small commercial customers in the Pennsylvania territory, and sold back electricity supply commitments to our energy supplier for $9.3 million. The Company’s operating results for the three months ended January 31, 2005 included income from operations of $1.3 million compared to a loss of $4.6 million for the same prior year period.

Net revenue

Retail energy sales

     Retail energy sales decreased $1.2 million, or 3%, to $44.8 million in the three months ended January 31, 2005 compared to $46.0 million in the same period in the prior fiscal year. The decrease resulted primarily from decreased energy sales of $3.9 million in California and $1.1 million in Pennsylvania offset by an increase in Michigan of $3.3 million compared to the prior year period. In California, we sold 201 million kWh at an average retail price per kWh of $0.071 in the three months ended January 31, 2005, as compared to 267 million kWh sold at an average retail price per kWh of $0.068 in the same period last year. The decrease in volume was primarily attributable to customer attrition due in part to our efforts to improve profitability per customer. In Pennsylvania, we sold 328 million kWh at an average retail price per kWh of $0.057 in the three months ended January 31, 2005, as compared to 305 million kWh sold at an average retail price per kWh of $0.065 in the same period last year. The volume increase was primarily due to our increased customer base in the current year in New Jersey which was offset by an average price decrease in this territory due to unstable prices as we entered this new market at the end of fiscal 2004. In Michigan, we sold 190 million kWh at an average retail price per kWh of $0.060 in the three months ended January 31, 2005, as compared to 151 million kWh at an average retail price per kWh of $0.054 in the same period last year. The increase in volume was primarily due to continued increases in our Michigan customer base.

Excess energy sales

     Excess energy sales increased $15.2 million to $16.2 million in the three months ended January 31, 2005 compared to $1.0 million in the same period in the prior year. The increase is attributable to the $9.3 million sale of future electricity supply in Pennsylvania and the sale of excess energy for California operations of $2.3 million and for Pennsylvania operations of $3.6 million compared to the prior fiscal second quarter.

     Excess energy sales represents the proceeds from surplus electric power we sell back into the wholesale market when the electricity we have acquired exceeds our retail customer’s requirements. The sale of excess energy supply is a natural by-product of balancing the power load used by our customers against the power that we have previously purchased under contract in anticipation of our forecast customer demand. Due to the inherent mismatch between our block purchases and our retail demand and the volatility of customer load from day-to-day and within a given day, and the volatility of prices on the spot market, significant fluctuations in excess energy sales can occur from the optimization of the Company’s supply portfolio and customer demand.

     At January 31, 2005, we had approximately 94,000 customers compared to 107,000 customers at January 31, 2004. We experienced higher attrition as rates increased in California by 17% and in Pennsylvania by 14%. We increased our customer base in Michigan by 29% and began to market in New Jersey in December 2003.

Direct energy costs

     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 $48.9 million for the three months ended January 31, 2005, an increase of $5.1 million, or 12%, from $43.8 million for the three months ended January 31, 2004.

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     The increase in direct energy costs occurred primarily in Michigan and California, with a partial offset in Pennsylvania. In Michigan, our average cost per kWh was $0.052 for the three months ended January 31, 2005, as compared to an average cost per kWh of $0.047 for the same period last year. In California, our average cost per kWh was $0.061 for the three months ended January 31, 2005, as compared to an average cost per kWh of $0.056 for the same period in fiscal 2004. In Pennsylvania, our average cost per kWh was $0.056 for the three months ended January 31, 2005, as compared to an average cost per kWh of $0.063 for the same period in fiscal 2004.

Selling and marketing expenses

     Our selling and marketing expenses decreased $0.2 million, or 25%, to $0.8 million for the three months ended January 31, 2005, as compared to $1.0 million for the three months ended January 31, 2004. The decrease was primarily due to lower advertising costs in the current fiscal quarter.

General and administrative expenses

     Our general and administrative expenses increased $4.2 million, or 72%, to $10.0 million for the three months ended January 31, 2005 compared to $5.8 million in the three months ended January 31, 2004. The increase in the current fiscal year was primarily attributed to a $3.6 million reserve for potential employment related settlements and severance of $0.5 million.

