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  **UNITED STATES SECURITIES AND EXCHANGE COMMISSION****Washington, D.C. 20549****Form 10-Q/ A**(Amendment No. 3)       (Mark One)  þ     **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.***(Exact name of registrant as specified in its charter)*    **Delaware** **20-0501090***(State or other jurisdiction of* *(I.R.S. Employer**incorporation or organization)* *Identification No.)***600 Anton Boulevard, Suite 2000, Costa Mesa, California92626***(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, ifchanged since last report)*    Indicate by check mark whether the registrant (1) has filedall reports required to be filed by Section 13 or 15(d) ofthe Securities Exchange Act of 1934 during the preceding12 months (or for such shorter period that the registrantwas required to file such reports), and (2) has beensubject to such filing requirements for the past90 days.     Yesþ          Noo     Indicate by check mark whether the registrant is an acceleratedfiler (as defined in Rule 12b-2 of the ExchangeAct).     Yes o          Noþ     Indicate by check mark whether the registrant is a shell company(as defined in Rule 12b-2 of the ExchangeAct).     Yes o          No þ     As of March 11, 2005, 31,432,523 shares of theregistrant’s common stock were outstanding.  

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**EXPLANATORY NOTE**     This quarterly report on Form 10-Q/ A (AmendmentNo. 3) is being filed by the Company to amend theCompany’s quarterly report on Form 10-Q for thequarterly period ended January 31, 2005 filed with theSecurities and Exchange Commission on March 17, 2005, asinitially amended by Amendment No. 1 filed with theSecurities and Exchange Commission on June 14, 2005(“Amendment No. 1”), and as further amended byAmendment No. 2 filed with the Securities and ExchangeCommission on July 12, 2005 (“AmendmentNo. 2”).     We purchase substantially all of our electricity and natural gassupplies for retail customers utilizing forward physicaldelivery contracts. Additionally, we utilize financialderivatives, primarily swaps and futures, to minimize earningsfluctuations resulting from commodity price market volatility.These physical and financial contracts are classified asderivatives under Statement of Financial AccountingStandard No. 133, *Accounting for DerivativeInstruments and Hedging Activities,* or SFAS No. 133. Weaccount for the majority of our forward physical contractspursuant to the normal purchase and normal sale exemption underSFAS No. 133, whereby contracted energy costs arerecorded at the time of physical delivery. The Company accountedfor certain financial derivatives and its electricity forwardphysical delivery contracts entered into after January 28,2005 for its Pennsylvania market (PJM-ISO) as cash flow hedges,whereby any related mark to market gain or loss on thesecontracts was deferred and reported as a component of othercomprehensive income (loss) until the period of delivery.     In connection with the preparation of our consolidated financialstatements for the fiscal year ended July 31, 2005, wedetermined that (a) certain electricity forward physicalcontracts and financial derivatives designated as cash flowhedges lacked adequate documentation of our method ofmeasurement and testing of hedge effectiveness to meet the cashflow hedge requirement of SFAS No. 133 and (b) aforward physical contract and several derivative contracts hadbeen inappropriately accounted for as exempt from hedgeaccounting under SFAS No. 133.     Without adequate documentation, we were not eligible to applycash flow hedge accounting under SFAS No. 133 in fiscal2005. Additionally, the derivative contracts that had beeninappropriately accounted for as exempt from hedge accountingmust be marked to market. Mark to market gains or losses onthese derivatives are required to be reflected in the statementof operations for each period rather than deferred as acomponent of other comprehensive income (loss) until physicaldelivery.     We have restated our results for the first, second and thirdquarters of fiscal 2005 to mark to market these derivatives inthe statement of operations for each period. The impact of therestatement on the financial statements for the three and sixmonths ended January 31, 2005 is summarized as follows (inthousands, except per share data):                    **Three Months Ended** **Six Months Ended**  **January 31, 2005** **January 31, 2005**       **Reported** **Restated** **Reported** **Restated**         **Condensed Consolidated Statement of Operations Data:**                    Net revenue $61,048  $61,048  $119,545  $119,545     Direct energy costs  51,026   52,639   103,433   103,975                  Gross profit  10,022   8,409   16,112   15,570     Net loss  (729)  (2,342)  (1,848)  (2,390)    Net loss per common share:                     Basic and diluted  (0.02)  (0.08)  (0.06)  (0.08)

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           **January 31, 2005**     **Reported** **Restated**     **Condensed Consolidated Balance Sheet Data:**            Total assets $104,917  $104,917     Accrued liabilities  10,104   10,104     Retained earnings  11,718   11,176     Other comprehensive loss  (542)  —     Total stockholders’ equity  71,562   71,562      The only change to the Condensed Consolidated Statement of CashFlows was within cash flows from operating activities. Net cashprovided by (used in) operating, investing and financingactivities did not change.     This amended Quarterly Report on Form 10-Q/ A (AmendmentNo. 3) also amends our prior disclosure regarding ourevaluation of controls and procedures as of the end of theperiod covered by this report.     This amendment includes changes to Item 1, Item 2 andItem 4 of Part I and Item 6 of Part II.Except as identified in the prior sentence, no other itemincluded in the original Form 10-Q has been amended, andsuch items shall remain in effect as of the filing date of theoriginal Form 10-Q. Additionally, this Form 10-Q/ A(Amendment No. 3) does not purport to provide an update ordiscussion of any other developments at the Company subsequentto its original filing.

**COMMERCE ENERGY GROUP, INC.****FORM 10-Q/ A****(Amendment No. 3)****Restated For the Period Ended January 31, 2005****Index**           **Page**     ** PART I — FINANCIAL    INFORMATION**     Item 1.      Financial Statements:           Condensed Consolidated Statements of    Operations for the three and six months ended January 31,    2004 and 2005 (Restated)  2        Condensed Consolidated Balance Sheets as of    July 31, 2004 and January 31, 2005 (Restated)  3        Condensed Consolidated Statements of Cash    Flows for the three and six months ended January 31, 2004    and 2005 (Restated)  4        Restated Notes to Condensed Consolidated    Financial Statements  5      Item 2.      Restated Management’s Discussion and    Analysis of Financial Condition and Results of Operations  15      Item 3.      Quantitative and Qualitative Disclosures    About Market Risk  29      Item 4.      Restated Controls and Procedures  30 ** PART II — OTHER    INFORMATION**     Item 1.      Legal Proceedings  32      Item 2.      Changes in Securities, Use of Proceeds and    Issuer Purchases of Equity Securities  32      Item 4.      Submission of Matters to a Vote of Security    Holders  33      Item 6.      Exhibits  33      Signatures  35  EXHIBIT 31.1 EXHIBIT 31.2 EXHIBIT 32.1 EXHIBIT 32.2
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**FORWARD-LOOKING INFORMATION**     A number of the matters and subject areas discussed in thisQuarterly Report on Form 10-Q/A (Amendment No. 3)contain forward-looking statements reflecting management’scurrent expectations. The discussion of such matters and subjectareas is qualified by the inherent risks and uncertaintiessurrounding future expectations generally, and also may differmaterially from our actual future experience involving any oneor more of such matters and subject areas. We wish to cautionreaders that all statements other than statements of historicalfact included in this Quarterly Report on Form 10-Q/A(Amendment No. 3) regarding our financial position andstrategy may constitute forward-looking statements. When used inthis document, the words “anticipate,”“believe,” “estimate,” “expect,”“intend,” “may,” “project,”“plan,” “should,” and similar expressionsare intended to be among the statements that identifyforward-looking statements. All of these forward-lookingstatements are based upon estimates and assumptions made by ourmanagement, which although believed to be reasonable, areinherently uncertain. Therefore, undue reliance should not beplaced on such estimates and statements. No assurance can begiven that any of such estimates or statements will be realizedand it is likely that actual results will differ materially fromthose contemplated by such forward-looking statements. Factorsthat may cause such differences include those set forth in thisQuarterly Report on Form 10-Q/A (Amendment No. 3), aswell 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 thefactors that we currently believe may cause actual futureexperience and results to differ from our current expectationsregarding the relevant matter or subject area. In addition tothe items specifically discussed above, our business and resultsof operations are subject to the risks and uncertaintiesdescribed in this Report in Part I, Item 2.Management’s Discussion and Analysis of Financial Conditionand Results of Operations and in our Annual Report onForm 10-K for the year ended July 31, 2004 which wefiled with the Securities and Exchange Commission onNovember 15, 2004. In evaluating forward-lookingstatements, you should consider these risks and uncertainties,together with the other risks described from time to time in ourreports and documents filed with the Securities and ExchangeCommission, and you should not place undue reliance on thesestatements. These forward-looking statements speak only as ofthe date on which the statements were made. We assume noobligation to update the forward-looking information to reflectactual results or changes in the factors affecting suchforward-looking information.
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**PART I — FINANCIAL INFORMATION****Item 1.*****Financial Statements.*****COMMERCE ENERGY GROUP, INC.****CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS****(In thousands, except per share amounts)****(Unaudited)**                    **Three Months Ended** **Six Months Ended**  **January 31,** **January 31,**       **2004** **2005** **2004** **2005**             **(Restated)**   **(Restated)**    Net revenue $47,038  $61,048  $105,434  $119,545     Direct energy costs  43,783   52,639   97,858   103,975                  Gross profit  3,255   8,409   7,576   15,570     Selling and marketing expenses  1,008   761   1,978   1,715     General and administrative expenses  5,829   10,043   11,347   15,050     Reorganization and initial public listing expenses  1,028   —   1,146   —                  Loss from operations  (4,610)  (2,395)  (6,895)  (1,195)    Other income and expenses:                     Initial formation litigation expenses  —   (162)  (585)  (1,601)     Provision for impairment on investments  (4,313)  —   (4,313)  —      Minority interest share of loss  351   —   895   —      Interest income, net  151   215   281   406                  Total other income and expenses  (3,811)  53   (3,722)  (1,195)                 Loss before benefit from income taxes  (8,421)  (2,342)  (10,617)  (2,390)    Benefit from income taxes  768   —   1,842   —                  Net loss $(7,653) $(2,342) $(8,775) $(2,390)                 Loss per common share:                     Basic $(0.28) $(0.08) $(0.32) $(0.08)                  Diluted $(0.28) $(0.08) $(0.32) $(0.08)             The accompanying notes are an integral part of these condensedConsolidated Financial Statements.
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**COMMERCE ENERGY GROUP, INC.****CONDENSED CONSOLIDATED BALANCE SHEETS****(In thousands)**             **July 31,** **January 31,**  **2004** **2005**         **(Unaudited)**    **(Restated)****ASSETS**    Current assets:             Cash and cash equivalents $54,065  $49,983      Accounts receivable, net  31,119   32,272      Income taxes refund receivable  4,423   4,430      Deferred income tax asset  74   74      Prepaid expenses and other current assets  5,141   1,278              Total current assets  94,822   88,037     Restricted cash and cash equivalents  4,008   4,333     Deposits  5,445   6,699     Investments  96   91     Property and equipment, net  2,613   2,253     Goodwill and other intangible assets  3,839   3,504              Total assets $110,823  $104,917         **LIABILITIES AND STOCKHOLDERS’ EQUITY**    Current liabilities:             Accounts payable $30,576  $23,251      Accrued liabilities  6,141   10,104              Total current liabilities  36,717   33,355     Stockholders’ equity:             Common stock — 150,000 shares authorized with    $0.001 par value; 30,519 and 30,499 shares issued and    outstanding at July 31, 2004 and January 31, 2005,    respectively  60,796   60,594      Unearned restricted stock compensation  (256)  (208)     Retained earnings  13,566   11,176              Total stockholders’ equity  74,106   71,562              Total liabilities and stockholders’ equity $110,823  $104,917        The accompanying notes are an integral part of these condensedConsolidated Financial Statements.
