UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

Commission File Number 001-32239

COMMERCE ENERGY GROUP, INC.

(Exact name of registrant as specified in its charter)

(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

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

      As of December 14, 2005, 30,231,809 shares of the registrant’s common stock were outstanding.

COMMERCE ENERGY GROUP, INC.

Form 10-Q

For the Period Ended October 31, 2005

Index

FORWARD-LOOKING INFORMATION

      A number of the matters and subject areas discussed in this Quarterly Report on Form 10-Q contain forward-looking statements reflecting management’s current expectations. On one or more occasions, we may make statements regarding our assumptions, projections, expectations, targets, intentions or beliefs about future events. All statements other than statements of historical facts included in this Form 10-Q relating to expectation of future financial performance, continued growth, changes in economic conditions or capital markets and changes in customer usage patterns and preferences, are forward-looking statements.

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

      In addition to the factors and other matters discussed under the caption “Factors That May Affect Future Results” in Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations in this Quarterly Report on Form 10-Q, some important factors that could cause actual results or outcomes for Commerce Energy Group, Inc. or our subsidiaries to differ materially from those discussed in forward-looking statements include:

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

PART I — FINANCIAL INFORMATION

COMMERCE ENERGY GROUP, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)

(Unaudited)

The accompanying notes are an integral part of these condensed Consolidated Financial Statements.

COMMERCE ENERGY GROUP, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands)

The accompanying notes are an integral part of these condensed Consolidated Financial Statements.

COMMERCE ENERGY GROUP, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

The accompanying notes are an integral part of these condensed Consolidated Financial Statements.

COMMERCE ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(In thousands, except per share amounts)

      The condensed financial statements for the three months ended October 31, 2005 of Commerce Energy Group, Inc. (“the Company”), include its two wholly-owned subsidiaries: Commerce Energy, Inc (“Commerce”) and Skipping Stone Inc. (“Skipping Stone”). All material inter-company balances and transactions have been eliminated in consolidation.

      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 and in the opinion of management, 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, 2005.

      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. In preparing our financial statements and accounting for the underlying transactions and balances, we apply our accounting policies as disclosed in our notes to the consolidated financial statements. The accounting policies relating to accounting for derivatives and hedging activities, inventory, independent system operator costs, allowance for doubtful accounts, revenue and unbilled receivables and other legal matters are those that we consider to be the most 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.

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

COMMERCE ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In thousands, except per share amounts)

      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:

      Skipping Stone revenue (which is included in retail electricity sales above), after elimination of inter-company transactions, for the three months ended October 31, 2005 and October 31, 2004 was $447 and $601, respectively, representing approximately 1% of total net revenue for both periods.

      Effective in the first quarter of fiscal 2006, the Company adopted Statement of Financial Accounting Standards No. 123 (revised 2004), Share-Based Payments (“SFAS 123R”) which revises SFAS No. 123, Accounting for Stock-Based Compensation and supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees. SFAS 123R requires all share-based payments to employees, including grants of employee stock options, be measured at fair value and expensed in the consolidated statement of operations over the service period (generally the vesting period). The Company uses the Black-Scholes option valuation model to value stock options. As a result of the adoption of SFAS 123R, the Company recognized a $231 pre-tax (tax effect minimal) charge associated with the expensing of stock options vested in the first fiscal quarter. This expense is included in general and administrative expenses.

      The fair value of options granted is estimated on the date of grant using the Black-Scholes model based on the following weighted-average assumptions in the table below. The assumption for the expected life is based on evaluations of historical and expected future exercise behavior. The risk-free interest rate is based on the US Treasury rates at the date of the grant with maturity dates approximately equal to the expected life at the grant date. The historical stock volatility of the Company’s common stock is used as the basis for the volatility assumption,

COMMERCE ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In thousands, except per share amounts)

      A summary of option activity under the Commonwealth Energy Corporation 1999 Equity Incentive Plan (the “Incentive Plan”) as of October 31, 2005 and the changes during the quarter then ended is presented below.

      As of October 31, 2005, there was $299 of total unrecognized compensation cost related to non-vested outstanding stock options, which is expected to be recognized over the period November 1, 2005 through August 1, 2007.

      Prior to the adoption of FAS123R, the Company accounted for its employee stock options under the provision of Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees and related interpretations. The Company’s compensation cost, net loss or loss per share, would have reflected a nominal change if the stock-based compensation plan had been determined based on the fair value method (estimated using Black-Scholes option pricing model) at the grant dates in accordance with Financial Accounting Standards Board Statement No. 123, Accounting for Stock-Based Compensation, for the three months ended October 31, 2004.

      The Company has established valuation allowances to reserve its net deferred tax assets, because management believes it is not certain that the Company will realize the tax benefits in the foreseeable future.

      The Company’s chief operating decision makers consist of members of senior management that work together to allocate resources to, and assess the performance of, the Company’s business. These members of senior management currently manage the Company’s business, assess its performance, and allocate its resources as the single operating segment of energy retailing. As Skipping Stone, net of inter-company eliminations, accounts for approximately 1% of total net revenue, and geographic information is not material, no segment information is provided.

COMMERCE ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In thousands, except per share amounts)

      Accounts receivable, net, is comprised of the following:

      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.

      Basic income (loss) per common share was computed by dividing net income (loss) available to common stockholders, 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 (loss) and the denominator (common shares in thousands) used in the computation of basic and diluted loss per common share:

      For the three months ended October 31, 2004, the effects of the assumed exercise of all stock options 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 months ended October 31, 2004 would have been 30,881.

