UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-Q

(Mark One)

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

For the quarterly period ended April 30, 2005

OR

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

For the transition period from ________________ to________________

Commission File Number 001-32239

COMMERCE ENERGY GROUP, INC.

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

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

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

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

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes o    No þ

As of June 10, 2005, 31,432,523 shares of the registrant’s common stock were outstanding.

COMMERCE ENERGY GROUP, INC.

Form 10-Q
For the Period Ended April 30, 2005
Index

FORWARD-LOOKING INFORMATION

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

	•	regulatory changes in the states in which we operate that could adversely affect our operations;
	•	our continued ability to obtain and maintain licenses from the states in which we operate;
	•	the competitive restructuring of retail marketing may prevent us from selling electricity and natural gas in certain states;
	•	our dependence upon a limited number of third parties to generate and supply to us electricity and natural gas;
	•	fluctuations in market prices for electricity and natural gas;
	•	a decision by electricity and natural gas utilities not to raise rates proportionately to higher electricity and natural gas costs, thereby adversely affecting our profitability;
	•	our ability to successfully integrate the businesses that we acquire;
	•	our ability to successfully enter and compete in new electricity and natural gas markets that we enter;
	•	seasonal weather or force majeure events that adversely impact electricity and natural gas supply and infrastructure could prevent us from competitively servicing customers and meeting demand requirements in each of the states where we operate;
	•	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 local electric and natural gas utilities to transmit and distribute the electricity and natural gas we sell to our customers.

     We have attempted to identify, in context, certain of the factors that we currently believe may cause actual future experience and results to differ from our current expectations regarding the relevant matter or subject area. In addition to the items specifically discussed above, our business and results of operations are subject to the risks and uncertainties described in this Report in Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and in our Annual Report on Form 10-K for the year ended July 31, 2004 which we filed with the Securities and Exchange Commission on November 15, 2004. In evaluating forward-looking statements, you should consider these risks and uncertainties, together with the other risks described from

time to time in our reports and documents filed with the Securities and Exchange Commission, and you should not place undue reliance on these statements. These forward-looking statements speak only as of the date on which the statements were made. We assume no obligation to update the forward-looking information to reflect actual results or changes in the factors affecting such forward-looking information.

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements.

COMMERCE ENERGY GROUP, INC.

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

1

COMMERCE ENERGY GROUP, INC.

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

2

COMMERCE ENERGY GROUP, INC.

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

3

COMMERCE ENERGY GROUP, INC.

1. Summary of Significant Accounting Policies

Basis of Presentation

     The condensed consolidated financial statements for the three and nine months ended April 30, 2005 include the accounts of Commerce Energy Group, Inc. (the “Company”), its three wholly-owned subsidiaries: Commerce Energy, Inc. (formerly Commonwealth Energy Corporation) doing business under the brand name electricAmerica and for the three months ended April 30, 2005 includes the recently acquired business of ACN Utility Services, Inc. and its subsidiaries (ACNU) (see Note 6), Skipping Stone Inc. (“Skipping Stone”), which was acquired on April 1, 2004, and UtiliHost, Inc. All material intercompany balances and transactions have been eliminated in consolidation.

     At April 30, 2004, the Company’s consolidated financial statements included the accounts of its controlled investment in Summit Energy Ventures, LLC (“Summit”), and its majority ownership in Power Efficiency Corporation (“PEC”). In the fourth quarter of fiscal 2004, the Company terminated its relationship with Summit and its investment in PEC decreased to 39.9% and subsequently, to 39.3% at April 30, 2005. As of July 31, 2004 and as of April 30, 2005, both entities were no longer consolidated. (See Note 4).

Preparation of Interim Condensed Consolidated Financial Statements

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

Uses of Estimates

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

Revenue Recognition

     Energy sales are recognized when the electricity and natural gas are delivered to the Company’s customers. The Company’s net revenue is comprised of the following:

4

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

     Skipping Stone revenue (which is included in retail electricity sales above), after elimination of intercompany transactions, for the three and nine months ended April 30, 2005 was $420 and $1,616, respectively, representing approximately 1% of total net revenue for both periods.

Stock-Based Compensation

     The Company accounts for its employee stock options under the recognition and measurement principles of Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees (“APB No. 25”), and related interpretations. Under APB No. 25, no stock-based employee compensation costs are reflected in net loss for the three and nine month periods ended April 30, 2005 and 2004, since all options granted under the plans had an exercise price equal to or greater than the market value of the underlying common stock on the date of grant.

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

Segment Reporting

     The Company’s chief operating decision makers consist of members of senior management who work together to allocate resources to, and assess the performance of, the Company’s business. These members of senior management currently manage the Company’s business, assess its performance, and allocate its resources as a single reportable segment, retail energy marketing, comprised of two business lines: electricity and natural gas.

     Because the revenue of the Company’s subsidiary, Skipping Stone, which the Company acquired in fiscal 2004, accounts for only approximately 1% of total net revenue (after elimination of intercompany transactions), and geographic information is immaterial, no segment information is provided.

Accounts Receivable, Net

     Accounts receivable, net, is comprised of the following:

5

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

Inventory

     Inventory represents natural gas in storage as required by state regulatory bodies and contractual obligations under customer choice programs. Inventory is stated at the lower of cost or market.

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

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

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

     For the three and nine months ended April 30, 2005 and 2004, the effects of the assumed exercise of all stock options and the assumed conversion of preferred stock into common stock are anti-dilutive; accordingly, such assumed exercises and conversions have been excluded from the calculation of net loss — diluted. If the assumed exercises or conversions had been used, the fully diluted shares outstanding for the three and nine months ended April 30, 2005 would have been 31,596 and 31,164, respectively. If the assumed exercises or conversions had been used, the fully diluted shares outstanding for the three and nine months ended April 30, 2004 would have been 29,020 and 29,602, respectively.

3. Market and Regulatory

     The Company considers each utility service territory within which it operates to be a distinct market due to the unique characteristics of each.

Electricity

California

6

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

     On April 1, 1998, the Company began supplying customers in California with electricity as an Electric Service Provider (“ESP”).

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

     Currently, several important issues are under review at the CPUC, a Resource Adequacy Requirement and a Renewable Portfolio Standard. Additional costs to serve customers in California are anticipated from these proceedings, however, the CPUC decisions will determine the distribution of those costs across all load serving entities and ultimately the Company’s financial impact.

Pennsylvania

     The Company began serving customers in Pennsylvania in 1999. There are no current rate cases or filings in this state that are anticipated to impact the Company’s financial results.

Michigan

     The Company began marketing in Michigan’s Detroit Edison (“DTE”) service territory in September 2002. There are no current rate cases or filings in this state that are anticipated to impact the Company’s financial results.

New Jersey

     The Company began marketing in New Jersey in the Public Service Electric and Gas service territory in December 2003. There are no current rate cases or filings in this state that are anticipated to impact the Company’s financial results.

Texas

     In February 2005, with the acquisition of ACNU’s operations, the Company began serving electric customers in the TXU and CenterPoint market areas of the Electric Reliability Council of Texas (“ERCOT”). On May 16, 2005, the Company expanded further into the Texas markets of American Electric Power and Texas New Mexico Power.