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**COMMERCE ENERGY GROUP, INC.****CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS****(In thousands)****(Unaudited)**             **Six Months Ended**  **January 31,**     **2004** **2005**         **(Restated)****Cash Flows From Operating Activities**            Net loss $(8,775) $(2,390)    Adjustments to reconcile net income (loss) to net cash provided    by (used in) operating activities:             Depreciation  761   683      Amortization  127   336      Provision for doubtful accounts  1,125   1,318      Impairment of Summit investments  4,843   5      Stock-based compensation expense  —   48      Minority interest share of loss of consolidated entity  (282)  —      Changes in operating assets and liabilities:              Accounts receivable, net  13,249   (2,402)      Prepaid expenses and other assets  1,318   1,992       Accounts payable  (6,685)  (7,325)      Accrued liabilities and other  (258)  4,505            Net cash provided by (used in) operating activities  5,423   (3,230)**Cash Flows From Investing Activities**            Purchase of property and equipment  (571)  (325)           Net cash used in investing activities  (571)  (325)**Cash Flows From Financing Activities**            Proceeds from exercise of stock  1   50     Cancellation of common stock  —   (252)    Decrease (increase) in restricted cash and cash equivalents  8,602   (325)           Net cash provided by (used in) financing activities  8,603   (527)           Increase (decrease) in cash and cash equivalents  13,455   (4,082)    Cash and cash equivalents at beginning of period  40,921   54,065            Cash and cash equivalents at end of period $54,376  $49,983        The accompanying notes are an integral part of these condensedConsolidated Financial Statements.
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**COMMERCE ENERGY GROUP, INC.****NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS****(In thousands, except per share and per kWh amounts)****1.****Summary of Significant Accounting Policies*****Basis of Presentation***     The condensed Consolidated Financial Statements for the threeand six months ended January 31, 2005 include the accountsof Commerce Energy Group, Inc. (the “Company”), itsthree wholly-owned subsidiaries: Commonwealth Energy Corporationdoing business under the brand name *electricAmerica*,Skipping Stone Inc. (“Skipping Stone”), which wasacquired on April 1, 2004, and UtiliHost, Inc. All materialinter-company balances and transactions have been eliminated inconsolidation.     At January 31, 2004, the Company’s ConsolidatedFinancial Statements included the accounts of its controlledinvestment in Summit Energy Ventures, LLC (“Summit”),and its majority ownership in Power Efficiency Corporation(“PEC”). In the fourth quarter of fiscal 2004, theCompany terminated its relationship with Summit and itsinvestment in PEC decreased to 39.9% and subsequently, to 36.4%at January 31, 2005. As of July 31, 2004 and as ofJanuary 31, 2005, both entities were no longerconsolidated. (See Note 4).***Preparation of Interim Condensed Consolidated Financial    Statements***     These interim condensed Consolidated Financial Statements havebeen prepared by the Company’s management, without audit,in accordance with accounting principles generally accepted inthe United States. In the opinion of management, these financialstatements contain all adjustments (consisting of only normalrecurring adjustments) necessary to present fairly theCompany’s consolidated financial position, results ofoperations and cash flows for the periods presented. Certaininformation and note disclosures normally included inconsolidated annual financial statements prepared in accordancewith accounting principles generally accepted in the UnitedStates have been condensed or omitted in these consolidatedinterim financial statements, although the Company believes thatthe disclosures are adequate to make the information presentednot misleading. The condensed consolidated results ofoperations, financial position, and cash flows for the interimperiods presented herein are not necessarily indicative offuture financial results. These interim condensed ConsolidatedFinancial Statements should be read in conjunction with theannual Consolidated Financial Statements and the notes theretoincluded in the Company’s most recent Annual Report onForm 10-K for the year ended July 31, 2004.***Uses of Estimates***     The preparation of condensed Consolidated Financial Statementsin conformity with accounting principles generally accepted inthe United States requires management to make certain estimatesand assumptions that affect the reported amounts and timing ofrevenue and expenses, the reported amounts and classification ofassets and liabilities, and disclosure of contingent assets andliabilities. These estimates and assumptions are based on theCompany’s historical experience as well asmanagement’s future expectations. As a result, actualresults could differ from management’s estimates andassumptions. The Company’s management believes that itsmost critical estimates herein relate to independent systemoperator costs, allowance for doubtful accounts, unbilledreceivables and loss contingencies.***Reclassifications***     Certain amounts in the condensed Consolidated FinancialStatements for the comparative prior fiscal period have beenreclassified to be consistent with the current fiscalperiod’s presentation.
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**COMMERCE ENERGY GROUP, INC.****NOTES TO CONDENSED CONSOLIDATED FINANCIALSTATEMENTS — (Continued)****(In thousands, except per share and per kWh amounts)*****Revenue Recognition***     Energy sales are recognized as the electric power is deliveredto customers. The Company’s net revenue is comprised of thefollowing:                    **Three Months Ended** **Six Months Ended**  **January 31,** **January 31,**       **2004** **2005** **2004** **2005**             Retail energy sales $46,034  $44,807  $102,181  $97,499     Excess energy sales  1,004   16,241   3,253   22,046                   Net revenue $47,038  $61,048  $105,434  $119,545                   Skipping Stone revenue (which is included in retail energy salesabove), after elimination of inter-company transactions, for thethree and six months ended January 31, 2005 was $595 and$1,195, respectively, representing approximately 1% of total netrevenue for both periods.***Stock-Based Compensation***     The Company accounts for its employee stock options under therecognition and measurement principles of Accounting PrinciplesBoard Opinion No. 25, *Accounting for Stock Issued toEmployees*(“APB No. 25”), and relatedinterpretations. Under APB No. 25, no stock-based employeecompensation costs are reflected in net income (loss) for thethree and six month periods ended January 31, 2005 and2004, because all options granted under the plans had anexercise price equal to or greater than the market value of theunderlying 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 fairvalue recognition provisions of Statement of FinancialAccounting Standards (“SFAS”) No. 123:                    **Three Months Ended** **Six Months Ended**  **January 31,** **January 31,**       **2004** **2005** **2004** **2005**             **(Restated)**   **(Restated)**    Net income (loss) as applicable to common stock —    basic and diluted $(7,679) $(2,342) $(8,827) $(2,390)    Deduct: Total stock-based compensation expense determined under    fair value based method for all awards, net of related tax    effects  (9)  (7)  (92)  (10)                 Pro forma net loss — basic and diluted $(7,688) $(2,349) $(8,919) $(2,400)                 Net loss per share:                     Basic — as reported $(0.28) $(0.08) $(0.32) $(0.08)                  Basic — pro forma $(0.28) $(0.08) $(0.32) $(0.08)                  Diluted — as reported $(0.28) $(0.08) $(0.32) $(0.08)                  Diluted — pro forma $(0.28) $(0.08) $(0.32) $(0.08)             
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**COMMERCE ENERGY GROUP, INC.****NOTES TO CONDENSED CONSOLIDATED FINANCIALSTATEMENTS — (Continued)****(In thousands, except per share and per kWh amounts)*****Employee Stock Purchase Plan***     On January 12, 2005, the stockholders of the Companyapproved the 2005 Employee Stock Purchase Plan (the“ESPP”). The ESPP will allow eligible employees,officers, directors and consultants of the Company and itsdesignated affiliates to purchase, through payroll deductions,shares of the Company’s common stock. As ofJanuary 31, 2005, the ESPP had not been implemented.***Segment Reporting***     The Company’s chief operating decision makers consist ofmembers of senior management that work together to allocateresources to, and assess the performance of, the Company’sbusiness. These members of senior management currently managethe Company’s business, assess its performance, andallocate its resources as a single operating segment. Becausethe 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 inter-companytransactions), and geographic information is not relevant, nosegment information is provided.***Recent Accounting Standards***     In December 2004, the Financial Accounting Standards Boardissued SFAS No. 123 (Revised 2004), Share-BasedPayment, (“SFAS No. 123R”), which is arevision to SFAS No. 123 and supersedes APBNo. 25 and SFAS No. 148, Accounting forStock-Based Compensation — Transition and Disclosure.This statement requires that the cost resulting from allshare-based payment transactions be recognized in the financialstatements. This statement establishes fair value as themeasurement objective in accounting for share-based paymentarrangements and requires all entities to apply a fair-valuebased measurement method in accounting for share-based paymenttransactions with employees except for equity instruments heldby employee share ownership plans. SFAS No. 123Rapplies to all awards granted after the required effective date(the beginning of the first interim or annual reporting periodthat begins after June 15, 2005) and to awards modified,repurchased, or cancelled after that date. As of the requiredeffective date, all public entities that used the fair-valuebased method for either recognition or disclosure underSFAS No. 123 will apply this statement using amodified version of prospective application. Under thattransition method, compensation costs is recognized on or afterthe required effective date for the portion of outstandingawards for which the requisite service has not yet beenrendered, based on the grant-date fair value of those awardscalculated under SFAS No. 123 for either recognitionor pro forma disclosures. For periods before the requiredeffective date, those entities may elect to apply a modifiedversion of the retrospective application under which financialstatements for prior periods are adjusted on a basis consistentwith the pro forma disclosures required for those periods bySFAS No. 123. As a result, beginning in the firstquarter of fiscal 2006, the Company will adoptSFAS No. 123R and begin reflecting the stock optionexpense determined under fair-value based methods in itsstatement of operations rather than as pro forma disclosure inthe notes to the financial statements. The Company has not yetdetermined whether the adoption of SFAS No. 123R willresult in amounts that are similar to the current pro formadisclosures under SFAS No. 123 and it is evaluatingthe requirements under SFAS No. 123R.**2.****Basic and Diluted Income (Loss) per Common Share**     Basic income (loss) per common share was computed by dividingnet income (loss) available to common stockholders, after anypreferred stock dividends, by the weighted average number ofcommon shares outstanding during the period. Diluted income(loss) per common share reflects the potential dilution thatwould occur if all outstanding options or other contracts toissue common stock were exercised or converted and was computedby dividing net income (loss) by the weighted average number ofcommon shares plus dilutive common equivalent sharesoutstanding, unless they were anti-dilutive.
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**COMMERCE ENERGY GROUP, INC.****NOTES TO CONDENSED CONSOLIDATED FINANCIALSTATEMENTS — (Continued)****(In thousands, except per share and per kWh amounts)**     The following is a reconciliation of the numerator (income orloss) and the denominator (common shares in thousands) used inthe computation of basic and diluted income (loss) per commonshare:                   **Three Months Ended** **Six Months Ended**  **January 31,** **January 31,**       **2004** **2005** **2004** **2005**             **(Restated)**   **(Restated)****Numerator:**                    Netloss $(7,653) $(2,342) $(8,775) $(2,390)    Deduct: Preferred stock dividends  (26)  —   (52)  —                  Net loss applicable to common stock — basic and diluted $(7,679) $(2,342) $(8,827) $(2,390)                                **Three Months Ended** **Six Months Ended**  **January 31,** **January 31,**       **2004** **2005** **2004** **2005**             **(Restated)**   **(Restated)****Denominator:**                    Weighted-average outstanding common shares — basic  27,645   30,534   27,645   30,528     Effect of stock options  —   —   —   —                  Weighted-average outstanding common shares — diluted  27,645   30,534   27,645   30,528                   For the three and six months ended January 31, 2004, theeffects of the assumed exercise of all stock options and theassumed conversion of preferred stock into common stock areanti-dilutive; accordingly, such assumed exercises andconversions have been excluded from the calculation of netloss — diluted. If the assumed exercises orconversions had been used, the fully diluted shares outstandingfor the three and six months ended January 31, 2005 wouldhave been 30,881 and 30,888, respectively. If the assumedexercises or conversions had been used, the fully diluted sharesoutstanding 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 codifiedthe restructuring of the California electric industry andprovided for the right of direct access (“DA”). DAallowed electricity customers to buy their power from a supplierother than the electric distribution utilities beginningJanuary 1, 1998. On April 1, 1998, the Company begansupplying customers in California with electricity as anElectric Service Provider (“ESP”).     The California Public Utility Commission (“CPUC”)issued a ruling on September 20, 2001 suspending directaccess. The suspension permitted the Company to keep currentcustomers and to solicit DA customers served by other providers,but prohibited the Company from soliciting new non-DA customersfor 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 energycrisis. This amount is currently being collected by SCE as a$0.01 per kilowatt-hour (“kWh”) surcharge on theretail electricity bill paid by
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**COMMERCE ENERGY GROUP, INC.****NOTES TO CONDENSED CONSOLIDATED FINANCIALSTATEMENTS — (Continued)****(In thousands, except per share and per kWh amounts)**the Company’s customers. SCE estimates that full paymentcould be achieved as soon as early 2006. While the HPC does notdirectly impact the Company’s rate design or revenue, itmay affect the Company’s ability to retain existingcustomers or compete for new customers.     Effective January 1, 2003, the CPUC authorized the electricdistribution utilities to charge certain DA customers asurcharge to cover state power contract costs. The Direct AccessCost Responsibility Surcharge (the “DA CRS”) iscurrently fixed at $0.027 per kWh. The DA CRS is onlyassessed to those DA customers who enrolled in DA on or afterFebruary 1, 2001. In the SCE service territory, the $0.027DA CRS includes the $0.01 HPC. Those customers who were enrolledin DA prior to February 1, 2001, and are in the SCE serviceterritory continue to pay only the $0.01 HPC. While this chargedoes not directly impact the Company’s rate design orrevenue, it may affect the Company’s ability to retainexisting customers or compete for new customers.     In December 2003, Pacific Gas and Electric(“PG&E”) and the CPUC reached a settlement in thePG&E bankruptcy. In February 2004, the CPUC approved a ratesettlement agreement, which reduced overall customer rates inthe PG&E service territory. DA bills have generally declinedin the PG&E service territory and the lower rates haveaffected the Company’s revenue and profitability.     Currently, four important issues are under review at the CPUC, aResource Adequacy Requirement, a Renewable Portfolio Standard,Utilities Long Term Procurement Plans and the General Rate Casesof the electric distribution utilities. Additional costs toserve customers in California are anticipated from theseproceedings; however, the CPUC decisions will determine thedistribution of those costs across all load serving entities andultimately the financial impact on the Company.***Pennsylvania***     In 1996, the Electricity Generation Customer Choice andCompetition Act was passed. This law allowed electric customersto choose among competitive power suppliers beginning with onethird of the State’s consumers by January 1999, two thirdsby January 2000, and all consumers by January 2001. The Companybegan serving customers in the Pennsylvania territory in 1999.There are no current rate cases or filings regarding thisterritory that are anticipated to impact the Company’sfinancial results.***Michigan***     The Michigan state legislature passed two acts, the CustomerChoice Act and Electricity Reliability Act, signed into law onJune 3, 2000. Open access, or Choice, became available toall customers of Michigan electric distribution utilities,beginning January 1, 2002. The Company began marketing inMichigan’s Detroit Edison (“DTE”) serviceterritory in September 2002.     In February 2004, the Michigan Public Service Commission(“MPSC”) issued an interim order granting partial butimmediate rate relief to DTE, the Company’s primaryelectric distribution utility market in Michigan. The ordersignificantly reduced the savings of commercial customers whochoose an alternative electric supplier, such as the Company.These changes have adversely affected the Company’s abilityto retain some of the Company’s existing customers andobtain new customers, primarily among larger commercialcustomers.     In November 2004, the MPSC issued the final order in the DTEGeneral Rate case making slight changes in the rates originallyapproved in the interim order issued in February 2004. The finalorder reinstated a small percentage of savings of largecommercial customers who choose an alternative electricsupplier, while generally maintaining the charges for smallercommercial customers. More notable changes were made to rulesregarding moving between the local utility and alternativesuppliers. New customers electing service from alternativeproviders must remain outside utility service for a minimum oftwo years.