Reorganization and initial public listing expenses

     We incurred $1.0 million in the second quarter of 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 believed it was appropriate to classify these costs as a separately identified selling, general and administrative expense category, and included expenses such as legal, accounting, auditing, consulting, and printing and reproduction fees that were specific to these activities. We incurred no such expenses in fiscal 2005.

Initial formation litigation expenses

     In the three months ended January 31, 2005, we incurred $0.2 million of initial formation litigation costs related to Commonwealth Energy Corporation’s formation compared to no such costs during the three months ended January 31, 2004. Initial formation litigation expenses include legal and litigation costs associated with the initial capital raising efforts by former Commonwealth Energy Corporation employees, various board member matters, and the legal complications arising from those activities.

Provision for impairment on investments

     In the three months ended January 31, 2004, we recorded an impairment of $4.3 million on our investments, to reflect our percentage ownership in the net equity of each of Summit’s two investments: Turbocor and Encorp, Inc. (formerly Envenergy, Inc.).

Minority interest share of loss

     Minority interests in fiscal 2004 represent that portion of PEC’s post-consolidation losses that are allocated to the non-Summit investors based on their aggregate minority ownership interest in PEC. PEC is no longer consolidated in our financial statements in fiscal 2005.

Benefit from income taxes

     No provision for, or benefit from, income taxes was recorded for the three months ended January 31, 2005; as compared to the benefit from income taxes of $0.8 million for the three months ended January 31, 2004. In fiscal

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2005, we established a valuation allowance equal to our calculated tax benefit because we believed it was not certain that we would realize these tax benefits in the foreseeable future. The current period results are not sufficient to modify this conclusion.

Six months ended January 31, 2005 compared to six months ended January 31, 2004.

     Net revenue increased $14.1 million, or 13%, to $119.5 million for the six months ended January 31, 2005 as compared to $105.4 million in the six months ended January 31, 2004. Gross profit increased $10.6 million to $18.2 million for the six months ended January 31, 2005 as compared to $7.6 million for the same prior year period. The revenue and gross profit improvement in the six months ended January 31, 2005 was primarily due to the sale of a portion of the future Pennsylvania energy supply for $9.3 million, an increase in excess energy sales of $9.5 million and increased gross profit in Michigan and New Jersey due to increased customer base offset by the continuing pressure on gross profit in the California business. The Company’s operating results for the six months ended January 31, 2005 included income from operations of $1.4 million compared to a loss of $6.9 million for the same prior year period.

Net revenue

Retail energy sales

     Retail energy sales decreased $4.7 million, or 5%, to $97.5 million in the current fiscal year compared to $102.2 million for the six months ended January 31, 2004. The decrease resulted primarily from decreased energy sales of $8.3 million in California and $3.1 million in Pennsylvania offset by an increase in Michigan of $5.6 million compared to the prior year period. In California, we sold 462 million kWh at an average retail price per kWh of $0.072 in the six months ended January 31, 2005, as compared to 595 million kWh sold at an average retail price per kWh of $0.070 in the same period last year. The decrease in volume was primarily attributable to customer attrition due in part to our efforts to improve profitability per customer. In Pennsylvania, we sold 675 million kWh at an average retail price per kWh of $0.059 in the six months ended January 31, 2005, as compared to 699 million kWh sold at an average retail price per kWh of $0.061 in the same period last year. The decrease in volume was primarily due to decreases attributable to customer attrition due in part to our efforts to improve profitability per customer offset by increases in our New Jersey customer base in the current fiscal year, while the price continues to fluctuate in this new market. In Michigan, we sold 399 million kWh at an average retail price per kWh of $0.059 in the six months ended January 31, 2005, as compared to 330 million kWh at an average retail price per kWh of $0.054 in the same period last year. The increase in volume was primarily due to continued increases in our Michigan customer base.

Excess energy sales

     Excess energy sales increased $18.7 million to $22.0 million in the six months ended January 31, 2005, as compared to $3.3 in the same period in the prior year. The increase is attributable to the $9.3 million sale of future electricity supply in Pennsylvania and the sale of excess energy for California operations of $4.3 million and for Pennsylvania operations of $5.2 million as compared to the six months ended January 31, 2004.