Natural Gas

     Through the acquisition of ACNU’s operations, the Company now serves natural gas customers in eight utility gas market areas in six states.

California

     The Company currently serves residential and small commercial customers in the Southern California Gas and Pacific Gas & Electric gas markets, which serve most of the state. The Company is the only alternate natural gas provider to residential customers in these market areas. There are no current rate cases or filings pending before the California Public Utility Commission that are anticipated to impact the Company’s financial results.

Georgia

     The Company currently serves natural gas to residential and small commercial customers in Georgia in the Atlanta Gas Light market. There are no current rate cases or filings pending before the Georgia Public Service Commission that are anticipated to impact the Company’s financial results.

7

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

     The ability to disconnect customers for non-payment of invoices is severely constrained by system design and human resource limitations in this market. This may affect the Company’s ability to timely control credit losses within this market.

Maryland

     The Company provides natural gas service to residential and small commercial customers in the Baltimore Gas & Electric market area.

     The Maryland Public Service Commission plans to consider adopting enhanced customer protection rules later this year which will be applied to the retail energy market. It is not anticipated that the approval of these rules will impact the Company’s financial results.

New York

     The Company currently serves residential and small commercial customers in the Keyspan Energy Delivery natural gas market and is one of several gas marketers that serve these types of customers.

     In August 2004, the New York State Public Service Commission (“NY PSC”) issued a statement of policy on advancing competition in retail energy markets. The NY PSC ordered that all utilities shall prepare plans to foster the development of retail energy market competition in collaboration with its staff and other interested parties. This order is anticipated to have no impact on the Company’s financial results.

Ohio

     The Company provides natural gas service to residential and small commercial customers in the Dominion East Ohio (“DEO”) and Columbia Gas of Ohio service areas.

     In December 2004, DEO notified the Public Utilities Commission of Ohio (“PUCO”) of its desire to exit the commodity market. Its goal is to become a distribution-only company by the end of 2006. Nearly 60 percent of DEO’s customers currently participate in customer choice. In April 2005, DEO filed with the PUCO to embark upon its plan. The ultimate outcome of this filing is unknown; however, it is not anticipated to adversely impact the Company’s financial results.

Pennsylvania

     The Company provides natural gas service to residential and small commercial consumers in the Philadelphia Electric Company service area in Pennsylvania.

     In May 2004, the Pennsylvania Public Utility Commission (“PUC”) undertook an evaluation of the competitiveness of natural gas supply services in the state. If the PUC determines the market is not sufficiently competitive, further actions will be considered. The Company is the only natural gas provider to residential customers in this market. The potential impact of this evaluation to the Company’s operations is unknown at this time.

4. Investments

     The Company has three investments in early-stage, energy related entities incurring operating losses, which are expected to continue, at least in the near term: Encorp, Inc. (“Encorp”), Turbocor B.V. (“Turbocor”) and Power Efficiency Corporation (“PEC”). Each company has very limited working capital and as a result, continuing operations will be dependent upon their securing additional financing to meet their respective immediate capital needs. The Company has no obligation, and currently no intention to invest additional funds into these companies.

     At April 30, 2005, these investments are carried at a nominal value in goodwill, intangibles and other assets.

8

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

5. Contingencies

Employment Settlements

     On April 21, 2005, the Company entered into a settlement agreement with a director and the former Chief Executive Officer, Ian B. Carter. The settlement agreement provides for payments to Mr. Carter totaling $3,100. In addition, Mr. Carter will retain an option to purchase 2,500 shares of the Company’s common stock at $2.50 per share. Under the settlement agreement, Mr. Carter and the Company agreed to mutual general releases of all claims that the parties may have against each other and Mr. Carter agreed to relinquish any stock options he has been granted, or claims to have been granted, in excess of the 2,500 stock options. The Company had previously recorded a $3,000 reserve for this employment settlement in January 2005. Mr. Carter remains as a director of the Company.

Regulatory Proceedings

     The Company is a party to a number of Federal Energy Regulatory Commission (“FERC”) and California independent system operator proceedings related to the California Energy Crisis of 2000 and 2001. The FERC and other regulatory and judicial bodies continue to examine the behavior of market participants during this energy crisis and may recalculate what market clearing prices should have or might have been under alternative scenarios of behavior by market participants. In the event the historical costs of market operations were to be reallocated among market participants, the Company can not predict whether the results would be favorable or unfavorable for the Company, nor can it predict the amount of any such adjustments.

Litigation

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

6. Acquisition

     On February 9, 2005, the Company acquired certain assets of ACN Utility Services, Inc. (ACNU), a subsidiary of American Communications Network, Inc. (the Parent), and its retail electricity and natural gas sales business. ACNU sells retail electricity in Texas and Pennsylvania and sells retail natural gas in California, Georgia, Maryland, New York, Ohio and Pennsylvania. The aggregate purchase price was $14,525 in cash and 930,233 shares of the Company common stock, valued at $2,000. In addition, as part of the initial purchase price, the Company was required to fund $2,542 of collateralized letters of credit on the closing date to guarantee our performance to various third parties. The common stock payment is contingent upon meeting certain sales requirements and have been placed in an escrow account. The purchase was accounted for under the purchase method of accounting and resulted in a preliminary estimate of $8,500 of goodwill, including the contingent equity, and other intangible assets, subject to a final purchase price adjustments and settlements to be completed by fiscal year-end.

     The assets acquired include natural gas inventory associated with utility and pipeline storage and transportation agreements and natural gas and electricity supply, scheduling and capacity contracts, software and other infrastructure plus approximately 82,000 natural gas and electricity residential and small commercial customers. Cash, accounts receivable, certain prepaid expenses and other asset were not acquired in the transaction. In addition, none of ACNU’s liabilities were assumed. The assets purchased and the operating results generated from the acquisition have been included in the Company’s operations as of February 1, 2005, since the acquisition agreement stated that the transaction was effective as of February 1, 2005.

9

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

     The Company is operating as an agent of ACNU under the acquisition agreement during the transition of ACNU’s regulatory licenses to the Company, which the Company believes is proceeding as rapidly as regulatory rules allow.

     The following selected unaudited pro forma financial data for the three and nine months ended April 30, 2005 and 2004 reflects the Company’s consolidated results of operations as if the acquisition of the energy business of ACNU had taken place at the beginning of the respective periods. The pro forma information includes primarily adjustments for estimated amortization of intangible assets resulting from the acquisition, removal of depreciation expense related to property, plant and equipment not purchased, removal of interest expense paid to ACNU, reduction of interest income for the Company’s invested cash used to fund the acquisition, and removal of ACNU’s tax benefit from income taxes. The pro forma financial information is presented for informational purposes only and may not necessarily be indicative of the results of operations as they would have been had the transaction been effected on the assumed date.