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**COMMERCE ENERGY GROUP, INC.****NOTES TO CONDENSED CONSOLIDATED FINANCIALSTATEMENTS — (Continued)****(In thousands, except per share and per kWh amounts)**Additionally, the local utility now requires substantial noticeprior to returning to their service. Overall rate and rulechanges are not expected to have a significant impact to theCompany’s ability to retain its existing customers andobtain new customers.     The Michigan Senate has energy restructuring language before itin various bills, supported by the electric distributionutilities, which could negatively impact competition in theMichigan electric market.***New Jersey***     Deregulation activities began in New Jersey in November 1999when the Board of Public Utilities, or BPU, approved theimplementation plan. The Company began marketing in New Jerseyin the Public Service Electric and Gas service territory inDecember 2003.     The Basic Generation Service is the comparable utility price forsmall and large commercial accounts and includes areconciliation charge which can change on a monthly basis.Reconciliation charge fluctuations can affect the Company’sability to remain competitive against the comparable utilitypricing.**4.****Investments**     The Company has three investments in early-stage, energy relatedentities incurring operating losses, which are expected tocontinue, at least in the near term: Encorp, Inc.(“Encorp”), Turbocor B.V. (“Turbocor”) andPower Efficiency Corporation (“PEC”). Each company hasvery limited working capital and as a result, continuingoperations will be dependent upon their securing additionalfinancing to meet their respective immediate capital needs. TheCompany has no obligation, and currently no intention to investadditional funds into these companies.     At January 31, 2005, the Company’s ownership interestin Encorp, Turbocor and PEC was 1.9%, 6.5% and 36.4%,respectively. The Company accounts for its investment in Encorpand Turbocor under the cost method of accounting. The Companycurrently 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 financialstatements. In fiscal 2004, these investments were written downto $96. In fiscal 2005, these investments are carried at $91 andhave no material impact on our financial statements.**5.****Commitments and Contingencies*****Commitments****Purchase Commitments*     On January 28, 2005, the Company made a strategic decisionto discontinue service to certain customers in the Pennsylvaniaservice territory, specifically certain residential and smallcommercial customers. In connection with that decision, theCompany sold back future electricity supply commitments relatedto serving those customers to its energy supplier. The supplycommitments would have provided the Company with electricity toserve the discontinued customers’ electricity requirementsthrough May 2006. The transaction occurred in January 2005 andresulted in a gain on the sale of the supply commitments of$9,301, which has been reflected in the Company’s financialstatements for its second fiscal quarter ending January 31,2005. This gain was partially offset by $1,500 of additionalcosts, to cover the timing and forecasting issues related torealigning the customer portfolio, incurred in the third fiscalquarter of 2005 and $600 of a reserve for additional estimatedenergy costs in the fourth fiscal quarter of 2005. (SeeNote 8). The Company will continue to serve remainingcustomers in the Pennsylvania territory from remaining supplycontracts with other wholesale suppliers. After giving effect tothe supply commitment that was sold in the
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**COMMERCE ENERGY GROUP, INC.****NOTES TO CONDENSED CONSOLIDATED FINANCIALSTATEMENTS — (Continued)****(In thousands, except per share and per kWh amounts)**Pennsylvania territory and any new supply commitments enteredinto in the second fiscal quarter, the following is a summary ofthe Company’s commitments to purchase electric power as ofJanuary 31, 2005:                **Fiscal Years Ending**     **2005** **2006** **Total**           California $24,494  $18,586  $43,080     Pennsylvania and New Jersey  6,898   5,079   11,977                Total $31,392  $23,665  $55,057           ***Contingencies****Employment Settlements*     As of January 31, 2005, the Company has recorded a $3,600reserve for potential employment related settlements.***Litigation***     On November 25, 2003, several stockholders filed a lawsuitagainst the Company entitled Coltrain, et al. v.Commonwealth Energy Corporation, et al. The complaintpurported to be a class action against the Company forviolations of section 709 of the California CorporationsCode. This action was dismissed for lack of prosecution onJanuary 21, 2005.     On December 23, 2004, the Company entered into a full andcomprehensive Settlement Agreement and Mutual General Release(“Settlement Agreement”) with stockholder and formerdirector of Commonwealth Energy Corporation, Joseph P. Saline,and stockholder Joseph Ogundiji. The Settlement Agreementeffectively ended all legal actions between the parties thatbegan in 2001. The Settlement Agreement acknowledges andvalidates Mr. Saline’s shares of common stock in theCompany and provides for a $1,200 settlement payment toMr. Saline. The Settlement Agreement also providesMr. Ogundiji with a payment of $222 in settlement of all ofhis claims and for canceling all of his shares of common stock.In addition, Mr. Saline and Mr. Ogundiji agreed thatfor the next two years they would submit any future disputes tomediation before commencing litigation or before they take anysteps to contact the Company’s stockholders for any reason.The Company accrued $1,200 in October of 2004 for the settlementwith Mr. Saline and the $222 settlement forMr. Ogundiji was recorded as cancellation of stock with noincome statement effect.     On February 18, 2005, the court struck the defendant’sanswers and dismissed their counter-claim in Commonwealth EnergyCorporation v. Wayne Mosley, et al. for failure toprosecute 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 ofthe Company’s operations in the normal course of business.While the Company cannot predict the ultimate outcome of itspending matters or how they will affect the Company’sresults of operations or financial position, the Company’smanagement currently does not expect any of the legalproceedings to which the Company is currently a party, includingthe legal proceedings described above, individually or in theaggregate, to have a material adverse effect on its results ofoperations or financial position beyond the accruals provided asof January 31, 2005.**6.****Derivative Financial Instruments**     The Company’s activities expose it to a variety of marketrisks, including commodity prices and interest rates. Managementhas established risk management policies and procedures designedto reduce the
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**COMMERCE ENERGY GROUP, INC.****NOTES TO CONDENSED CONSOLIDATED FINANCIALSTATEMENTS — (Continued)****(In thousands, except per share and per kWh amounts)**potentially adverse effects that the price volatility of thesemarkets may have on its operating results. The Company’srisk management activities, including the use of derivativeinstruments, are subject to the management, direction andcontrol of an internal risk oversight committee. The Companymaintains commodity price risk management strategies that usederivative instruments within strict risk tolerances to minimizesignificant, unanticipated earnings fluctuations caused bycommodity price volatility. Changes in fair market value arerecognized currently in earnings unless specific hedgeaccounting criteria are met.     Supplying electricity to retail customers requires the Companyto match customers’ projected demand with fixed pricepurchases. The Company primarily uses forward physical deliverycontracts and financial derivative instruments to minimizesignificant, unanticipated earnings fluctuations caused bycommodity price volatility. In certain markets where the Companyoperates, entering into forward physical delivery contracts maybe expensive relative to derivative alternatives. Financialderivative instruments, primarily swaps and futures, are used tohedge the future purchase price of electricity for theapplicable forecast usage protecting the Company fromsignificant price volatility. The Company did not engage intrading activities in the wholesale energy market other than tomanage its direct energy cost.**7.****Subsequent Event**     On February 9, 2005, the Company and its wholly-ownedsubsidiary, Commonwealth Energy Corporation, entered into anagreement with American Communications Network, Inc.(“ACN”), and several of its subsidiaries, ACN UtilityServices, Inc., ACN Energy, Inc. and ACN Power, Inc.(collectively the “Sellers”) to purchase certainassets of the Sellers, retail electric power and natural gassales business, and assume specified liabilities. The Sellerssell retail electric power in Texas and Pennsylvania and sellretail natural gas in California, Ohio, Georgia, New York,Pennsylvania and Maryland. The assets acquired includeequipment, gas inventory associated with utility and pipelinestorage and transportation agreements and electricity supply,scheduling and capacity contracts, software and otherinfrastructure plus approximately 80 residential and smallcommercial customers. The initial consideration paid by theCompany 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 theCompany’s common stock as of February 8, 2005, thedate immediately prior to the closing date. The shares of theCompany’s common stock will initially be placed in escrowand released upon satisfaction of certain performance targetsrelated to customer growth. ACN was also paid at closing anestimated prepayment amount of approximately $5,500 as paymentfor certain working capital and prepayment items relating to theassets being acquired, and are subject to final adjustment andsettlement. The Company has sufficient cash to cover the needsof this acquisition.**8.****Restated Quarterly Financial Information (Unaudited)*****Restatement — Gain on Sale of Electricity Supply    Contracts***     In January 2005, the Company announced a strategic realignmentof its customer portfolio in the Pennsylvania electricity marketand the discontinuation of service to certain classes ofresidential and small commercial customers. In connection withthis decision, the Company sold electricity commodity supplycontracts, which were deemed excess based on the realignmentplan, back to the original supplier and recorded a gain on thesale of the contracts of $9,301 in the second quarter of fiscal2005. As a result of timing and forecasting issues related torealigning the portfolio, the Company had unforeseentransitional supply obligations which could have been servedmore cost effectively with the original supply contracts ratherthan with the market cost of the replacement power which wassubsequently purchased. As a result, the Company is restatingthe second quarter gain from $9,301 to $7,201, to account forthe higher replacement cost of power
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**COMMERCE ENERGY GROUP, INC.****NOTES TO CONDENSED CONSOLIDATED FINANCIALSTATEMENTS — (Continued)****(In thousands, except per share and per kWh amounts)**incurred in the third quarter of fiscal 2005 and estimated inthe fourth quarter of fiscal 2005 compared to the cost thatwould have been incurred under the original supply contracts, asreflected below.                   **Three Months Ended** **Six Months Ended**  **January 31, 2005** **January 31, 2005**       **Reported** **Restated** **Reported** **Restated**             Net revenue $61,048  $61,048  $119,545  $119,545     Direct energy costs  48,926   51,026   101,333   103,433                  Gross profit  12,122   10,022   18,212   16,112     Earnings (loss) from operations $1,318  $(782) $1,447  $(653)    Net income (loss) $1,371  $(729) $252  $(1,848)    Earnings (loss) per share — basic $0.04  $(0.02) $0.01  $(0.06)                 Earnings (loss) per share — diluted $0.04  $(0.02) $0.01  $(0.06)             ***     Restatement —Accounting for Derivatives***     In connection with the preparation of the Company’sconsolidated financial statements for the fiscal year endedJuly 31, 2005, the Company determined that certain forwardphysical delivery contracts and financial derivatives previouslydesignated as cash flow hedges lacked adequate documentation ofthe method of measurement and testing of hedge effectiveness tomeet the cash flow hedge requirements of SFAS No. 133,“Accounting for Derivative Instruments and HedgingActivities”. Additionally, the Company determined that aforward physical delivery contract and several financialderivative contracts had been inappropriately accounted for asexempt from hedge accounting under SFAS No. 133.     The Company restated its results for the first, second and thirdquarters of fiscal 2005 to eliminate cash flow hedge accountingand to recognize the mark to market gains or losses on thesederivatives in the statement of operations for each period. Theimpact of the restatement is summarized as follows:                   **Three Months Ended** **Six Months Ended**  **January 31, 2005** **January 31, 2005**       **Reported** **Restated** **Reported** **Restated**         **Condensed Consolidated Statement of Operations Data:**                    Net revenue $61,048  $61,048  $119,545  $119,545     Direct energy costs  51,026   52,639   103,433   103,975                  Gross profit  10,022   8,409   16,112   15,570     Loss from operations $(782) $(2,395) $(653) $(1,195)    Net loss $(729) $(2,342) $(1,848) $(2,390)    Net loss per common share — basic and diluted $(0.02) $(0.08) $(0.06) $(0.08)             
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**COMMERCE ENERGY GROUP, INC.****NOTES TO CONDENSED CONSOLIDATED FINANCIALSTATEMENTS — (Continued)****(In thousands, except per share and per kWh amounts)**           **January 31, 2005**     **Reported** **Restated**     **Condensed Consolidated Balance Sheet Data:**            Total assets $104,917  $104,917     Accrued liabilities  10,104   10,104     Retained earnings  11,718   11,176     Other comprehensive loss  (542)  —     Total stockholders’ equity  71,562   71,562      The only change to the Condensed Consolidated Statement of CashFlows was within cash flows from operating activities. Net cashprovided by (used in) operating, investing and financingactivities did not change.