Direct energy costs

     Our direct energy costs increased to $101.3 million for the six months ended January 31, 2005, an increase of $3.4 million, or 4%, from $97.9 million for the six months ended January 31, 2004. The increase in direct energy costs occurred primarily in Michigan and California partially offset by decreases in Pennsylvania related to the new New Jersey market. In Michigan, our average cost per kWh was $0.051 for the six months ended January 31, 2005, as compared to an average cost per kWh of $0.047 for the same period last year. In California, our average cost per kWh was $0.060 for the six months ended January 31, 2005, as compared to an average cost per kWh of $0.055 for

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the same period in fiscal 2004. In Pennsylvania, our average cost per kWh was $0.056 for the six months ended January 31, 2005, as compared to an average cost per kWh of $0.063 for the same period in fiscal 2004.

Selling and marketing expenses

     Our selling and marketing expenses decreased $0.3 million, or 13%, to $1.7 million for the six months ended January 31, 2005, as compared to $2.0 million for the six months ended January 31, 2004. The decrease is primarily due to decreased advertising costs in the current fiscal period.

General and administrative expenses

     Our general and administrative expenses increased $3.8 million, or 33%, to $15.1 million for the six months ended January 31, 2005 compared to $11.3 million in the six months ended January 31, 2004. The increase was primarily attributed to a $3.6 million reserve for potential employment related settlements.

Reorganization and initial public listing expenses

     We incurred $1.1 million in the six months ended January 31, 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 believed it was appropriate to classify these costs as a separately identified selling, general and administrative expense category, and included expenses such as legal, accounting, auditing, consulting, and printing and reproduction fees that were specific to these activities. We incurred no such expenses in fiscal 2005.

Initial formation litigation expenses

     In the six months ended January 31, 2005, we incurred $1.6 million of initial formation litigation costs related to Commonwealth Energy Corporation’s formation compared to $0.6 million incurred during the six months ended January 31, 2004. Initial formation litigation expenses include legal and litigation costs associated with the initial capital raising efforts by former Commonwealth Energy Corporation employees, various board member matters, and the legal complications arising from those activities.

Minority interest share of loss

     Minority interests in fiscal 2004 represent that portion of PEC’s post-consolidation losses that are allocated to the non-Summit investors based on their aggregate minority ownership interest in PEC. PEC is no longer consolidated in our financial statements in fiscal 2005.

Benefit from income taxes

     No provision for, or benefit from, income taxes was recorded for the six months ended January 31, 2005; as compared to the benefit from income taxes of $1.8 million for the six months ended January 31, 2004. In fiscal 2005, we established a valuation allowance equal to our calculated tax benefit because we believed it was not certain that we would realize these tax benefits in the foreseeable future. The current period results are not sufficient to modify this conclusion.

Liquidity and Capital Resources

     As of January 31, 2005, our unrestricted cash and cash equivalents were $50.0 million, compared to $54.1 million at July 31, 2004 and our restricted cash and cash equivalents were $4.3 million, compared to $4.0 million at July 31, 2004. In addition to restricted cash, we also had cash deposits of $6.7 million at January 31, 2005, compared to $5.4 million at July 31, 2004. Our principal sources of liquidity to fund ongoing operations were cash provided by operations and existing cash and cash equivalents.

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     Cash flow used in operations for the six months ended January 31, 2005 was $3.2 million, compared to cash flow provided by operations of $5.4 million in the six months ended January 31, 2004. In the six months ended January 31, 2005, cash was used primarily by an increase in accounts receivable of $2.4 million and a decrease in accounts payable of $7.3 million offset by a decrease in prepaid expenses of $2.0 million primarily due to a prepayment contract ending in December 2004.

     Cash flow used in investing activities for the six months ended January 31, 2005 was $0.3 million compared to $0.6 million for the six months ended January 31, 2004. Cash used in investments consisted of capital expenditures.

     Cash flow used in financing activities for the six months ended January 31, 2005 was $0.5 million, compared to cash flow provided by financing activities of $8.6 million in the six months ended January 31, 2004. In the current fiscal year, cash flow used was primarily for the cancellation of common stock and increased restricted cash primarily for increased required letters of credit in New Jersey. In the prior fiscal year, restricted cash decreased primarily due to the cancellation of the required security for an appeals bond of $4.1 million related to a settled litigation and the $3.5 million reduction of the required letters of credit secured by cash related to energy suppliers.