7. Derivative Financial Instruments

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

     Supplying electricity and natural gas to retail customers requires the Company to match customers’ projected demand with long term and short term commodity purchases. The Company primarily uses derivative instruments to minimize significant, unanticipated earnings fluctuations caused by commodity price volatility. The Company purchases substantially all of its power under long-term forward physical delivery contracts for supply to its retail electricity customers. Electricity supply contracts are commodity derivative contracts under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”. Using the exemption available for qualifying electricity contracts under SFAS No. 133, the Company applies the normal purchase, normal sale accounting treatment to its forward purchase supply contracts. Accordingly, the Company records revenue generated from customer sales as energy is delivered to its retail customers, and direct energy costs are recorded when the energy under its long-term forward physical delivery contracts is delivered. In January 2005, the Company sold electricity commodity supply contracts back to the original supplier in connection with a strategic realignment of its customer portfolio in the Pennsylvania electricity market, which resulted in a gain in the second fiscal quarter of 2005. As a result of that sale, the normal purchase and sale exemption for the Pennsylvania market is no longer available for that market. Accordingly, the Company has applied mark-to-market accounting on any electricity supply contracts

10

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

entered into after the January 28, 2005 date but not yet delivered as of April 30, 2005. This amount is reported as a component of other comprehensive income (loss) at April 30, 2005. In the first, second and third quarters of fiscal 2005, the Company also employed financial hedges using derivative instruments to hedge its commodity price risks. During this same period in fiscal 2005, certain forward fixed price purchases and swap agreements were designated as cash flow hedges resulting in changes in the hedge value being recorded as other comprehensive income (loss). To the extent that the hedges are not effective, the ineffective portion of the changes in fair market value is recorded currently in direct energy costs. The Company intends to continue to use derivative instruments as an efficient way of assisting in managing its price and volume risk in energy supply procurement for its retail customers. Certain derivative instrument treatment may not qualify for hedge treatment and require mark-to-market accounting in accordance with SFAS No. 133. The Company also entered into transactions that did not qualify as accounting hedges but were designed to reduce its direct energy costs or protect margin. In such cases, the changes in the fair value of these transactions are recorded in earnings as a component of direct energy costs. The Company does not engage in trading activities in the wholesale energy market other than to manage its direct energy cost.

     The amounts recorded in other comprehensive income (loss) at April 30, 2005 related to cash flow hedges are summarized in the following table:

8. Quarterly Financial Information (Unaudited)

     In January 2005, the Company announced a strategic realignment of its customer portfolio in the Pennsylvania electricity market and the discontinuation of service to certain classes of residential and small commercial customers. In connection with this decision, the Company sold electricity commodity supply contracts, which were deemed excess based on the realignment plan, back to the original supplier and recorded a gain on the sale of the contracts of $9,301 in the second quarter of fiscal 2005. As a result of timing and forecasting issues related to realigning the portfolio, the Company had unforeseen transitional supply obligations which could have been served more cost effectively with the original supply contracts rather than with the market cost of the replacement power which was subsequently purchased. As a result, the Company is restating the second quarter gain from $9,301 to $7,201, to account for the higher replacement cost of power incurred in the third quarter of fiscal 2005 and estimated in the fourth quarter of fiscal 2005 compared to the cost that would have been incurred under the original supply contracts, as reflected below.

9. Related Party Transactions

     The Company purchases natural gas from several suppliers, including Cook Inlet Energy Supply LLC (“Cook Inlet”). Gregory L. Craig is the chief executive officer and a substantial shareholder of Cook Inlet and was

11

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

appointed to the Company’s Board of Directors as a Class I director in November 2004. For the three months ended April 30, 2005, the Company purchased $5,911 of natural gas from Cook Inlet, 10% of the Company’s total direct energy costs. The Company believes that the natural gas was purchased on terms comparable to those available from unaffiliated suppliers. The Company’s natural gas business was acquired in February 2005 and the supply arrangement with Cook Inlet existed at the time of the acquisition.

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

Overview

     We are a diversified independent energy marketer of electricity and natural gas. We were founded in 1997 as a retail electricity marketer in California, and have grown to serve 16 utility markets in nine states for electricity and natural gas, and in some cases both. Growth has occurred by a combination of organic means and acquisitions. In the past twelve months, we acquired Skipping Stone Inc., or Skipping Stone, an energy consulting company, and ACN Utility Services, Inc., or ACNU, a market energy retailer of natural gas and electricity.

     We provide electricity to our residential, commercial, industrial and institutional customers in California, Pennsylvania, Michigan, New Jersey, and Texas. We are licensed by the Federal Energy Regulatory Commission, or FERC, as a power marketer. We are also licensed to supply retail electricity by applicable state agencies in New York, Maryland, Ohio and Virginia. We sell natural gas to our residential and small commercial customers in California, Georgia, Maryland, New York, Ohio and Pennsylvania. We also provide consulting and outsourced energy transaction services to utilities, energy merchants and asset owners through Skipping Stone Inc., or Skipping Stone. Unless otherwise noted, as used herein, “the Company,” “we,” “us,” and “our” mean Commerce Energy Group, Inc. and its three wholly-owned subsidiaries: Commerce Energy Inc. (formerly Commonwealth Energy Corporation, doing business under the brand name electricAmerica), Skipping Stone and UtiliHost, Inc.

     As of April 30, 2005, we delivered electricity to approximately 88,000 customers in California, Pennsylvania, Michigan, New Jersey, and Texas; and natural gas to approximately 62,000 customers in the California, Georgia, Maryland, New York, Ohio and Pennsylvania customers which we recently acquired in connection with the transaction with ACN Utility Services, Inc., or ACNU, in February 2005, described under the caption “Acquisitions”. The potential growth of this business depends upon a number of factors including the degree of deregulation in each state, the availability of energy at competitive prices and credit terms, and our ability to acquire new retail and commercial customers.

     Our core business is the retail sale of electricity and natural gas to end-use customers. All of the energy we sell to our customers is purchased from third-party power generators and natural gas suppliers under long-term contracts and in the spot market. We do not own electricity generation facilities, natural gas producing properties or pipelines. The electricity and natural gas we sell is generally metered and delivered to our customers by local utilities. The local utilities also provide billing and collection services for many of our customers on our behalf. To facilitate load shaping for our electricity customers and balancing activities for our retail natural gas customer portfolio, we also buy and sell surplus electricity and natural gas from and to other market participants when necessary. We store our natural gas inventory in independently-owned third party storage facilities.

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

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

13

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

Acquisitions

     In the past twelve months, we acquired Skipping Stone, an energy industry consulting company, and we acquired certain assets of ACNU, a energy marketer of retail natural gas and electricity.

     Skipping Stone, which we acquired in April 2004, provides energy-related consulting and technologies to utilities, electricity generators, natural gas pipelines, wholesale energy merchants, energy technology providers and financial institutions. Skipping Stone’s revenue (after elimination of intercompany transactions) was approximately 1% of our consolidated net revenue for the three and nine months ended April 30, 2005.

     On February 9, 2005, we acquired certain assets of ACNU, a subsidiary of American Communications Network, Inc., or the Parent, and its retail electricity and natural gas sales business. ACNU sells retail electricity in Texas and Pennsylvania and sells retail natural gas in California, Georgia, Maryland, New York, Ohio and Pennsylvania.