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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 provideelectric power to our residential, commercial, industrial andinstitutional customers in the California, Pennsylvania,Michigan and New Jersey electricity markets. We are licensed bythe Federal Energy Regulatory Commission, or FERC, as a powermarketer. In addition to the state agencies in which wecurrently operate, we are also licensed to supply retailelectric power by applicable state agencies in New York,Maryland, Texas, Ohio and Virginia. Unless otherwise noted, asused herein, “the Company,” “we,”“us,” and “our” mean Commerce Energy Group,Inc. and its three wholly-owned subsidiaries: CommonwealthEnergy 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 toapproximately 94,000 customers in California, Pennsylvania,Michigan and New Jersey. The growth of this business dependsupon the degree of deregulation in each state, the availabilityof energy at competitive prices, credit terms, and our abilityto acquire retail or commercial customers.     Our core business is the retail sale of electricity to end-usecustomers. All of the power we sell to our customers ispurchased from third-party power generators under long-termcontracts and in the spot market. We do not own electricitygeneration facilities, with the exception of small experimentalrenewal energy assets. The electric power we sell is generallymetered and delivered to our customers by local incumbentelectric distribution utilities, or local utilities. The localutilities also provide billing and collection services for mostof our customers on our behalf. To facilitate load shaping andbalancing for our retail customer portfolio, we also buy andsell surplus electric power from and to other marketparticipants when necessary.     We buy electricity in the wholesale market in blocks oftime-related quantities usually at fixed prices. We sellelectricity in the real time market based on the demand from ourcustomers at contracted prices. We manage the inherent mismatchbetween our block purchases and our sales by buying and sellingin the spot market. In addition, the independent systemoperators (“ISO”), the entities which manage each ofthe electric grids in which we operate, perform real time loadbalancing. We are charged or credited for electricity purchasedand sold for our account by the ISO.     There are inherent risks and uncertainties in our core businessoperations. These include: regulatory uncertainty, timingdifferences between our purchases and sales of electricity,forecasting error between our estimated customer usage and thecustomer’s actual usage, weather related changes inquantities demanded by our customers, customer attrition, spreadchanges between on-peak and off-peak power pricing and seasonaldifferences between summer and winter demand, and spring andfall demand seasons, unexpected factors in the wholesale powermarkets such as regional power plant outages, volatile fuelprices (used to generate the electricity that we buy),transmission congestion or system failure, and credit relatedcounter-party risk for us or within the grid system generally.Accordingly, these uncertainties may produce results that maydiffer from our internal forecasts. For a discussion of otherrisks related to the operation of our business, see thediscussion herein under the caption “Factors That MayAffect Future Results.”     Skipping Stone, which we acquired in April 2004, providesenergy-related consulting and technologies to utilities,electricity generators, natural gas pipelines, wholesale energymerchants, energy technology providers and investment banks.Skipping Stone’s revenue (after elimination ofinter-company transactions) was approximately 1% of ourconsolidated net revenue for the three and six months endedJanuary 31, 2005.     In fiscal 2004, we consolidated Summit Energy Ventures, orSummit, and its majority interest in Power EfficiencyCorporation, or PEC, into our financial results. In the thirdfiscal quarter of 2004, we terminated our relationship withSummit. We no longer consolidate Summit and PEC in our currentfiscal year financial results as we retained a 39.9% interest inPEC. At January 31, 2005, our ownership interest wasdiluted to 36.4% as a result of an equity linked financing byPEC. Although we currently account for our investment in PECunder the equity method of accounting, in fiscal 2004, werecorded a loss sufficient to reduce our investment basis in PECto zero and, therefore, it will have no negative impact on ourfinancial results in fiscal 2005 or in the future.
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     The information in this Item 2, should be read inconjunction with the audited Consolidated Financial Statementsand notes thereto and Management’s Discussion and Analysisof Financial Condition and Results of Operations contained inthe Company’s Annual Report on Form 10-K for the yearended July 31, 2004, and the unaudited condensedConsolidated Financial Statements and notes thereto included inthis Quarterly Report.**Market and Regulatory*****California***     The 1996 California Assembly Bill, or AB, 1890 codified therestructuring of the California electric industry and providedfor the right of direct access, or DA. DA allowed electricitycustomers to buy their power from a supplier other than theelectric distribution utilities beginning January 1, 1998.On April 1, 1998, we began supplying customers inCalifornia with electricity as an Electric Service Provider, orESP.     The California Public Utility Commission, or CPUC, issued aruling on September 20, 2001 suspending direct access. Thesuspension permitted us to keep current customers and to solicitDA customers served by other providers, but prohibited us fromsoliciting new non-DA customers for an indefinite period of time.     In July 2002, the CPUC authorized Southern California Edison, orSCE, to implement a Historical Procurement Charge, or HPC, torepay debt incurred during the energy crisis. This amount iscurrently being collected by SCE as a $0.01 perkilowatt-hour, or kWh, surcharge on the retail electricity billpaid by our customers. SCE estimates that full payment could beachieved as soon as early 2006. While the HPC does not directlyimpact our rate design or revenue, it may affect our ability toretain existing customers or compete for new customers.     Effective January 1, 2003, the CPUC authorized the electricdistribution utilities to charge certain DA customers asurcharge to cover state power contract costs. The Direct AccessCost Responsibility Surcharge, or the DA CRS, is currently fixedat $0.027 per kWh. The DA CRS is only assessed to those DAcustomers 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 toFebruary 1, 2001, and are in the SCE service territorycontinue to pay only the $0.01 HPC. While this charge does notdirectly impact our rate design or revenue, it may affect ourability to retain existing customers or compete for newcustomers.     In December 2003, Pacific Gas and Electric, or PG&E, and theCPUC reached a settlement in the PG&E bankruptcy. InFebruary 2004, the CPUC approved a rate settlement agreement,which reduced overall customer rates in the PG&E serviceterritory. DA bills have generally declined in the PG&Eservice territory and the lower rates have affected our revenueand profitability.     Currently, four important issues are under review at the CPUC, aResource Adequacy Requirement, a Renewable Portfolio Standard,Utilities Long Term Procurement Plans and the General Rate Casesof the electric distribution utilities. Additional costs toserve customers in California are anticipated from theseproceedings; however, the CPUC decisions will determine thedistribution of those costs across all load serving entities andultimately the financial impact on us.***Pennsylvania***     In 1996, the Electricity Generation Customer Choice andCompetition Act was passed. This law allowed electric customersto choose among competitive power suppliers beginning with onethird of the State’s consumers by January 1999, two thirdsby January 2000, and all consumers by January 2001. We beganserving customers in the Pennsylvania territory in 1999. Thereare no current rate cases or filings regarding this territorythat are anticipated to impact our financial results.***Michigan***     The Michigan state legislature passed two acts, the CustomerChoice Act and Electricity Reliability Act, signed into law onJune 3, 2000. Open access, or Choice, became available toall customers of Michigan
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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, orMPSC, issued an interim order granting partial but immediaterate relief to DTE, our primary electric distribution utilitymarket in Michigan. The order significantly reduced the savingsof commercial customers who choose an alternative electricsupplier, such as us. These changes have adversely affected ourability to retain some of our existing customers and obtain newcustomers, primarily among larger commercial customers.     In November 2004, the MPSC issued the final order in the DTEGeneral Rate case making slight changes in the rates originallyapproved in the interim order issued in February 2004. The finalorder reinstated a small percentage of savings of largecommercial customers who choose an alternative electricsupplier, while generally maintaining the charges for smallercommercial customers. More notable changes were made to rulesregarding moving between the local utility and alternativesuppliers. New customers electing service from alternativeproviders must remain outside utility service for a minimum oftwo years. Additionally, the local utility now requiressubstantial notice prior to returning to their service. Overallrate and rule changes are not expected to have a significantimpact to our ability to retain our existing customers andobtain new customers.     The Michigan Senate has energy restructuring language before itin various bills, supported by the electric distributionutilities, which could negatively impact competition in theMichigan electric market.***New Jersey***     Deregulation activities began in New Jersey in November 1999when the Board of Public Utilities approved the implementationplan. We began marketing in New Jersey in the Public ServiceElectric and Gas service territory in December 2003.     The Basic Generation Service is the comparable utility price forsmall and large commercial accounts and includes areconciliation charge which can change on a monthly basis.Reconciliation charge fluctuations can affect our ability toremain competitive against the comparable utility pricing.**Critical Accounting Policies and Estimates**     The following discussion and analysis of our financial conditionand operating results are based on our Consolidated FinancialStatements. The preparation of this Form 10-Q requires usto make estimates and assumptions that affect the reportedamount of assets and liabilities, disclosure of contingentassets and liabilities at the date of our financial statements,and the reported amount of revenue and expenses during thereporting period. Actual results may differ from those estimatesand assumptions. In preparing our financial statements andaccounting for the underlying transactions and balances, weapply our accounting policies as disclosed in our notes to thecondensed Consolidated Financial Statements. The accountingpolicies discussed below are those that we consider to becritical to an understanding of our financial statements becausetheir application places the most significant demands on ourability to judge the effect of inherently uncertain matters onour financial results. For all of these policies, we cautionthat future events rarely develop exactly as forecast, and thebest estimates routinely require adjustment. • *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. 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
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     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 arecalculated based on dollars in thousands. The states ofPennsylvania and New Jersey are within the same ISO territoryand 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 endedJanuary 31, 2005 compared to the three months endedJanuary 31, 2004. Gross profit increased $5.1 millionto $8.4 million for the three months ended January 31,2005 compared to $3.3 million for the same prior yearperiod. The revenue and gross profit improvement in the threemonths ended January 31, 2005 was primarily due to the saleof a portion of our Pennsylvania energy supply for$9.3 million and an increase in excess energy sales of$5.9 million, partly offset by a $1.6 millionmark-to-market loss related largely to derivative contractsmarked at the end of the quarter. For the quarter endedOctober 31, 2004, the Company recognized a netmark-to-market gain on its derivatives of $1.1 million. OnJanuary 28, 2005, we made a strategic decision todiscontinue service to certain residential and small commercialcustomers in the Pennsylvania territory, and sold backelectricity supply commitments to our energy supplier for$9.3 million. This gain was partially offset by$1.5 million and $0.6 million of additional cost, tocover the timing and forecasting issues related to realigningthe customer portfolio, incurred in the third fiscal quarter of2005 and estimated to be incurred in the fourth fiscal quarterof 2005, respectively. The Company’s operating results forthe three months ended January 31, 2005 included a lossfrom operations of $2.4 million compared to a loss of$4.6 million for the same prior year period.