     The Company does not have open lines of credit for direct unsecured borrowings or 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. If we are required to post such additional security, a portion of our cash would become restricted, which could adversely affect our liquidity. As of January 31, 2005, we had $4.3 million in restricted cash to secure letters of credit required by our suppliers and $6.5 million in deposits pledged as collateral in connection with energy purchase agreements.

     Based upon our current plans, level of operations and business conditions, we believe that our cash and cash equivalents, and cash generated from 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.

Contractual Obligations

     There have been no material changes to contractual obligations from the disclosures set forth in Part II, Item 7 in our Annual Report on Form 10-K for the year ended July 31, 2004, except as set forth below.

     In January 2005, we sold back our electricity supply commitments related to serving certain residential and small commercial customers, in the Pennsylvania territory, to our energy supplier. The supply commitments would have provided us with electricity to serve the discontinued customers’ electricity requirements through May 2006. The transaction occurred in January 2005 and resulted in a gain on the sale of the supply commitments of $9.3 million, which has been reflected in our financial statements for our second fiscal quarter ending January 31, 2005. We will continue to serve remaining customers in the Pennsylvania territory from remaining supply contracts with other wholesale suppliers. After giving effect to the supply commitment that was sold in the Pennsylvania territory and any new supply commitments entered into in the second fiscal quarter, our contractual commitments for electricity purchase contracts as of January 31, 2005 are $55.1 million, of which $54.8 million is for less than one year and $0.3 million is for more than one year through March 2006.

Subsequent Event

     On February 9, 2005, we entered into an agreement with American Communications Network, Inc. (“ACN”), and several of its subsidiaries, ACN Utility Services, Inc. (“ACN Utility”), ACN Energy, Inc. (“ACN Energy”) and ACN Power, Inc. (“ACN Power”, and collectively with ACN Utility and ACN Energy, the “Sellers”) to purchase certain assets of the Sellers’ retail electric power and natural gas sales business, and assume specified liabilities. The Sellers sell retail electric power in Texas and Pennsylvania and sell retail natural gas in California, Ohio,

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Georgia, New York, Pennsylvania and Maryland. The assets acquired include equipment, gas inventory associated with utility and pipeline storage and transportation agreements and electricity supply, scheduling and capacity contracts, software and other infrastructure plus approximately 80,000 residential and small commercial customers. The initial consideration paid by us was (a) $6.5 million in cash, plus (b) 930,233 shares of our common stock, valued at $2.0 million, based upon the market price for our common stock as of February 8, 2005, the date immediately prior to the closing date. The shares of common stock will initially be placed in escrow and released upon satisfaction of certain performance targets related to customer growth. ACN was also paid at closing an estimated prepayment amount of approximately $5.5 million as payment for certain working capital and prepayment items relating to the assets being acquired, and are subject to final adjustment and settlement. We have sufficient cash to cover the needs of this acquisition. This transaction was previously reported by us on a current report on Form 8-K filed with the Securities and Exchange Commission on February 10, 2005.

Factors That May Affect Future Results

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

     The Federal Energy Regulatory Commission, 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. 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 other 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 be assured 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 truly 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.

We face many uncertainties that may cause substantial operating losses and we cannot assure stockholders that we can achieve and maintain profitability.

     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;

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	•	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 may have difficulty obtaining a sufficient number of customers.

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

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

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

     To provide electricity to our customers, we must, from time to time, purchase electricity in the short-term or spot wholesale energy markets, which can be highly volatile. In particular, the wholesale electric power market can experience large price fluctuations during peak load periods. Furthermore, to the extent that we enter into contracts with customers that require us to provide electricity at a fixed price over an extended period of time, and to the extent that we have not purchased electricity to cover those commitments, we may incur losses caused by rising wholesale electricity prices. Periods of rising electricity prices may reduce our ability to compete with 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.

     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.