     In addition to the acquisition, we have entered into a sales agency agreement with the Parent whereby the Parent’s extensive direct sales force will continue to sell energy products for us. This arrangement expands our existing sales force enabling customer acquisition in mass markets, small businesses and commercial and industrial markets.

     The assets acquired include natural gas inventory associated with utility and pipeline storage and transportation agreements and natural gas and electricity supply, scheduling and capacity contracts, software and other infrastructure plus approximately 82,000 natural gas and electricity residential and small commercial customers. Cash, accounts receivable, certain prepaid expenses and other asset were not acquired in the transaction. In addition, none of ACNU’s liabilities were assumed. The assets purchased and the operating results generated from the acquisition have been included in our operations as of February 1, 2005, since the acquisition agreement stated that the transaction was effective as of February 1, 2005.

     We are operating as an agent of ACNU under the acquisition agreement during the transition of ACNU’s regulatory licenses to us, which we believe is proceeding as rapidly as regulatory rules allow.

Summit Energy Ventures

     In fiscal 2004, we consolidated Summit Energy Ventures, or Summit, and its majority interest in Power Efficiency Corporation, or PEC, into our financial results. In the third fiscal quarter of 2004, we terminated our relationship with Summit. We no longer consolidate Summit and PEC in our current fiscal year financial results as we retained a 39.9% interest in PEC. At April 30, 2005, our ownership interest was diluted to 36.3% as a result of an equity linked financing by PEC. We currently account for our investment in PEC under the equity method of accounting, however, as we have no investment basis in PEC, further losses are not being recognized in our consolidated financial statements.

Market and Regulatory

     We consider each utility service territory within which we operates to be a distinct market due to the unique characteristics of each.

Electricity

California

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     On April 1, 1998, we began supplying customers in California with electricity as an Electric Service Provider, or ESP.

     The California Public Utility Commission, or CPUC, issued a ruling on September 20, 2001 suspending the right of direct access, which allowed electricity customers to buy their power from a supplier other than the electric utilities. The suspension permitted us to keep current customers and to solicit DA customers served by other providers, but prohibited us from soliciting new non-DA customers for an indefinite period of time.

     Currently, several important issues are under review at the CPUC, a Resource Adequacy Requirement and a Renewable Portfolio Standard. Additional costs to serve customers in California are anticipated from these proceedings, however, the CPUC decisions will determine the distribution of those costs across all load serving entities and ultimately our financial impact.

Pennsylvania

     We began serving customers in Pennsylvania in 1999. There are no current rate cases or filings in this state that are anticipated to impact our financial results.

Michigan

     We began marketing in Michigan’s Detroit Edison, or DTE, service territory in September 2002. There are no current rate cases or filings in this state that are anticipated to impact our financial results.

New Jersey

     We began marketing in New Jersey in the Public Service Electric and Gas service territory in December 2003. There are no current rate cases or filings in this state that are anticipated to impact our financial results.

Texas

     In February 2005, with the acquisition of ACNU’s operations, we began serving electric customers in the TXU and CenterPoint market areas of the Electric Reliability Council of Texas, or ERCOT. On May 16, 2005, we expanded further into the Texas markets of American Electric Power and Texas New Mexico Power.

Natural Gas

     Through the acquisition of ACNU’s operations in February 2005, we now serve natural gas customers in eight utility gas market areas in six states.

California

     We currently serve residential and small commercial customers in the Southern California Gas and Pacific Gas & Electric gas markets, which serve most of the state. We are the only alternate natural gas provider to residential customers in these market areas. There are no current rate cases or filings pending before the California Public Utility Commission that are anticipated to impact our financial results.

Georgia

     We currently serve natural gas to residential and small commercial customers in Georgia in the Atlanta Gas Light market. There are no current rate cases or filings pending before the Georgia Public Service Commission that are anticipated to impact our financial results.

     The ability to disconnect customers for non-payment of invoices is severely constrained by system design and human resource limitations in this market. This may affect our ability to timely control credit losses within this market.

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Maryland

     We provide natural gas service to residential and small commercial customers in the Baltimore Gas & Electric market area.

     The Maryland Public Service Commission plans to consider adopting enhanced customer protection rules later this year which will be applied to the retail energy market. It is not anticipated that the approval of these rules will impact our financial results.

New York

     We currently serves residential and small commercial customers in the Keyspan Energy Delivery natural gas market and is one of several natural gas marketers that serve these types of customers.

     In August 2004, the New York State Public Service Commission, or NY PSC, issued a statement of policy on advancing competition in retail energy markets. The NY PSC ordered that all utilities shall prepare plans to foster the development of retail energy market competition in collaboration with its staff and other interested parties. This order is anticipated to have no impact on our financial results.

Ohio

     We provide natural gas service to residential and small commercial customers in the Dominion East Ohio, or DEO, and Columbia Gas of Ohio service areas.

     In December 2004, DEO notified the Public Utilities Commission of Ohio, or PUCO, of its desire to exit the commodity market. Its goal is to become a distribution-only company by the end of 2006. Nearly 60 percent of DEO’s customers currently participate in customer choice. In April 2005, DEO filed with the PUCO to embark upon its plan. The ultimate outcome of this filing is unknown; however, it is not anticipated to adversely impact our financial results.

Pennsylvania

     We provide natural gas service to residential and small commercial consumers in the Philadephia Electric Company service area in Pennsylvania.

     In May 2004, the Pennsylvania Public Utility Commission, or PUC, undertook an evaluation of the competitiveness of natural gas supply services in the state. If the PUC determines the market is not sufficiently competitive, further actions will be considered. We are the only natural gas provider to residential customers in this market. The potential impact of this evaluation to our operations is unknown at this time.

Critical Accounting Policies and Estimates

     The following discussion and analysis of our financial condition and operating results are based on our consolidated financial statements. The preparation of this Form 10-Q requires us to make estimates and assumptions that affect the reported amount of assets and liabilities, disclosure of contingent assets and liabilities at the date of our financial statements, and the reported amount of revenue and expenses during the reporting period. Actual results may differ from those estimates and assumptions. In preparing our financial statements and accounting for the underlying transactions and balances, we apply our accounting policies as disclosed in our notes to the condensed consolidated financial statements. The accounting policies discussed below are those that we consider to be critical to an understanding of our financial statements because their application places the most significant demands on our ability to judge the effect of inherently uncertain matters on our financial results. For all of these policies, we caution that future events rarely develop exactly as forecast, and the best estimates routinely require adjustment.