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*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 theprior fiscal year. The decrease resulted primarily fromdecreased energy sales of $3.9 million in California and$1.1 million in Pennsylvania offset by an increase inMichigan of $3.3 million compared to the prior year period.In California, we sold 201 million kWh at an average retailprice per kWh of $0.071 in the three months endedJanuary 31, 2005, as compared to 267 million kWh soldat an average retail price per kWh of $0.068 in the same periodlast year. The decrease in volume was primarily attributable tocustomer attrition due in part to our efforts to improveprofitability per customer. In Pennsylvania, we sold328 million kWh at an average retail price per kWh of$0.057 in the three months ended January 31, 2005, ascompared to 305 million kWh sold at an average retail priceper kWh of $0.065 in the same period last year. The volumeincrease was primarily due to our increased customer base in thecurrent year in New Jersey which was offset by an average pricedecrease in this territory due to unstable prices as we enteredthis new market at the end of fiscal 2004. In Michigan, we sold190 million kWh at an average retail price per kWh of$0.060 in the three months ended January 31, 2005, ascompared to 151 million kWh at an average retail price perkWh of $0.054 in the same period last year. The increase involume was primarily due to continued increases in our Michigancustomer 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 theprior year. The increase is attributable to the$9.3 million sale of future electricity supply inPennsylvania and the sale of excess energy for Californiaoperations of $2.3 million and for Pennsylvania operationsof $3.6 million compared to the prior fiscal second quarter.     Excess energy sales represents the proceeds from surpluselectric power we sell back into the wholesale market when theelectricity we have acquired exceeds our retail customer’srequirements. The sale of excess energy supply is a naturalby-product of balancing the power load used by our customersagainst the power that we have previously purchased undercontract in anticipation of our forecast customer demand. Due tothe inherent mismatch between our block purchases and our retaildemand and the volatility of customer load from day-to-day andwithin a given day, and the volatility of prices on the spotmarket, significant fluctuations in excess energy sales canoccur from the optimization of the Company’s supplyportfolio and customer demand.     At January 31, 2005, we had approximately 94,000 customerscompared to 107,000 customers at January 31, 2004. Weexperienced higher attrition as rates increased in California by17% and in Pennsylvania by 14%. We increased our customer basein Michigan by 29% and began to market in New Jersey in December2003.***Direct Energy Costs***     Direct energy costs, which are recognized concurrently withrelated energy sales, include the aggregated cost of purchasedelectric power, fees incurred from various energy-relatedservice providers, energy-related taxes that cannot be passeddirectly through to the customer and any mark-to-market gains orlosses on derivative contracts. Our direct energy costsincreased to $52.6 million for the three months endedJanuary 31, 2005, an increase of $8.8 million, or 20%,from $43.8 million for the three months endedJanuary 31, 2004.     The increase in direct energy costs occurred primarily inMichigan and California, with a partial offset in Pennsylvania.In Michigan, our average cost per kWh was $0.052 for the threemonths ended January 31, 2005, as compared to an averagecost per kWh of $0.047 for the same period last year. InCalifornia, our average cost per kWh was $0.061 for the threemonths ended January 31, 2005, as compared to an averagecost per kWh of $0.056 for the same period in fiscal 2004. InPennsylvania, our average cost per kWh was $0.061 for the threemonths ended January 31, 2005, as compared to an averagecost per kWh of $0.063 for the same period in fiscal 2004. Inaddition, increased cost in the current period reflect$2.1 million of
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additional costs incurred in the third fiscal quarter 2005 andestimated to be incurred in the fourth fiscal quarter 2005,which was restated in the second fiscal quarter 2005 to offsetthe $9.3 million gain recognized in this same period.Additionally, the increase in direct energy cost includes$1.6 million of mark to market losses on forward physicalcontracts previously accounted for as cash flow hedges.*Selling and Marketing Expenses*     Our selling and marketing expenses decreased $0.2 million,or 25%, to $0.8 million for the three months endedJanuary 31, 2005, as compared to $1.0 million for thethree months ended January 31, 2004. The decrease wasprimarily due to lower advertising costs in the current fiscalquarter.*General and Administrative Expenses*     Our general and administrative expenses increased$4.2 million, or 72%, to $10.0 million for the threemonths ended January 31, 2005 compared to $5.8 millionin the three months ended January 31, 2004. The increase inthe current fiscal year was primarily attributed to a$3.6 million reserve for potential employment relatedsettlements and severance of $0.5 million.*Reorganization and Initial Public Listing Expenses*     We incurred $1.0 million in the second quarter of fiscal2004 of costs related to our reorganization into a Delawareholding company structure and the initial public listing of ourcommon stock on the American Stock Exchange. Management believedit was appropriate to classify these costs as a separatelyidentified selling, general and administrative expense category,and included expenses such as legal, accounting, auditing,consulting, and printing and reproduction fees that werespecific to these activities. We incurred no such expenses infiscal 2005.*Initial Formation Litigation Expenses*     In the three months ended January 31, 2005, we incurred$0.2 million of initial formation litigation costs relatedto Commonwealth Energy Corporation’s formation compared tono such costs during the three months ended January 31,2004. Initial formation litigation expenses include legal andlitigation costs associated with the initial capital raisingefforts by former Commonwealth Energy Corporation employees,various board member matters, and the legal complicationsarising from those activities.*Provision for Impairment on Investments*     In the three months ended January 31, 2004, we recorded animpairment of $4.3 million on our investments, to reflectour percentage ownership in the net equity of each ofSummit’s two investments: Turbocor and Encorp, Inc.(formerly Envenergy, Inc.).*Minority Interest Share of Loss*     Minority interests in fiscal 2004 represent that portion ofPEC’s post-consolidation losses that are allocated to thenon-Summit investors based on their aggregate minority ownershipinterest in PEC. PEC is no longer consolidated in our financialstatements in fiscal 2005.*Benefit from Income Taxes*     No provision for, or benefit from, income taxes was recorded forthe three months ended January 31, 2005; as compared to thebenefit from income taxes of $0.8 million for the threemonths ended January 31, 2004. In fiscal 2005, weestablished a valuation allowance equal to our calculated taxbenefit because we believed it was not certain that we wouldrealize these tax benefits in the foreseeable future. Thecurrent period results are not sufficient to modify thisconclusion.
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***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 endedJanuary 31, 2004. Gross profit increased $8.0 millionto $15.6 million for the six months ended January 31,2005 as compared to $7.6 million for the same prior yearperiod. The revenue and gross profit improvement in the sixmonths ended January 31, 2005 was primarily due to the saleof a portion of the future Pennsylvania energy supply for$9.3 million, partially offset by $2.1 millionadditional cost incurred to cover the timing and forecastingissues related to realigning the customer portfolio, an increasein excess energy sales of $9.5 million and increased grossprofit in Michigan and New Jersey due to increased customer baseoffset by the continuing pressure on gross profit in theCalifornia business. The Company’s operating results forthe six months ended January 31, 2005 included a loss fromoperations of $0.7 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 energysales of $8.3 million in California and $3.1 millionin Pennsylvania offset by an increase in Michigan of$5.6 million compared to the prior year period. InCalifornia, we sold 462 million kWh at an average retailprice per kWh of $0.072 in the six months ended January 31,2005, as compared to 595 million kWh sold at an averageretail price per kWh of $0.070 in the same period last year. Thedecrease in volume was primarily attributable to customerattrition due in part to our efforts to improve profitabilityper customer. In Pennsylvania, we sold 675 million kWh atan average retail price per kWh of $0.059 in the six monthsended January 31, 2005, as compared to 699 million kWhsold at an average retail price per kWh of $0.061 in the sameperiod last year. The decrease in volume was primarily due todecreases attributable to customer attrition due in part to ourefforts to improve profitability per customer offset byincreases in our New Jersey customer base in the current fiscalyear, while the price continues to fluctuate in this new market.In Michigan, we sold 399 million kWh at an average retailprice per kWh of $0.059 in the six months ended January 31,2005, as compared to 330 million kWh at an average retailprice per kWh of $0.054 in the same period last year. Theincrease in volume was primarily due to continued increases inour 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 offuture electricity supply in Pennsylvania and the sale of excessenergy for California operations of $4.3 million and forPennsylvania operations of $5.2 million as compared to thesix months ended January 31, 2004.***Direct Energy Costs***     Our direct energy costs increased to $104.0 million for thesix months ended January 31, 2005, an increase of$6.1 million, or 6%, from $97.9 million for the sixmonths ended January 31, 2004. The increase in directenergy costs occurred primarily in Michigan and Californiapartially offset by decreases in Pennsylvania related to the NewJersey market. In Michigan, our average cost per kWh was $0.051for the six months ended January 31, 2005, as compared toan 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 sixmonths ended January 31, 2005, as compared to an averagecost per kWh of $0.055 for the same period in fiscal 2004. InPennsylvania, our average cost per kWh was $0.057 for the sixmonths ended January 31, 2005, as compared to an averagecost per kWh of $0.063 for the same period in fiscal 2004.
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*Selling and Marketing Expenses*     Our selling and marketing expenses decreased $0.3 million,or 13%, to $1.7 million for the six months endedJanuary 31, 2005, as compared to $2.0 million for thesix months ended January 31, 2004. The decrease isprimarily due to decreased advertising costs in the currentfiscal period.*General and Administrative Expenses*     Our general and administrative expenses increased$3.8 million, or 33%, to $15.1 million for the sixmonths 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 relatedsettlements.*Reorganization and Initial Public Listing Expenses*     We incurred $1.1 million in the six months endedJanuary 31, 2004 of costs related to our reorganizationinto a Delaware holding company structure and the initial publiclisting of our common stock on the American Stock Exchange.Management believed it was appropriate to classify these costsas a separately identified selling, general and administrativeexpense category, and included expenses such as legal,accounting, auditing, consulting, and printing and reproductionfees that were specific to these activities. We incurred no suchexpenses 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 relatedto Commonwealth Energy Corporation’s formation compared to$0.6 million incurred during the six months endedJanuary 31, 2004. Initial formation litigation expensesinclude legal and litigation costs associated with the initialcapital raising efforts by former Commonwealth EnergyCorporation employees, various board member matters, and thelegal complications arising from those activities.*Minority Interest Share of Loss*     Minority interests in fiscal 2004 represent that portion ofPEC’s post-consolidation losses that are allocated to thenon-Summit investors based on their aggregate minority ownershipinterest in PEC. PEC is no longer consolidated in our financialstatements in fiscal 2005.*Benefit from Income Taxes*     No provision for, or benefit from, income taxes was recorded forthe six months ended January 31, 2005; as compared to thebenefit from income taxes of $1.8 million for the sixmonths ended January 31, 2004. In fiscal 2005, weestablished a valuation allowance equal to our calculated taxbenefit because we believed it was not certain that we wouldrealize these tax benefits in the foreseeable future. Thecurrent period results are not sufficient to modify thisconclusion.**Liquidity and Capital Resources**     As of January 31, 2005, our unrestricted cash and cashequivalents were $50.0 million, compared to$54.1 million at July 31, 2004 and our restricted cashand cash equivalents were $4.3 million, compared to$4.0 million at July 31, 2004. In addition torestricted cash, we also had cash deposits of $6.7 millionat January 31, 2005, compared to $5.4 million atJuly 31, 2004. Our principal sources of liquidity to fundongoing operations were cash provided by operations and existingcash and cash equivalents.     Cash flow used in operations for the six months endedJanuary 31, 2005 was $3.2 million, compared to cashflow provided by operations of $5.4 million in the sixmonths ended January 31, 2004. In the six months endedJanuary 31, 2005, cash was used primarily by an increase inaccounts receivable of $2.4 million and a decrease inaccounts payable of $7.3 million offset by an increase inaccrued liabilities related to hedged electric contracts and adecrease in prepaid expenses of $2.0 million primarily dueto a prepayment contract ending in December 2004.