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

     Under a Settlement agreement with the California 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 estimated that HPC charges had impacted our sales and pretax earnings by a range of $4.8 million to $6.0 million. We were unable to precisely determine the actual HPC charges applied to our customers by SCE because there were different charges, by customer type, and this charge was 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 indirectly includes the former impact of the HPC. This rate reduction impacted sales and pretax profit in the SCE district. The rate reduction remained in place in 2004 and approximated the effect of the HPC dollar impact of 2003.

     In 2003, 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.

Some suppliers of electricity have been experiencing deteriorating credit quality.

     We continue to monitor our suppliers’ credit quality to attempt to reduce the impact of any potential counterparty default. As of January 31, 2005, 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.

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

     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 our potential default on the contract. If we are required to post such security, a portion of our cash would become restricted, which could adversely affect our liquidity.

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

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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 required to bear credit risk and billing responsibility for our customers.

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

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

     We sell electricity that we purchase from third-party power generation companies to our retail customers on a contractual basis. We are not guaranteed any rate of return through 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 stream flow,
	•	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 may experience difficulty in integrating and managing acquired businesses successfully and in realizing anticipated economic, operational and other benefits in a timely manner

     We recently completed the acquisition of certain assets of ACN Energy, Inc. The ultimate success of this acquisition depends, in part, on our ability to realize the anticipated synergies, cost savings and growth opportunities from integrating ACN Energy’s business into our existing businesses.

If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential stockholders could lose confidence in our financial reporting, which would harm our business and the trading price of our stock.

     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 fiscal 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 fiscal 2004 and 2005, 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 fiscal 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.

Investor confidence and share value may be adversely impacted if our independent auditors are unable to provide us with the attestation of the adequacy of our internal controls over financial reporting as of July 31, 2006, as required by Section 404 of the Sarbanes-Oxley Act of 2002.

     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, 2006. 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 the financial marketplace due to a loss of investor confidence in the reliability of our financial statements, which ultimately could negatively impact the market price of our shares.

     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

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made numerous improvements to the design and effectiveness of our internal controls over financial reporting through the period ended January 31, 2005. We anticipate that improvements will continue to be made.

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

     There have been no material changes to information called for by this Item 3 from the disclosures set forth in Part II, Item 7A in the Company’s Annual Report on Form 10-K for the year ended July 31, 2004, except as set forth below.

     Our activities expose us to a variety of market risks including commodity prices and interest rates. Management has established risk management policies and strategies to reduce the potentially adverse effects that the price volatility of these markets may have on our operating results. Our risk management activities, including the use of derivative instruments, are subject to the management, direction and control of an internal risk oversight committee. We maintain commodity price risk management strategies that use derivative instruments within strict risk tolerances to minimize significant, unanticipated earnings fluctuations caused by commodity price volatility. Derivative instruments measured at fair market value are recorded on the balance sheet as an asset or liability. Changes in fair market value are recognized currently in earnings unless specific hedge accounting criteria are met.

     Supplying electricity to retail customers requires us to match customers’ projected demand with fixed price purchases. We primarily use forward physical energy purchases and derivative instruments to minimize significant, unanticipated earnings fluctuations caused by commodity price volatility. In certain markets where we operate, entering into forward fixed price contracts may be expensive relative to derivative alternatives. Derivative instruments, primarily swaps and futures, are used to hedge the future purchase price of electricity for the applicable forecast usage protecting us from significant price volatility. In the first and second fiscal quarters of 2005, certain forward fixed price purchases and swap agreements were designated as cash flow hedges resulting in changes in the hedge value being deferred in other comprehensive income (“OCI”). To the extent that the hedges are not effective, the ineffective portion of the changes in fair market value was recorded in direct energy costs. We also entered into transactions that did not qualify as accounting hedges but were designed to take advantage of trends in wholesale power prices to reduce our direct energy costs. Some of these transactions do not qualify for hedge accounting treatment under SFAS 133. In such cases, the changes in the fair value of these transactions are recorded in earnings as a component of direct energy costs. We did not engage in trading activities in the wholesale energy market other than to manage our direct energy cost in an attempt to improve the profit margin associated with our customer requirements.