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Accounting for derivative instruments and hedging activities — 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. Electricity supply contracts are commodity derivative contracts under Statement of Financial Accounting Standard, or SFAS, No. 133, “Accounting for Derivative Instruments and Hedging Activities”. Using the exemption available for qualifying electricity contracts under SFAS No. 133, we apply the normal purchase, normal sale accounting treatment to our forward purchase supply contracts. Accordingly, we record revenue generated from customer sales 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 January 2005, we sold electricity commodity supply contracts back to the original supplier in connection with a strategic realignment of our customer portfolio in the Pennsylvania electricity market, which resulted in a gain in the second fiscal quarter of 2005. As a result of that sale, the normal purchase and sale exemption for the Pennsylvania market is no longer available for that market. Accordingly, we have applied mark-to-market accounting on any electricity supply contracts entered into after the January 28, 2005 date but not yet delivered as of April 30, 2005. This amount is reported as a component of other comprehensive income (loss) at April 30, 2005. In the first, second and third quarters of fiscal 2005, we also employed financial hedges using derivative instruments, to hedge our commodity price risks. During this same period in fiscal 2005, certain forward fixed price purchases and swap agreements were designated as cash flow hedges resulting in changes in the hedge value being recorded as other comprehensive income (loss). To the extent that the hedges are not effective, the ineffective portion of the changes in fair market value is recorded currently in direct energy costs. We intend to continue to use derivative instruments as an efficient way of assisting in managing our price and volume risk in energy supply procurement for our retail customers. Certain derivative instrument treatment may not qualify for hedge treatment and require mark-to-market accounting in accordance with SFAS No. 133.

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Independent system operator costs — Included in direct energy costs, along with electricity 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.

•	Transportation and delivery costs — Included in direct energy costs, along with natural gas that we purchase, are interstate pipeline costs and utility service charges. These fees are identified in the month incurred and settled in the following month.

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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.

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Unbilled receivables — Our customers are billed monthly throughout the month on a sequential basis or on a meter read cycle. Unbilled receivables represent the amount of electricity and natural gas 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 or dekatherms delivered, but not yet billed, multiplied by the current customer average sales price per kilowatt-hour or dekatherms as applicable.

•	Inventory —Inventory represents natural gas in storage as required by state regulatory bodies and contractual obligations under customer choice programs. Inventory is stated at the lower of cost or market.

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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.

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Results of Operations

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

     In January 2005, we announced a strategic realignment of our customer portfolio in the Pennsylvania electricity market and the discontinuation of service to certain classes of residential and small commercial customers. In connection with this decision, we sold electricity commodity supply contracts, which were deemed excess based on the realignment plan, back to the original supplier and recorded a gain on the sale of the contracts of $9,301 in the second quarter of fiscal 2005. As a result of timing and forecasting issues related to realigning the portfolio, we had unforeseen transitional supply obligations which could have been served more cost effectively with the original supply contracts rather than with the market cost of the replacement power which was subsequently purchased. As a result, we are restating the second quarter gain from $9,301 to $7,201, to account for the higher replacement cost of power incurred in the third quarter of fiscal 2005 and estimated to be incurred in the fourth quarter of fiscal 2005 compared to the cost that would have been incurred under the original supply contracts.

Three months ended April 30, 2005 compared to three months ended April 30, 2004.

     Net revenue of $68.5 million increased by $20.0 million, or 41%, for the three months ended April 30, 2005 compared to the three months ended April 30, 2004. Gross profit increased $2.3 million to $8.0 million for the three months ended April 30, 2005 compared to $5.7 million for the same prior year period. The gross profit increase in the three months ended April 30, 2005 was primarily due to the newly acquired ACNU business, which contributed $4.2 million of gross profit. The gross profit increase was offset by an overall increase in energy costs, which are influenced by energy commodities, including natural gas and oil, in the national and international markets. Our operating results for the three months ended April 30, 2005 included a loss from operations of $1.2 million compared to a loss of $3.5 million for the same prior year period.

Net revenue

Retail electricity sales

     Retail electricity sales decreased $2.1 million, or 5%, to $44.8 million in the three months ended April 30, 2005 compared to $46.9 million in the same period in the prior fiscal year. The decrease resulted primarily from decreased energy sales across all markets, primarily in California of $3.3 million, in Pennsylvania of $1.5 million, and in Michigan of $2.7 million due to customer attrition compared to the prior year period. This decrease was offset by the newly acquired ACNU business which contributed $5.4 million in electricity sales for the three months ended April 30, 2005. We sold 621 million kilowatt hours, or kWh, at an average retail price per kWh of $0.071 in the three months ended April 30, 2005, as compared to 713 million kWh sold at an average retail price per kWh of $0.065 in the same period in the prior fiscal year.

Natural gas sales

     We acquired our natural gas business in six markets in February 2005. In the three months ended April 30, 2005, natural gas sales were $18.0 million. We sold 1,826 million dekatherms, or DTH, in the three months ended April 30, 2005 at an average price of $9.87 per DTH. The primary markets that contributed to these sales were in Ohio of $8.6 million, in California of $4.4 million, and in Georgia of $3.0 million.

Excess energy sales

     Excess energy sales increased $4.0 million to $5.7 million in the three months ended April 30, 2005 compared to $1.7 million in the same period in the prior year. The increase is attributable to the sale of excess electricity for Pennsylvania operations of $2.6 million and for California operations of $1.4 million compared to the prior fiscal third quarter.

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

Direct energy costs

     Direct energy costs, which are recognized concurrently with related energy sales, include the aggregated cost of purchased electricity and natural gas, fees incurred from various energy-related service providers and energy-related taxes that cannot be passed directly through to the customer. Beginning in February 2005, direct energy costs also include transportation and delivery costs for interstate pipeline costs and utility service charges for natural gas.

Electricity costs

     Our direct energy costs related to electricity increased to $45.7 million for the three months ended April 30, 2005, an increase of $2.9 million, or 7%, from $42.8 million for the three months ended April 30, 2004. This increase is primarily due to our newly acquired ACNU business which contributed $4.5 million in direct energy costs. This increase was also attributable to an increase in the average cost per kWh of $0.064 for the three months ended April 30, 2005, as compared to an average cost per kWh of $0.057 for the three months ended April 30, 2004.

Natural gas costs

     Our direct energy costs related to natural gas for the three months ended April 30, 2005 was $14.7 million at an average cost of $8.07 per DTH.

Customers

     At April 30, 2005, we had approximately 150,000 electricity and natural gas customers compared to 105,000 customers at April 30, 2004. In February 2005, we acquired 18,000 electricity and 64,000 natural gas customers with the newly acquired ACNU business. The decrease, excluding the acquired customers, was primarily due to customer attrition, including the effects of our strategic realignment of our Pennsylvania customer portfolio.

Selling and marketing expenses

     Our selling and marketing expenses decreased slightly by $0.1 million, or 8%, to $1.1 million for the three months ended April 30, 2005, as compared to $1.2 million for the three months ended April 30, 2004. The decrease was primarily due to lower advertising costs in the current fiscal quarter.

General and administrative expenses

     Our general and administrative expenses increased $1.2 million, or 16%, to $8.2 million for the three months ended April 30, 2005 compared to $7.0 million in the three months ended April 30, 2004. The increase in the current fiscal year was primarily attributed to additional general and administrative expenses of $3.1 million related to the newly acquired ACNU business, offset by approximately $2.0 million of decreases at the Company in general and administrative expenses in the current three month period.

Reorganization and initial public listing expenses

     We incurred $1.0 million in the third quarter of fiscal 2004 of costs related to our reorganization into a Delaware holding company structure and the initial public listing of our common stock on the American Stock Exchange. Management believed it was appropriate to classify these costs as a separately identified selling, general and administrative expense category, and included expenses such as legal, accounting, auditing, consulting, and printing and reproduction fees that were specific to these activities. We incurred no such expenses in fiscal 2005.