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     Cash flow used in investing activities for the six months endedJanuary 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 endedJanuary 31, 2005 was $0.5 million, compared to cashflow provided by financing activities of $8.6 million inthe six months ended January 31, 2004. In the currentfiscal year, cash flow used was primarily for the cancellationof common stock and increased restricted cash primarily forincreased required letters of credit in New Jersey. In the priorfiscal year, restricted cash decreased primarily due to thecancellation 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 creditsecured by cash related to energy suppliers.     The Company does not have open lines of credit for directunsecured borrowings or letters of credit. Credit terms from oursuppliers of electricity often require us to post collateralagainst our energy purchases and against our mark-to-marketexposure with certain of our suppliers. We currently financethese collateral obligations with our available cash. If we arerequired to post such additional security, a portion of our cashwould become restricted, which could adversely affect ourliquidity. As of January 31, 2005, we had $4.3 millionin restricted cash to secure letters of credit required by oursuppliers and $6.5 million in deposits pledged ascollateral in connection with energy purchase agreements.     Based upon our current plans, level of operations and businessconditions, we believe that our cash and cash equivalents, andcash generated from operations will be sufficient to meet ourcapital requirements and working capital needs for theforeseeable future. However, there can be no assurance that wewill not be required to seek other financing in the future orthat such financing, if required, will be available on termssatisfactory to us.***Contractual Obligations***     There have been no material changes to contractual obligationsfrom the disclosures set forth in Part II, Item 7 inour Annual Report on Form 10-K for the year endedJuly 31, 2004, except as set forth below.     In January 2005, we sold back our electricity supply commitmentsrelated to serving certain residential and small commercialcustomers, in the Pennsylvania territory, to our energysupplier. The supply commitments would have provided us withelectricity to serve the discontinued customers’electricity requirements through May 2006. The transactionoccurred in January 2005 and resulted in a gain on the sale ofthe supply commitments of $9.3 million, which has beenreflected in our financial statements for our second fiscalquarter ending January 31, 2005. This gain was partiallyoffset by $2.1 million of additional cost, to cover thetiming and forecasting issues related to realigning the customerportfolio, incurred in the third fiscal quarter of 2005 andestimated to be incurred in the fourth fiscal quarter of 2005.We will continue to serve remaining customers in thePennsylvania territory from remaining supply contracts withother wholesale suppliers. After giving effect to the supplycommitment that was sold in the Pennsylvania territory and anynew supply commitments entered into in the second fiscalquarter, our contractual commitments for electricity purchasecontracts as of January 31, 2005 are $55.1 million, ofwhich $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 withAmerican Communications Network, Inc. (“ACN”), andseveral of its subsidiaries, ACN Utility Services, Inc.(“ACN Utility”), ACN Energy, Inc. (“ACNEnergy”) and ACN Power, Inc. (“ACN Power”, andcollectively with ACN Utility and ACN Energy, the“Sellers”) to purchase certain assets of theSellers’ retail electric power and natural gas salesbusiness, and assume specified liabilities. The Sellers sellretail electric power in Texas and Pennsylvania and sell retailnatural gas in California, Ohio, Georgia, New York, Pennsylvaniaand Maryland. The assets acquired include equipment, gasinventory associated with utility and pipeline storage andtransportation agreements and electricity supply, scheduling andcapacity contracts, software and other infrastructure plusapproximately 80,000 residential and small commercial customers.The initial consideration paid by us was
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(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 commonstock as of February 8, 2005, the date immediately prior tothe closing date. The shares of common stock will initially beplaced in escrow and released upon satisfaction of certainperformance targets related to customer growth. ACN was alsopaid at closing an estimated prepayment amount of approximately$5.5 million as payment for certain working capital andprepayment items relating to the assets being acquired, and aresubject to final adjustment and settlement. We have sufficientcash to cover the needs of this acquisition. This transactionwas previously reported by us on a current report onForm 8-K filed with the Securities and Exchange Commissionon 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, hasmaintained a strong commitment over the past seven years to thederegulation of electricity markets. This movement would seem toindicate the continuation and growth of a competitive electricretail industry. Twenty-four states and the District of Columbiahave either enacted enabling legislation or issued a regulatoryorder to implement retail access. In 18 of these states, retailaccess is either currently available to some or all customers,or will soon be available. However, in many of these markets themarket rules adopted have not resulted in energy serviceproviders being able to compete successfully with the localutilities and customer switching rates have been low. Ourbusiness model depends on other favorable markets opening underviable competitive rules in a timely manner. In any particularmarket, there are a number of rules that will ultimatelydetermine the attractiveness of any market. Markets that weenter may have both favorable and unfavorable rules. If thetrend towards competitive restructuring of retail energy marketsdoes not continue or is delayed or reversed, our businessprospects and financial condition could be materially adverselyimpaired.     Retail energy market restructuring has been and will continue tobe a complicated regulatory process, with competing interestsadvanced not only by relevant state and federal utilityregulators, but also by state legislators, federal legislators,local utilities, consumer advocacy groups and other marketparticipants. As a result, the extent to which there arelegitimate competitive opportunities for alternative energysuppliers in a given jurisdiction may vary widely and we cannotbe assured that regulatory structures will offer us competitiveopportunities to sell energy to consumers on a profitable basis.The regulatory process could be negatively impacted by a numberof factors, including interruptions of service and significantor rapid price increases. The legislative and regulatoryprocesses in some states take prolonged periods of time. In anumber of jurisdictions, it may be many years from the datelegislation is enacted until the retail markets are truly openfor competition.     In addition, although most retail energy market restructuringhas been conducted at the state and local levels, bills havebeen proposed in Congress in the past that would preempt statelaw concerning the restructuring of the retail energy markets.Although none of these initiatives has been successful, wecannot assure stockholders that federal legislation will not bepassed in the future that could materially adversely affect ourbusiness.***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 andexpand our business, including brand development, marketing andother promotional activities and the continued development ofour billing, customer care and power procurement infrastructure.Our ability to operate profitably will depend on, among otherthings: •     Our ability to attract and to retain a critical mass of    customers at a reasonable cost;  •     Our ability to continue to develop and maintain internal    corporate organization and systems;
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 •     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 enternew markets and pursue customers by utilizing a variety ofmarketing methods. In order for us to recover these expenses, wemust attract and retain a large number of customers to ourservice.     We may experience difficulty attracting customers because manycustomers may be reluctant to switch to a new supplier for acommodity as critical to their well-being as electric power. Amajor focus of our marketing efforts will be to convincecustomers that we are a reliable provider with sufficientresources to meet our commitments. If our marketing strategy isnot successful, our business, results of operations andfinancial 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 ourback-office functions, including customer enrollment, metering,forecasting, settlement and billing. Problems that arise withthe performance of our back-office functions could result inincreased expenditures, delays in the launch of our commercialoperations into new markets, or unfavorable customer experiencesthat could materially adversely affect our business strategy.Also, any interruption of these services could be disruptive toour 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 totime, purchase electricity in the short-term or spot wholesaleenergy markets, which can be highly volatile. In particular, thewholesale electric power market can experience large pricefluctuations during peak load periods. Furthermore, to theextent that we enter into contracts with customers that requireus to provide electricity at a fixed price over an extendedperiod of time, and to the extent that we have not purchasedelectricity to cover those commitments, we may incur lossescaused by rising wholesale electricity prices. Periods of risingelectricity prices may reduce our ability to compete with localutilities because their regulated rates may not immediatelyincrease to reflect these increased costs. Energy ServiceProviders like us take on the risk of purchasing power for anuncertain load and if the load does not materialize as forecast,it leaves us in a long position that would be resold into thewholesale electricity market. Sales of this surplus electricitycould be at prices below our cost. Conversely, if unanticipatedload appears that may result in an insufficient supply ofelectricity, we would need to purchase the additional supply.These purchases could be at prices that are higher than oursales price to our customers. Either situation could createlosses for us if we are exposed to the price volatility of thewholesale spot markets. Any of these contingencies couldsubstantially increase our costs of operation. Such factorscould have a material adverse effect on our financial condition.     We are dependent on local utilities for distribution ofelectricity to our customers over their distribution networks.If these local utilities are unable to properly operate theirdistribution networks, or if the operation of their distributionnetworks is interrupted for periods of time, we could be unableto deliver electricity to our customers during thoseinterruptions. This would results in lost revenue to us, whichcould 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 wasauthorized to recoup $3.6 billion in debt incurred duringthe energy crisis of 2000-2001 from all customers. This debt wasto be collected under the Procurement Related ObligationsAccount, or PROACT, from bundled (non direct access) customersand under the HPC from DA customers.     In July 2002, the California PUC issued an interim orderimplementing the HPC sought by SCE. This interim orderauthorized SCE to collect $391 million in HPC charges fromall DA customers by reducing their Procured Energy Credit, or PECredit, by $0.027 per kWh beginning July 27, 2002. Thelowered PE Credit continued until an exit fee for DA customerswas approved by the CPUC. Effective January 1, 2003, it wasreduced to $0.01 per kWh. For the fiscal year endedJuly 31, 2003, we estimated that HPC charges had impactedour sales and pretax earnings by a range of $4.8 million to$6.0 million. We were unable to precisely determine theactual HPC charges applied to our customers by SCE because therewere different charges, by customer type, and this charge wasonly on the electricity usage above the monthly baseline usageallocation.     On September 5, 2003 the CPUC issued Decision 03-09-016granting SCE’s request to recover additional shortfall andauthorizing the HPC balance to be revised to $473 million;however, the $0.01 per kWh monthly charge remained inplace. As of August 1, 2003, SCE revised its billingmethodology to a “bottoms-up” design effectively doingaway with the PE Credit and the net effect of the HPC on ourrates. While the HPC no longer discretely impacts our ratecalculations, a recent SCE rate reduction indirectly includesthe former impact of the HPC. This rate reduction impacted salesand pretax profit in the SCE district. The rate reductionremained in place in 2004 and approximated the effect of the HPCdollar impact of 2003.     In 2003, SCE acknowledged that the PROACT debt was paid in fullby bundled customers at the end of July 2003. As a result, onAugust 1, 2003, all SCE rates were lowered. As a directresult, to retain our customers in the SCE utility district, welowered our customer rates proportionately. Our estimate of theannual financial impact of this rate reduction is a decline insales and pretax profit during fiscal 2004, in the range of $3.0to $3.5 million. This reduction is separate from, and inaddition to, the HPC related reduction in 2003.     These changes in the SCE service territory will continue tocause a significant impact on our revenue and cash flow;however, we currently do not expect they will preclude us fromcontinuing to participate in the SCE market.***Some suppliers of electricity have been experiencing    deteriorating credit quality.***     We continue to monitor our suppliers’ credit quality toattempt to reduce the impact of any potential counterpartydefault. As of January 31, 2005, the majority of ourcounterparties are rated investment grade or above by the majorrating agencies. These ratings are subject to change at any timewith no advance warning. A deterioration in the credit qualityof our suppliers could have an adverse impact on our sources ofelectricity 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-termcontracts is fixed over the term of the contracts, if the marketprice of wholesale electricity decreases below the contractprice, the power generator may require us to post margin in theform of a letter of credit, or other collateral, to protectthemselves against our potential default on the contract. If weare required to post such security, a portion of our cash wouldbecome restricted, which could adversely affect our liquidity.