     The amounts recorded in OCI at January 31, 2005 related to cash flow hedges are summarized in the following table:

     On January 28, 2005, we sold back future electricity supply commitments related to serving certain customers in Pennsylvania to our energy supplier. As a result of the portfolio rebalancing required due to this sale, the portfolio coverage ratio is more meaningful at February 28, 2005, where we had 87% of our forecast energy load through

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December 31, 2005 covered through either fixed price power purchases with counterparties, or price protected through financial hedges.

Item 4. Controls and Procedures.

     a) Evaluation of Disclosure Controls and Procedures.

     Our Principal Executive Officer and Chief Financial Officer have concluded, based on their evaluation as of the end of the period covered by this report, that our disclosure controls and procedures (as defined in Rules 13(a)-15(e) under the Securities Act of 1934, as amended) are effective to ensure that all information required to be disclosed by the Company in the reports filed or submitted by it under the Securities and Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and include controls and procedures designed to ensure that information required to be disclosed by the Company in such reports is accumulated and communicated to the Company’s management, including the Principal Executive Officer and the Chief Financial Officer, as appropriate and allow timely decisions regarding required disclosure.

     b) Changes in Internal Controls.

     In connection with the above-referenced evaluation, no change in the Company’s internal control over financial reporting occurred during the period covered by this report that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II — OTHER INFORMATION

Item 1. Legal Proceedings.

     Reference is made to the Company’s Report on Form 10-K for the period ended July 31, 2004 (the “10-K”), for a summary the Company’s legal proceedings previously reported. Since the date of the 10-K, there have been no material developments in previously reported legal proceedings,except as set forth below.

     On January 21, 2005, the court granted the Company’s motion to dismiss in Coltrain, et al. v. Commonwealth Energy Corporation, et al. (Case number CV03-8560-FMC (RNBx)) for lack of prosecution.

     On December 23, 2004, the Company entered into a full and comprehensive Settlement Agreement and Mutual General Release (the “Settlement Agreement”) with stockholder and former director of Commonwealth Energy Corporation, Joseph P. Saline, and stockholder Joseph Ogundiji. The Settlement Agreement effectively ended all legal actions between the parties that began in 2001, including Orange Court Superior Court case numbers 01CC10657, 01CC13887, 04CC09285, 03CC03409, 04CC05038. The Settlement Agreement acknowledges and validates Mr. Saline’s shares of common stock in the Company and provides for a $1.2 million settlement payment to Mr. Saline. The Settlement Agreement also provides Mr. Ogundiji with a payment of $222,400 in settlement of all his claims and for canceling all of his shares of common stock. In addition, Mr. Saline and Mr. Ogundiji agreed that for the next two years they would submit any future disputes to mediation before commencing litigation or before they take any steps to contact the Company’s stockholders for any reason related to bringing a proxy contest.

     On February 18, 2005, the court struck the defendant’s answers and dismissed their counter-claim in Commonwealth Energy Corporation v. Wayne Mosley, et al. (Case number CV03-00402-NM (RNBx)) for failure to prosecute and failure to comply with orders of the court.

Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities.

Stock Repurchases

     The following table details our common stock repurchases for the three months ended January 31, 2005:

Issuer Purchases of Equity Securities

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Company entered into with stockholder and former director of Commonwealth Energy Corporation, Joseph P. Saline, and stockholder Joseph Ogundiji on December 23, 2004, the Company paid Mr. Ogundiji $222,400 in settlement of all his claims and for canceling all of his shares of common stock. For a further description of this settlement, see Part II, Item 1. Legal Proceedings.

Item 4. Submission of Matters to a Vote of Security Holders.

     The results of the voting at the Company’s annual meeting of stockholders held on January 12, 2005 were previously reported on a current report on Form 8-K filed with the Securities and Exchange Commission on January 19, 2005.

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Item 6. Exhibits.

     The exhibit listed below is hereby filed with the Securities and Exchange Commission as part of this Report.

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SIGNATURES

     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

COMMERCE ENERGY GROUP, INC.

Date: March 17, 2005	By:	/s/ Peter Weigand
		Peter Weigand
		President (Principal Executive Officer)
Date: March 17, 2005	By:	/s/ Richard L. Boughrum
		Richard L. Boughrum
		Senior Vice President, Chief Financial Officer (Principal Financial Officer)

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EXHIBIT INDEX

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