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Initial formation litigation expenses

     In the three months ended April 30, 2004, we incurred $0.4 million of initial formation litigation costs related to Commonwealth Energy Corporation’s formation compared to no such costs during the three months ended April 30, 2005. Initial formation litigation expenses include legal and litigation costs associated with the initial capital raising efforts by former Commonwealth Energy Corporation employees, various board member matters, and the legal complications arising from those activities.

Provision for impairment on investments

     In the three months ended April 30, 2004, we recorded an additional impairment of $1.8 million on our investments, to reflect the reduction of the remaining investment basis in Turbocor, BV, or Turbocor, to zero. In fiscal 2005, we incurred no such provision.

Provision for termination of Summit

     In the three months ended April 30, 2004, we recorded a provision for the termination of Summit of $1.9 million, which also reflected a reduction of our ownership interest to 39.9% in Power Efficiency Corporation, or PEC. In fiscal 2005, we incurred no such provision.

Minority interest share of loss

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

Benefit from income taxes

     No provision for, or benefit from, income taxes was recorded for the three months ended April 30, 2005; as compared to the benefit from income taxes of $1.6 million for the three months ended April 30, 2004. In fiscal 2005, we established a valuation allowance equal to our calculated tax benefit because we believed it was not certain that we would realize these tax benefits in the foreseeable future. The current period results are not sufficient to modify this conclusion.

Nine months ended April 30, 2005 compared to nine months ended April 30, 2004.

     Net revenue of $188.0 million increased by $34.0 million, or 22%, for the nine months ended April 30, 2005 compared to the nine months ended April 30, 2004. Gross profit increased $10.9 million, or 82%, to $24.2 million for the nine months ended April 30, 2005 compared to $13.3 million for the same prior year period. The gross profit increase in the nine months ended April 30, 2005 was primarily due to the newly acquired ACNU business, which contributed $4.2 million of gross profit and the sale of the electricity commodity supply contracts related to Pennsylvania market of $7.2 million. Our operating results for the nine months ended April 30, 2005 included loss from operations of $1.9 million compared to a loss of $10.4 million for the same prior year period.

Net revenue

Retail electricity sales

     Retail electricity sales decreased $6.7 million, or 5%, to $142.3 million in the nine months ended April 30, 2005 compared to $149.0 million in the same period in the prior fiscal year. The decrease resulted primarily from customer attrition compared to the prior year period, offset by electricity sales of $5.4 million contributed from the newly acquired ACNU business. We sold 2,077 million kWh at an average retail price per kWh of $0.068 in the nine months ended April 30, 2005, as compared to 2,270 million kWh sold at an average retail price per kWh of $0.065 in the nine months ended April 30, 2004. The markets that contributed were primarily a decrease in

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California of $11.7 million and Pennsylvania of $6.1 million, offset by increased electricity sales in Michigan of $3.0 million.

Natural gas sales

     In February 2005, we acquired our natural gas business, therefore, the three months and the nine months sales are the same at $18.0 million.

Excess energy sales

     Excess energy sales increased $22.8 million to $27.7 million in the nine months ended April 30, 2005 compared to $4.9 million in the same period in the prior year. The increase is attributable to the $9.3 million sale in January 2005 of electricity supply contracts in Pennsylvania and the sale of excess electricity for Pennsylvania operations of $7.8 million and for California operations of $5.7 million compared to the same period in the prior year.

Direct energy costs

Electricity costs

     Our direct energy costs related to electricity increased to $149.2 million for the nine months ended April 30, 2005, an increase of $8.5 million, or 6%, from $140.7 million for the nine months ended April 30, 2004. This increase is primarily due to our newly acquired ACNU business which contributed $4.5 million in direct energy costs for electricity and was acquired at the beginning of the third quarter of fiscal 2005. The remaining increase was due to overall increases in energy costs. Our average cost per kWh was $.062 for the nine months ended April 30, 2005, as compared to $0.059 in the nine months ended April 30, 2004.

Natural gas costs

     In February 2005, we acquired our natural gas business, therefore, our direct energy costs related to natural gas for the three and nine months ended April 30, 2005 were the same at $14.7 million.

Selling and marketing expenses

     Our selling and marketing expenses decreased by $0.3 million, or 10%, to $2.8 million for the nine months ended April 30, 2005, as compared to $3.1 million for the nine months ended April 30, 2004. The decrease was primarily due to lower advertising costs in the current fiscal year.

General and administrative expenses

     Our general and administrative expenses increased $4.4 million, or 23%, to $23.2 million for the nine months ended April 30, 2005 compared to $18.8 million in the nine months ended April 30, 2004. The increase in the current fiscal year was primarily attributed to $3.6 million employment related settlement payments and additional general and administrative expenses related to the newly acquired ACNU business, offset by $1.7 million in the prior fiscal nine month period for severance to former executives.

Reorganization and initial public listing expenses

     We incurred $1.8 million in the nine months ended April 30, 2004 of costs related to our reorganization into a Delaware holding company structure and the initial public listing of our common stock on the American Stock Exchange. We incurred no such expenses in fiscal 2005.

Initial formation litigation expenses

     In the nine months ended April 30, 2005, we incurred $1.6 million of initial formation litigation costs related to Commonwealth Energy Corporation’s formation compared to $1.0 million during the nine months ended April 30, 2004. Initial formation litigation expenses include legal and litigation costs associated with the initial capital raising

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efforts by former Commonwealth Energy Corporation employees, various board member matters, and the legal complications arising from those activities.

Provision for impairment on investments

     In the nine months ended April 30, 2004, we recorded an impairment of $6.1 million on our investments, to reflect our percentage ownership in the net equity of each of Summit’s investments for Turbocor and Envenergy, Inc. In fiscal 2005, we incurred no such provision.

Minority interest share of loss

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

Benefit from income taxes

     No provision for, or benefit from, income taxes was recorded for the nine months ended April 30, 2005; as compared to the benefit from income taxes of $3.4 million for the nine months ended April 30, 2004. In fiscal 2005, we established a valuation allowance equal to our calculated tax benefit because we believed it was not certain that we would realize these tax benefits in the foreseeable future. The current period results are not sufficient to modify this conclusion.

Liquidity and Capital Resources

     As of April 30, 2005, our unrestricted cash and cash equivalents were $36.1 million, compared to $54.1 million at July 31, 2004 and our restricted cash and cash equivalents were $8.4 million, compared to $4.0 million at July 31, 2004. In addition to restricted cash, we also had cash deposits of $9.4 million at April 30, 2005, compared to $5.4 million at July 31, 2004. Our principal sources of liquidity to fund ongoing operations were cash provided by operations and existing cash and cash equivalents.

     Cash flow used in operations for the nine months ended April 30, 2005 was $0.7 million, compared to cash flow used in operations of $0.3 million in the nine months ended April 30, 2004. In the nine months ended April 30, 2005, cash was used primarily by decreases in accounts payable of $11.0 million, accounts receivable of $1.2 million and prepaid expenses and other assets of $4.4 million, offset by working capital used for the newly acquired ACNU business.