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***We are required to rely on utilities with whom we will be    competing to perform some functions for our customers.***     Under the regulatory structures adopted in most jurisdictions,we will be required to enter into agreements with localutilities for use of the local distribution systems, and for thecreation and operation of functional interfaces necessary for usto serve our customers. Any delay in these negotiations or ourinability to enter into reasonable agreements with thoseutilities could delay or negatively impact our ability to servecustomers in those jurisdictions. This could have a materialnegative impact on our business, results of operations andfinancial condition.     We are dependent on local utilities for maintenance of theinfrastructure through which electricity is delivered to ourcustomers. We are limited in our ability to control the level ofservice the utilities provide to our customers. Anyinfrastructure failure that interrupts or impairs delivery ofelectricity to our customers could have a negative effect on thesatisfaction of our customers with our service, which could havea material adverse effect on our business.     Regulations in many markets require that the services of readingour customers’ energy meters and the billing and collectionprocess be retained by the local utility. In those states, wewill be required to rely on the local utility to provide us withour customers’ energy usage data and to pay us for ourcustomers’ usage based on what the local utility collectsfrom our customers. We may be limited in our ability to confirmthe accuracy of the information provided by the local utilityand we may not be able to control when we receive payment fromthe local utility. The local utility’s systems andprocedures may limit or slow down our ability to create asupplier relationship with our customers that would delay thetiming of when we can begin to provide electricity to our newcustomers. If we do not receive payments from the local utilityon 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 andcollection functions for our customers. In these markets, we maybe limited in our ability to terminate service to customers whoare delinquent in payment. Even if we terminate service tocustomers who fail to pay their utility bill in a timely manner,we may remain liable to our suppliers of electricity for thecost of the electricity and to the local utilities for servicesrelated to the transmission and distribution of electricity tothose customers. The failure of our customers to pay their billsin a timely manner or our failure to maintain adequate billingand collection programs could materially adversely affect ourbusiness.***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 powergeneration companies to our retail customers on a contractualbasis. We are not guaranteed any rate of return throughregulated rates, and our revenues and results of operations arelikely to depend, in large part, upon prevailing market pricesfor electricity in our regional markets. These market prices mayfluctuate substantially over relatively short periods of time.These factors could have an adverse impact on our revenues andresults of operations.     Volatility in market prices for electricity results frommultiple 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 ACNEnergy, 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 ACNEnergy’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 providereliable financial reports and effectively prevent fraud. If wecannot provide reliable financial reports or prevent fraud, ouroperating results could be harmed. We have in the pastdiscovered, and may in the future discover, areas of ourinternal controls that need improvement. For example, in January2005, we sold electricity commodity supply contracts related toa strategic realignment of our customer portfolio in thePennsylvania electricity market and the discontinuation ofservice to certain classes of residential and small commercialcustomers. As a result of timing issues related to realigningthe portfolio and inaccurately forecasting the resultingrequired electricity supply, we had transitional electricitysupply obligations which could have been served more costeffectively with the original supply contract rather than withthe current market cost of the replacement power. In theexecution of this portfolio realignment, we observeddeficiencies in our internal controls relating to monitoring theoperational progress of the realignment. These internal controldeficiencies constituted reportable conditions, andcollectively, a material weakness that caused us to restate oursecond quarter reported results. In connection with thepreparation of our consolidated financial statements for thefiscal year ended July 31, 2005, we determined that(a) certain electricity forward physical contracts andfinancial derivatives designated as cash flow hedges lackedadequate documentation of our method of measurement and testingof hedge effectiveness to meet the cash flow hedge requirementsof SFAS 133 and (b) a forward physical contract andseveral financial derivative contracts had been inappropriatelyaccounted for as exempt from hedge accounting underSFAS 133. These errors in the proper application of theprovisions of SFAS No. 133 required us to restate ourpreviously reported results for each of the first three quartersin fiscal 2005 and led us to conclude and report the existenceof a material weakness in our internal controls over financialreporting. We purchase substantially all of our power andnatural gas under forward physical delivery contracts, which aredefined as commodity derivative contracts underSFAS No. 133. We also utilize other financialderivatives, primarily swaps, options and futures, to hedge ourprice risks. Accordingly, proper accounting for these contractsis very important to our overall ability to report timely andaccurate financial results.     We have devoted significant resources to remediate and improveour internal controls. Although we believe that these effortshave strengthened our internal controls and addressed theconcerns that gave rise to the reportable conditions andmaterial weaknesses in fiscal 2004 and 2005, we are continuingto work to improve our internal controls, particularly in thearea of energy accounting. We cannot be certain that thesecontrols, or difficulties encountered in their implementation,could harm our operating results or cause us to fail to meet ourreporting obligations. Inferior internal controls could alsocause investors to lose confidence in our reported financialinformation, which could have a negative effect on the tradingprice of our stock.
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*** ******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 required by Section 404 of the    Sarbanes-Oxley Act of 2002.***     As directed by Section 404 of the Sarbanes-Oxley Act of2002, the Securities and Exchange Commission adopted rulesrequiring public companies to include a report of management onour internal controls over financial reporting in our AnnualReports on Form 10-K that contains an assessment bymanagement of the effectiveness of our internal controls overfinancial reporting. In addition, our independent auditors mustattest to and report on management’s assessment of theeffectiveness of our internal controls over financial reporting.This requirement will first apply to our Annual Report onForm 10-K for the fiscal year ending July 31, 2006 ifthe aggregate market value of the voting and non-voting commonequity held by non-affiliates is $75 million or more as ofthe last business day of January 2006. If not, such requirementwill first apply to our Annual Report on Form 10-K for thefiscal year ending July 31, 2007. How companies should beimplementing these new requirements including internal controlreforms, if any, to comply with Section 404’srequirements, and how independent auditors will apply these newrequirements and test companies’ internal controls, aresubject to uncertainty. Although we are diligently andvigorously reviewing our internal controls over financialreporting in order to ensure compliance with the newSection 404 requirements, if our independent auditors arenot satisfied with our internal controls over financialreporting or the level at which these controls are documented,designed, operated or reviewed, or if the independent auditorsinterpret the requirements, rules or regulations differentlythan we do, then they may decline to attest to management’sassessment or may issue a report that is qualified. This couldresult in an adverse reaction in the financial marketplace dueto a loss of investor confidence in the reliability of ourfinancial statements, which ultimately could negatively impactthe market price of our shares.     We have initiated a company-wide review of our internal controlsover financial reporting as part of the process of preparing forcompliance with Section 404 of the Sarbanes-Oxley Act of2002 and as a complement to our existing overall program ofinternal controls over financial reporting. As a result of thison-going review, we have made numerous improvements to thedesign and effectiveness of our internal controls over financialreporting. We anticipate that improvements will continue to bemade.**Item 3.*****Quantitative and Qualitative Disclosures About Market    Risk.***     There have been no material changes to information called for bythis Item 3 from the disclosures set forth in Part II,Item 7A in the Company’s Annual Report onForm 10-K for the year ended July 31, 2004, except asset forth below.     Our activities expose us to a variety of market risks includingcommodity prices and interest rates. Management has establishedrisk management policies and strategies to reduce thepotentially adverse effects that the price volatility of thesemarkets may have on our operating results. Our risk managementactivities, including the use of derivative instruments, aresubject to the management, direction and control of an internalrisk oversight committee. We maintain commodity price riskmanagement strategies that use derivative instruments withinstrict risk tolerances to minimize significant, unanticipatedearnings fluctuations caused by commodity price volatility.Changes in the fair market value of these derivative instrumentsare recognized currently in earnings unless specific hedgeaccounting criteria are met.     Supplying electricity to retail customers requires us to matchcustomers’ projected demand with fixed price purchases. Weprimarily use forward physical energy purchases and derivativeinstruments to minimize significant, unanticipated earningsfluctuations caused by commodity price volatility. In certainmarkets where we operate, entering into forward fixed pricecontracts may be expensive relative to derivative alternatives.Derivative instruments, primarily swaps and futures, are used tohedge the future purchase price of electricity for theapplicable forecast usage protecting us from significant pricevolatility. We did not engage in trading activities in thewholesale energy market other than to manage our direct energycost in an attempt to improve the profit margin associated withour customer requirements.     On January 28, 2005, we sold back future electricity supplycommitments related to serving certain customers in Pennsylvaniato our energy supplier. As a result of the portfolio rebalancingrequired due to this
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sale, the portfolio coverage ratio is more meaningful atFebruary 28, 2005, where we had 87% of our forecast energyload through December 31, 2005 covered through either fixedprice power purchases with counterparties, or price protectedthrough financial hedges.**Item 4.*****Controls and Procedures.*****Restatement of Quarterly Periods***Gain on Sale of Electricity Supply Contracts*     In January 2005, we sold electricity commodity supply contractsrelated to a strategic realignment of our customer portfolio inthe Pennsylvania electricity market and the discontinuation ofservice to certain classes of residential and small commercialcustomers. As a result of timing issues related to realigningthe portfolio and inaccurately forecasting the resultingrequired electricity supply, we had transitional electricitysupply obligations which could have been served more costeffectively with the original electricity supply contractsrather than with the replacement power which we subsequentlypurchased at market prices. In the execution of this portfoliorealignment, we observed deficiencies in our internal controlsrelating to monitoring the operational progress of therealignment. Ernst & Young LLP, our independentregistered public accounting firm, advised us on June 8,2005 that in their opinion, with which we concurred, theseinternal control deficiencies constituted reportable conditionsand collectively, a material weakness in our internal controlover financial reporting and that our unaudited condensedconsolidated financial statements for the three and six monthsperiod ended January 31, 2005 should be restated. As aresult of these timing and forecasting issues and internalcontrol deficiencies, on June 14, 2005, we restated ourunaudited condensed consolidated financial statements for thethree and six months periods ended January 31, 2005 byfiling the Quarterly Report on Form 10-Q/A (AmendmentNo. 1) for the period ended January 31, 2005. Thefinancial impact of this adjustment (principally, reporting anet loss of $729,000 for the three months period endedJanuary 31, 2005 instead of the previously reported netincome of $1,371,000 and a net loss of $1,848,000 for the sixmonths period ended January 31, 2005 instead of thepreviously reported net income of $252,000), and to includeadditional disclosures in the appropriate period related tothese internal control deficiencies. On July 12, 2005, wefiled our Quarterly Report on Form 10-Q/ A (AmendmentNo. 2) for the quarterly period ended January 31, 2005to clarify the results of our evaluation of controls andprocedures for the period ended January 31, 2005.     With respect to the above-referenced deficiencies and materialweakness in our internal control over financial reporting, wetook the following corrective actions, some of which we began toimplement as early as March 2005: •      Determined that a major integrated system upgrade was required    to replace the current in-house forecasting, meter tracking and    sales systems. We have selected several third party software    systems that meet our requirements and have made substantial    implementation progress;  •      Established procedures to reconcile demand and load factors    among the various in-house systems until the integrated system    can be fully implemented;  •      Established procedures to reconcile meter counts on a weekly    basis among the various in-house systems until the integrated    system can be fully implemented; and  •      Established senior level management oversight of the load    forecasting process, including weekly update and reporting    meetings.     With the exception of the completion of the integrated systemupgrades, which we expect to complete by the end of the secondquarter of fiscal 2006, we have completed the other correctiveactions during the third quarter of fiscal 2005.**     ***SFAS No. 133*     In connection with the preparation of our financial statementsfor the fiscal year ended July 31, 2005, we determined thatcertain forward physical contracts and financial derivativespreviously designated as cash flow hedges lacked adequatedocumentation of our method of measurement and testing of hedgeeffectiveness to meet the cash flow hedge requirements ofStatement of Financial Accounting Standards No. 133,*Accounting for Derivative Instruments and HedgingActivities*, as amended (SFAS No. 133).Additionally, we determined