     Cash flow used in investing activities for the nine months ended April 30, 2005 was $15.2 million compared to $0.9 million for the nine months ended April 30, 2004. Cash used in investments was primarily for the purchase of the ACNU business in the current fiscal year.

     Cash flow used in financing activities for the nine months ended April 30, 2005 was $2.1 million, compared to cash flow provided by financing activities of $14.3 million in the nine months ended April 30, 2004. In the current fiscal year, cash flow used was primarily for the cancellation of common stock in connection with a shareholder settlement and increased restricted cash primarily for an increase required in letters of credit in New Jersey and Pennsylvania. In the prior fiscal year, restricted cash decreased primarily due to the cancellation of the required security for an appeals bond of $4.1 million related to a settled litigation and the $7.8 million net reduction of the required letters of credit secured by cash related to energy suppliers.

     We do not have open lines of credit for direct unsecured borrowings or letters of credit. Credit terms from our suppliers of electricity often require us to post collateral against our energy purchases and against our mark-to-market exposure with certain of our suppliers. We currently finance these collateral obligations with our available cash. If we are required to post such additional security, a portion of our cash would become restricted, which could adversely affect our liquidity. As of April 30, 2005, we had $8.4 million in restricted cash to secure letters of credit required by our suppliers and $9.1 million in deposits pledged as collateral in connection with energy purchase agreements.

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

Planned Capital Expenditures

     Our Board of Directors recently approved a $2.0 million budget for systems infrastructure upgrades. At April 30, 2005, $0.4 million of capital expenditures had been spent related to these system upgrades. The majority of these system upgrades will be purchased and implemented in calendar year 2005.

Contractual Obligations

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

     In January 2005, we announced a strategic realignment of our customer portfolio in the Pennsylvania electricity market and the discontinuation of service to certain classes of residential and small commercial customers. In connection with this decision, we sold electricity commodity supply contracts, which were deemed excess based on the realignment plan, back to the original supplier and recorded a gain on the sale of the contracts of $9.3 million in the second quarter of fiscal 2005. As a result of timing and forecasting issues related to realigning the portfolio, we had unforeseen transitional supply obligations which could have been served more cost effectively with the original supply contracts rather than with the market cost of the replacement power which was subsequently purchased. As a result, we are restating the second quarter gain from $9.3 million to $7.2 million, to account for the higher replacement cost of power incurred in the third quarter of fiscal 2005 and estimated to be incurred in the fourth quarter of fiscal 2005 compared to the cost that would have been incurred under the original supply contracts.

     After giving effect to the electricity supply contracts that were sold in January 2005 in the Pennsylvania territory, as of April 30, 2005, we have commitments of $79.6 million for electricity purchase contracts in the normal course of doing business. These contracts are with various suppliers and extend out through December 2006. In addition, at April 30, 2005, we have commitments of $2.0 million for natural gas purchase contracts, which are primarily transportation and capacity contracts, through October 2006.

Factors That May Affect Future Results

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

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

     Retail energy market restructuring has been and will continue to be a complicated regulatory process, with competing interests advanced not only by relevant state and federal utility regulators, but also by state legislators, federal legislators, local utilities, consumer advocacy groups and other market participants. As a result, the extent to which there are legitimate competitive opportunities for alternative energy suppliers in a given jurisdiction may vary widely and we cannot be assured that regulatory structures will offer us competitive opportunities to sell energy to

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consumers on a profitable basis. The regulatory process could be negatively impacted by a number of factors, including interruptions of service and significant or rapid price increases. The legislative and regulatory processes in some states take prolonged periods of time. In a number of jurisdictions, it may be many years from the date legislation is enacted until the retail markets are truly open for competition.

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

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

     We intend to increase our operating expenses to develop and expand our business, including brand development, marketing and other promotional activities and the continued development of our billing, customer care and power procurement infrastructure. Our ability to operate profitably will depend on, among other things:

	•	Our ability to attract and to retain a critical mass of customers at a reasonable cost;
	•	Our ability to continue to develop and maintain internal corporate organization and systems;
	•	The continued competitive restructuring of retail energy markets with viable competitive market rules; and
	•	Our ability to effectively manage our energy procurement and shaping requirements, and to sell our energy at a sufficient profit margin.

We may have difficulty obtaining a sufficient number of customers.

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

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

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

     We have developed our own systems and processes to operate our back-office functions, including customer enrollment, metering, forecasting, settlement and billing. Problems that arise with the performance of our back-office functions could result in increased expenditures, delays in the launch of our commercial operations into new markets, or unfavorable customer experiences that could materially adversely affect our business strategy. Also, any interruption of these services could be disruptive to our business. We are currently in the process of replacing a number of our internally developed legacy software systems with vendor systems. As we do so, we may incur duplicative expenses for a period of time, installation and integration issues with new systems or delays in the implementation of new systems. If we experience some or all of these new system implementation risks, we may not be able to establish a sufficient operating history for Sarbanes-Oxley 404 Attestation requirements, which we must meet by our fiscal year ending July 31, 2006.

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

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

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

Some suppliers of electricity have been experiencing deteriorating credit quality.

     We continue to monitor our suppliers’ credit quality to attempt to reduce the impact of any potential counterparty default. As of April 30, 2005, the majority of our counterparties are rated investment grade or above by the major rating agencies. These ratings are subject to change at any time with no advance warning. A deterioration in the credit quality of our suppliers could have an adverse impact on our sources of electricity purchases.

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

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

We do not utilize bank lines of credit at this time and may have limited access to additional credit from banks and commodity suppliers.

     As of April 30, 2005, we believe that we have adequate cash and liquidity and supplier lines of credit to sustain our business operations in the near term. To expand our business in the future, we will likely pursue external financing from banks, other financial institutions and commodity suppliers. In connection with financing arrangements, we may choose to pledge our accounts receivable and commodity inventory or commodity contracts as collateral to support the extension of credit. Additionally, we have issued and will continue to issue parent company guarantees of subsidiary obligations for commercial credit in connection with the arrangements for unsecured credit from commodity suppliers.

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

     Under the regulatory structures adopted in most jurisdictions, we will be required to enter into agreements with local utilities for use of the local distribution systems, and for the creation and operation of functional interfaces necessary for us to serve our customers. Any delay in these negotiations or our inability to enter into reasonable

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agreements with those utilities could delay or negatively impact our ability to serve customers in those jurisdictions. This could have a material negative impact on our business, results of operations and financial condition.

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

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

We are subject to federal and state regulations in our electricity and natural gas marketing business and the rules and regulations of regional independent system operators, or ISO’s, in our electricity business.

     The rules under which we operate are imposed upon us by federal and state regulators, the regional ISO’s and interstate pipelines. The rules are subject to change, challenge and revision, including revision after the fact.

     In California, the FERC and other regulatory and judicial bodies continue to examine the behavior of market participants during the California Energy Crisis of 2000 and 2001, and to recalculate what market clearing prices should have or might have been under alternative scenarios of behavior by market participants. In the event the historical costs of market operations were to be reallocated among market participants, we can not predict whether the results would be favorable or unfavorable for us nor can we predict the amount of such adjustments.

     In Pennsylvania, beginning in December 2004, the ISO established a Seams Elimination Charge Adjustment, or SECA, to compensate transmission owners for the change in the Regional Trough and Out Rates, or RTOR, which eliminated some transmission charges and revenues from the ISO system operations. The impact on us, if any, is uncertain at this time. Compensatory payments to transmission owners are likely, but the recovery mechanism from customers, utilities or other load serving entities, such as us, is uncertain. We can not predict the amount of these adjustments, if any, that it might be charged at this time.

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

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

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

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

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

	•	weather conditions, including hydrological conditions such as precipitation, snow pack and stream flow,
	•	seasonality,
	•	unexpected changes in customer usage,
	•	transmission or transportation constraints or inefficiencies,
	•	planned and unplanned plant or transmission line outages,
	•	demand for electricity,
	•	natural gas, crude oil and refined products, and coal supply availability to generators from whom we purchase electricity,
	•	natural disasters, wars, embargoes and other catastrophic events, and
	•	federal, state and foreign energy and environmental regulation and legislation.

We may experience difficulty in integrating and managing acquired businesses successfully and in realizing anticipated economic, operational and other benefits in a timely manner

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

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

     Effective internal controls are necessary for us to provide reliable financial reports and effectively prevent fraud. If we cannot provide reliable financial reports or prevent fraud, our operating results could be harmed. We have in the past discovered, and may in the future discover, areas of our internal controls that need improvement. For example, in January 2005, we sold electricity commodity supply contracts related to a strategic realignment of our customer portfolio in the Pennsylvania electricity market and the discontinuation of service to certain classes of residential and small commercial customers. As a result of timing issues related to realigning the portfolio and inaccurately forecasting the resulting required electricity supply, we had transitional electricity supply obligations which could have been served more cost effectively with the original supply contract rather than with the current market cost of the replacement power which was subsequently purchased at market prices. In the execution of this portfolio realignment, we observed deficiencies in our internal controls relating to monitoring the operational progress of the realignment. Our independent auditors advised us that in their opinion, with which we concur, these internal control deficiencies constitute reportable conditions, and collectively, a material weakness that caused us to restate our second quarter reported results, which means that this was an issue that in the auditor’s judgment could adversely affect our ability to record, process, summarize and report financial data consistent with the assertions of management in the financial statements. In both fiscal 2004 and 2005, we devoted significant resources to remediate and improve our internal controls. Although we believe that these efforts have strengthened our internal controls and addressed the concerns that gave rise to the reportable condition and material weakness in fiscal 2004 and 2005, we are continuing to work to improve our internal controls, including in the area of energy accounting. We cannot be certain that these measures will ensure that we implement and maintain adequate controls over our financial processes and reporting in the future. Any failure to implement required new or improved controls, or difficulties encountered in their implementation, could harm our operating results or cause us to fail to meet our reporting obligations. Inferior internal controls could also cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our stock.

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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 of July 31, 2006, as required by Section 404 of the Sarbanes-Oxley Act of 2002.

     As directed by Section 404 of the Sarbanes-Oxley Act of 2002, the Securities and Exchange Commission adopted rules requiring public companies to include a report of management on our internal controls over financial reporting in our Annual Reports on Form 10-K that contains an assessment by management of the effectiveness of our internal controls over financial reporting. In addition, our independent auditors must attest to and report on management’s assessment of the effectiveness of our internal controls over financial reporting. This requirement will first apply to our Annual Report on Form 10-K for the fiscal year ending July 31, 2006. How companies should be implementing these new requirements including internal control reforms, if any, to comply with Section 404’s requirements, and how independent auditors will apply these new requirements and test companies’ internal controls, are subject to uncertainty. Although we are diligently and vigorously reviewing our internal controls over financial reporting in order to ensure compliance with the new Section 404 requirements, if our independent auditors are not satisfied with our internal controls over financial reporting or the level at which these controls are documented, designed, operated or reviewed, or if the independent auditors interpret the requirements, rules or regulations differently than we do, then they may decline to attest to management’s assessment or may issue a report that is qualified. This could result in an adverse reaction in the financial marketplace due to a loss of investor confidence in the reliability of our financial statements, which ultimately could negatively impact the market price of our shares.

     We have initiated a company-wide review of our internal controls over financial reporting as part of the process of preparing for compliance with Section 404 of the Sarbanes-Oxley Act of 2002 and as a complement to our existing overall program of internal controls over financial reporting. As a result of this on-going review, we have made numerous improvements to the design and effectiveness of our internal controls over financial reporting through the period ended April 30, 2005. We anticipate that improvements will continue to be made.

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

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

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

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

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of direct energy costs. We did not engage in trading activities in the wholesale energy market other than to manage our direct energy cost in an attempt to improve the profit margin associated with our customer requirements.

     The amounts recorded in other comprehensive income (loss) at April 30, 2005 related to cash flow hedges are summarized in the following table:

     As of June 6, 2005, we had 92% of our forecast fixed price electricity load through December 31, 2005 covered through either fixed price power purchases with counterparties, or price protected through financial hedges. In addition, a significant portion of our forecast energy (both electricity and currently all natural gas) load contain variable pricing and therefore, do not have significant fixed price commitments beyond several months.

Item 4. Controls and Procedures.

     a) Evaluation of Disclosure Controls and Procedures.

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

     In June 2005, we advised the Audit Committee of our Board of Directors that, in monitoring the strategic realignment of our Pennsylvania customer portfolio, we noted deficiencies in our disclosure controls and procedures, as well as our internal controls over financial reporting relating to monitoring the operational progress of the realignment and properly forecasting the resulting required electricity supply.

     Our independent auditors, Ernst & Young LLP, have advised the Audit Committee, also in June 2005, that these internal control deficiencies constitute a reportable condition and a material weakness as defined in Statement on Auditing Standards No. 60. Immediately prior to the filing of this Quarterly Report on Form 10-Q, we filed an amended Quarterly Report on Form 10-Q/A for the period ended January 31, 2005. The amended Quarterly Report principally restates prior reported results and include additional disclosures in the appropriate period as a result of finding the foregoing weakness in our internal controls.

     We continue to evaluate and implement methods to improve our internal controls and procedures with the assistance of outside advisors. We have taken the following corrective actions, some of which we began to implement 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 evaluated several such third party systems and have begun implementation on our selections;
	•	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

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•

Established senior level management oversight of the load forecasting process, including weekly update and reporting meetings.

     We will continue to designed and implement additional procedures to ensure that these internal control deficiencies will not result in material misstatements in our consolidated financial statements contained in this Quarterly Report on Form 10-Q, and will not result in material misstatements in our future financial results.

     b) Changes in Internal Controls.

     Other than as described above, there have been no material changes in our internal control over financial reporting during the period covered by this report that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II — OTHER INFORMATION

Item 6. Exhibits.

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

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SIGNATURES

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

COMMERCE ENERGY GROUP, INC.

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EXHIBIT INDEX

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