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that a forward physical contract and several financialderivative contracts had been inappropriately accounted for asnormal purchase and normal sale contracts and therebyerroneously accounted for as exempt from hedge accounting underSFAS No. 133.     Without adequate documentation, we are not eligible to applycash flow hedge accounting in fiscal 2005. Additionally, thederivative contracts that had been inappropriately accounted foras exempt from hedge accounting must be marked to the market.Mark to market gains or losses on these derivative contracts arerequired to be reflected in the statement of operations for eachperiod rather than deferred as a component of othercomprehensive income (loss) until physical delivery.     As a result, management has determined that the failure toproperly document and account for certain of our forwardphysical contracts and financial derivatives in accordance withthe requirements of SFAS No. 133 represented amaterial weakness in our internal control over financialreporting.     On October 25, 2005, management recommended to the AuditCommittee of our Board of Directors that previously reportedfinancial results for the quarterly periods endedOctober 31, 2004, January 31, 2005 and April 30,2005 be restated to reflect proper accounting treatment forthese derivatives in accordance with SFAS No. 133 andthat the quarterly financial statements for the periods endedOctober 31, 2004, January 31, 2005 and April 30,2005 should no longer be relied upon. The Audit Committee agreedwith management’s assessment and recommendation and onOctober 26, 2005 recommended the same action to the Boardof Directors, which, on the same date, determined that thepreviously reported quarterly results for fiscal 2005 should berestated to reflect the appropriate accounting for thesederivatives. As a result, we are restating our quarterly resultsfor each of the first three quarters in the fiscal year endedJuly 31, 2005.     We have taken the following corrective actions which we believewill remediate the material weakness in our internal controlover financial reporting with respect to appropriate applicationof the provisions of SFAS No. 133 for our energysupply activities. The remedial actions included the institutionof: (a) improved training, education and accountingpolicies and procedures designed to ensure that all relevantpersonnel involved in the our utilization of derivativetransactions understand and apply cash flow hedge accounting incompliance with SFAS No. 133; and(b) additional senior management oversight proceduresdesigned to ensure such compliance. We expect that this processof remediation will be completed by the end of the first quarterof fiscal 2006.**Evaluation of Disclosure Controls and Procedures**     In light of the above-referenced information, we(a) conducted an evaluation of the effectiveness of thedesign and operation of our disclosure controls and procedures(as defined under Rules 13a-15(e) and 15d-15(e) under theSecurities Exchange Act of 1934, as amended (the “ExchangeAct”)) as of the end of the period covered by thisQuarterly Report on Form 10-Q/ A (Amendment No. 3);and (b) evaluated (in connection with the evaluationrequired by paragraph (d) of Rule 13a-15 or15d-15 of the Exchange Act) whether any change in our internalcontrol over financial reporting occurred during the secondquarter ended January 31, 2005 which materially affected,or is reasonably likely to materially affect, our internalcontrol over financial reporting. Each evaluation was done underthe supervision and with the participation of management,including our Chief Executive Officer and our Interim ChiefFinancial Officer.     Based upon the evaluation of the effectiveness of the design ofand operation of our disclosure controls and procedures as ofthe end of the period covered by this Quarterly Report onForm 10-Q/ A (Amendment No. 3), our Chief ExecutiveOfficer and Interim Chief Financial Officer concluded that,because of the deficiencies referenced above, the Company’sdisclosure controls and procedures were not effective as of theend of the quarterly period ended January 31, 2005.**Changes in Internal Control Over Financial Reporting**     There were no material changes in our internal controls overfinancial reporting during the second quarter of fiscal 2005that materially affected, or are reasonably likely to materiallyaffect, our internal control over financial reporting. Webelieve that the change to our internal controls and proceduresdesigned to address the
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deficiency related to the gain on sale of electricity supplycontracts, the implementation of which commenced during thethird quarter of fiscal 2005, and the change to our internalcontrols and procedures designed to address the deficiencyrelated to the application of SFAS No. 133, theimplementation of which commenced during the first quarter offiscal 2006, each has materially affected our internal controlover financial reporting.**PART II — OTHER INFORMATION****Item 1.*****Legal Proceedings.***     Reference is made to the Company’s Report on Form 10-Kfor the period ended July 31, 2004 (the “10-K”),for a summary the Company’s legal proceedings previouslyreported. Since the date of the 10-K, there have been nomaterial developments in previously reported legal proceedings,except as set forth below.     On January 21, 2005, the court granted the Company’smotion to dismiss in Coltrain, et al. v. CommonwealthEnergy Corporation, et al. (Case number CV03-8560-FMC(RNBx)) for lack of prosecution.     On December 23, 2004, the Company entered into a full andcomprehensive Settlement Agreement and Mutual General Release(the “Settlement Agreement”) with stockholder andformer director of Commonwealth Energy Corporation, Joseph P.Saline, and stockholder Joseph Ogundiji. The SettlementAgreement effectively ended all legal actions between theparties that began in 2001, including Orange Court SuperiorCourt case numbers 01CC10657, 01CC13887, 04CC09285, 03CC03409,04CC05038. The Settlement Agreement acknowledges and validatesMr. Saline’s shares of common stock in the Company andprovides for a $1.2 million settlement payment toMr. Saline. The Settlement Agreement also providesMr. Ogundiji with a payment of $222,400 in settlement ofall his claims and for canceling all of his shares of commonstock. In addition, Mr. Saline and Mr. Ogundiji agreedthat for the next two years they would submit any futuredisputes to mediation before commencing litigation or beforethey take any steps to contact the Company’s stockholdersfor any reason related to bringing a proxy contest.     On February 18, 2005, the court struck the defendant’sanswers and dismissed their counter-claim in Commonwealth EnergyCorporation v. Wayne Mosley, et al. (Case numberCV03-00402-NM (RNBx)) for failure to prosecute and failure tocomply 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 thethree months ended January 31, 2005:**Issuer Purchases of Equity Securities**                   **(a)** **(b)** **(c)** **(d)**                 **Maximum**        **Number (or**        **Approximate**        **Dollar**        **Value) of**      **Total Number** **Shares (or**      **of Shares** **Units) that**    **Average** **(or Units)** **may yet be**    **Price** **Purchased as** **Purchased**  **Total Number of** **Paid per** **Part of Publicly** **Under the**  **Shares (or Units)** **Share** **Announced Plans** **Plans or****Period** **Purchased** **(or Unit)** **or Programs** **Programs**             November 1 - 30, 2004  —   —   —   —     December 1 - 31, 2004  120,000(1)  (1)  —   —     January 1 - 31, 2005  —   —   —   — 
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 (1)     In connection with a Settlement Agreement and Mutual General    Release (the “Settlement Agreement”) the 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 meetingof stockholders held on January 12, 2005 were previouslyreported on a current report on Form 8-K filed with theSecurities and Exchange Commission on January 19, 2005.**Item 6.*****Exhibits.***     The exhibit listed below is hereby filed with the Securities andExchange Commission as part of this Report.     **Exhibit**  **Number** **Description**    10.1     Settlement Agreement and Mutual General Release dated    December 23, 2004 by and between Commerce Energy Group,    Inc, Commonwealth Energy Corporation, Ian Carter, Robert    Perkins, Brad Gates, Joseph P. Saline, Patricia E. Saline and    Joseph Ogundiji, previously filed with the Commission as    Exhibit 10.1 to the Company’s Current Report on    Form 8-K filed with the Commission on December 27,    2004, which is incorporated herein by reference. 10.2     Commerce Energy Group, Inc. 2005 Employee Stock Purchase Plan,    previously filed with the Commission as Exhibit 10.1 to the    Company’s Current Report on Form 8-K filed with the    Commission on January 19, 2005, which is incorporated    herein by reference. 10.3     Asset Purchase Agreement dated as of February 9, 2005 by    and among Commonwealth Energy Corporation, ACN Utility Services,    Inc., ACN Energy, Inc., ACN Power, Inc. and, as to certain    sections thereof only, Commerce Energy Group, Inc. and American    Communications Network, Inc., previously filed with the    Commission as Exhibit 2.1 to the Company’s Current    Report on Form 8-K filed with the Commission on    February 10, 2005, which is incorporated herein by    reference. 10.4     Transition Services Agreement dated as of February 9, 2005    by and between American Communications Network, Inc. and    Commonwealth Energy Corporation, previously filed with the    Commission as Exhibit 2.2 to the Company’s Current    Report on Form 8-K filed with the Commission on    February 10, 2005, which is incorporated herein by    reference. 10.5     Sales Agency Agreement dated as of February 9, 2005 by and    among Commonwealth Energy Corporation, Commerce Energy Group,    Inc. and American Communications Network, Inc., previously filed    with the Commission as Exhibit 2.3 to the Company’s    Current Report on Form 8-K filed with the Commission on    February 10, 2005, which is incorporated herein by    reference. 10.6     Escrow Agreement dated as of February 9, 2005 by and among    Commonwealth Energy Corporation, ACN Utility Services, Inc., ACN    Energy, Inc., ACN Power, Inc., Commerce Energy Group, Inc.,    American Communications Network, Inc. and Computershare Trust    Company, Inc., previously filed with the Commission as    Exhibit 2.4 to the Company’s Current Report on    Form 8-K filed with the Commission on February 10,    2005, which is incorporated herein by reference. 10.7     Summary of Commerce Energy Group, Inc. Management Bonus Program    for 2005, previously filed with the Commission as    Exhibit 10.1 to the Company’s Current Report on    Form 8-K filed with the Commission on March 1, 2005,    which is incorporated herein by reference. 10.8     Offer Letter for Tom Ulry dated February 28, 2005,    previously filed with the Commission as Exhibit 99.1 to the    Company’s Current Report on Form 8-K filed with the    Commission on March 7, 2005, which is incorporated herein    by reference. 31.1     Principal Executive Officer Certification required by    Rule 13a-14(a) under the Securities Exchange Act of 1934. 31.2     Principal Financial Officer Certification required by    Rule 13a-14(a) under of the Securities Exchange Act of 1934.
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     **Exhibit**  **Number** **Description**    32.1     Principal Executive Officer Certification pursuant to    18 U.S.C. Section 1350, as adopted pursuant to    Section 906 of the Sarbanes-Oxley Act of 2002. 32.2     Principal Financial Officer Certification pursuant to    18 U.S.C. Section 1350, as adopted pursuant to    Section 906 of the Sarbanes-Oxley Act of 2002.
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**SIGNATURES**     Pursuant to the requirements of the Securities Exchange Act of1934, the registrant has duly caused this report to be signed onits behalf by the undersigned thereunto duly authorized. **COMMERCE ENERGY GROUP, INC.** By:     /s/ STEVEN S. BOSS   **Steven S. Boss**     Chief Executive Officer     (Principal Executive Officer) Date: October 31, 2005 By:     /s/ LAWRENCE CLAYTON, JR.   **Lawrence Clayton, Jr.**     Interim Chief Financial Officer     (Principal Financial Officer) Date: October 31, 2005
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**EXHIBIT INDEX**     **Exhibit**  **Number** **Description**    10.1     Settlement Agreement and Mutual General Release dated    December 23, 2004 by and between Commerce Energy Group,    Inc, Commonwealth Energy Corporation, Ian B. Carter, Robert C.    Perkins, Brad Gates, Joseph P. Saline, Patricia E. Saline and    Joseph Ogundiji, previously filed with the Commission as    Exhibit 10.1 to the Company’s Current Report on    Form 8-K filed with the Commission on December 27,    2004, which is incorporated herein by reference. 10.2     Commerce Energy Group, Inc. 2005 Employee Stock Purchase Plan,    previously filed with the Commission as Exhibit 10.1 to the    Company’s Current Report on Form 8-K filed with the    Commission on January 19, 2005, which is incorporated    herein by reference. 10.3     Asset Purchase Agreement dated as of February 9, 2005 by    and among Commonwealth Energy Corporation, ACN Utility Services,    Inc., ACN Energy, Inc., ACN Power, Inc. and, as to certain    sections thereof only, Commerce Energy Group, Inc. and American    Communications Network, Inc., previously filed with the    Commission as Exhibit 2.1 to the Company’s Current    Report on Form 8-K filed with the Commission on    February 10, 2005, which is incorporated herein by    reference. 10.4     Transition Services Agreement dated as of February 9, 2005    by and between American Communications Network, Inc. and    Commonwealth Energy Corporation, previously filed with the    Commission as Exhibit 2.2 to the Company’s Current    Report on Form 8-K filed with the Commission on    February 10, 2005, which is incorporated herein by    reference. 10.5     Sales Agency Agreement dated as of February 9, 2005 by and    among Commonwealth Energy Corporation, Commerce Energy Group,    Inc. and American Communications Network, Inc., previously filed    with the Commission as Exhibit 2.3 to the Company’s    Current Report on Form 8-K filed with the Commission on    February 10, 2005, which is incorporated herein by    reference. 10.6     Escrow Agreement dated as of February 9, 2005 by and among    Commonwealth Energy Corporation, ACN Utility Services, Inc., ACN    Energy, Inc., ACN Power, Inc., Commerce Energy Group, Inc.,    American Communications Network, Inc. and Computershare Trust    Company, Inc., previously filed with the Commission as    Exhibit 2.4 to the Company’s Current Report on    Form 8-K filed with the Commission on February 10,    2005, which is incorporated herein by reference. 10.7     Summary of Commerce Energy Group, Inc. Management Bonus Program    for 2005, previously filed with the Commission as    Exhibit 10.1 to the Company’s Current Report on    Form 8-K filed with the Commission on March 1, 2005,    which is incorporated herein by reference. 10.8     Offer Letter for Thomas L. Ulry dated February 28, 2005,    previously filed with the Commission as Exhibit 99.1 to the    Company’s Current Report on Form 8-K filed with the    Commission on March 7, 2005,which is incorporated herein by    reference. 31.1     Principal Executive Officer Certification required by    Rule 13a-14(a) under the Securities Exchange Act of 1934. 31.2     Principal Financial Officer Certification required by    Rule 13a-14(a) under of the Securities Exchange Act of 1934. 32.1     Principal Executive Officer Certification pursuant to    18 U.S.C. Section 1350, as adopted pursuant to    Section 906 of the Sarbanes-Oxley Act of 2002. 32.2     Principal Financial Officer Certification pursuant to    18 U.S.C. Section 1350, as adopted pursuant to    Section 906 of the Sarbanes-Oxley Act of 2002.
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