      The Company currently serves electricity and gas customers in nine states, operating within the jurisdictional territory of nineteen different local utilities. Although regulatory requirements are determined at

COMMERCE ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In thousands, except per share amounts)

the individual state, and administered and monitored by the Public Utility Commission, or PUC, of each state, operating rules and rate filings for each utility are unique. Accordingly, the Company generally treats each utility distribution territory as a distinct market. Among other things, tariff filings by local distribution companies, or LDCs, for changes in their allowed billing rate to their customers in the markets in which the Company operates, significantly impact the viability of the Company’s sales and marketing plans, and its overall operating and financial results.

      Currently, the Company actively markets electricity in eleven LDC markets within the five states of California, Pennsylvania, Michigan, New Jersey and Texas.

      On April 1, 1998, the Company began supplying customers in California with electricity as an Electric Service Provider, or ESP. On September 20, 2001, the California Public Utility Commission, or CPUC, issued a ruling suspending the right of Direct Access, which allowed electricity customers to buy their power from a supplier other than the electric utilities. This suspension, although permitting the Company to keep current direct access customers and to solicit direct access customers served by other ESPs, prohibits the Company from soliciting new non-direct access customers for an indefinite period of time.

      Recently, the CPUC has made several important determinations, including a Resource Adequacy Requirement and a Renewable Portfolio Standard. The Resource Adequacy Requirement requires load serving entities, or LSEs, to demonstrate that they have, or have acquired, the capacity to serve their customers including a 15-17% reserve margin beginning in June 2006, with an initial demonstration due in January 2006. The Renewable Portfolio Standard will require increasing levels of renewable power supplied by LSEs up to 20% by 2010. Additional costs to serve customers in California are anticipated from these proceedings; however, the Company cannot predict the impact of these proceedings and the anticipated CPUC implementation rules will determine the distribution of those costs across all LSEs.

      On November 21, 2005 the Federal Energy Regulatory Commission (FERC) issued an order accepting the California Independent System Operator’s (CAISO’s) modification to their tariff amendment number 72. This change requires all California Scheduling Coordinators (SCs), and all Load Serving Entities (LSEs) who act as their own SCs which includes Commerce Energy, to submit day-ahead schedules that reflect purchased power equal to 95 percent of their forecasted daily demand. This change is expected to result in significant revisions to operating procedures to match the block shapes of the power purchased by SCs to the load shapes utilized by their customers. Failure to achieve the 95% precision required by the order may result in additional charges, penalties and/or the operational adjustments. The financial impact on the Company cannot be determined at this time.

      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 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 cannot predict whether the results would be favorable or unfavorable, or the amount of any resulting adjustment. The payment or receipt of adjustments, if any, will likely be conducted between FERC, the California ISO and the Company’s contracted scheduling coordinator for the period in question. Automated Power Exchange (APX). APX served as the direct interface with the now defunct California Power Exchange for the sale and purchase of some volumes of power by the Company during 2000 and 2001.

      Detroit Edison has to file a plan to un-bundle their energy and distribution charges with the Michigan Public Service Commission (MPSC). A primary component of this filing is a shifting of rate responsibility from commercial to residential customers. If this filing is approved, commercial and industrial customers will

COMMERCE ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In thousands, except per share amounts)

receive a substantial energy rate decrease which may have a negative impact on the Company’s ability to retain and acquire new commercial customers in the state.

      There are no current rate cases or filings in the states of Pennsylvania, New Jersey or Texas that are anticipated to adversely impact the Company’s financial results.

      Currently, the Company actively markets natural gas in eight LDC markets within the six states of California, Georgia, Maryland, New York, Ohio and Pennsylvania. Due to recent and significant increases in the price of natural gas, a number of LDCs have filed or communicated expectations of filing for approval of rate increases to their customers. Although the impact of these filings cannot currently be estimated, they are not anticipated to adversely impact the Company’s financial results.

      The Company had three investments in the following early-stage, energy related entities: Encorp, Inc. (“Encorp”), Turbocor B.V. (“Turbocor”) and Power Efficiency Corporation (“PEC”). On July 29, 2005, we sold our ownership interest in Turbocor for $2,000.

      The two remaining companies, which are expected to continue to incur operating losses, have very limited working capital. As a result, continuing operations will be dependent upon these companies 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 October 31, 2005, these two remaining investments are carried at a nominal value in goodwill, intangibles and other assets.

      On February 9, 2005, the Company acquired certain assets of ACN Utility Services, Inc. (“ACNU”), a subsidiary of American Communications Network, Inc. (“ACN”), 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 $14.5 million in cash and 930 shares of the Company’s common stock, valued at $2.0 million. 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 ACN meeting certain sales requirements under a one year, renewable, Sales Agency Agreement between ACN and the Company (“Sales Agency Agreement”) (See Note 8) during the year following the acquisition date, and has been placed in an escrow account. Based on sales results to date, it appears that the contingent consideration will not be earned and goodwill will be reduced by substantially all of the $2.0 million.

      The assets acquired included approximately 80,000 natural gas and electricity residential and small commercial customers, 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 infrastructures. No cash or accounts receivables were acquired in the transaction and none of ACNU’s legal 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, the effective date of the acquisition.

COMMERCE ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In thousands, except per share amounts)

      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 to have a material adverse effect on its results of operations or financial position.

      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 such as forward physical delivery contracts and financial swaps, options and futures contracts, are subject to the management, direction and control of an internal risk oversight committee. The Company maintains commodity price risk management strategies that use these derivative instruments, within approved risk tolerances, to minimize significant, unanticipated earnings fluctuations caused by commodity price volatility.

      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 purchases substantially all of its power and natural gas utilizing forward physical delivery contracts. These physical delivery contracts are defined as commodity derivative contracts under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”. Using the exemption available for qualifying contracts under SFAS No. 133, the Company applies the normal purchase and normal sale accounting treatment to its forward physical delivery contracts. Accordingly, the Company records revenue generated from customer sales as energy is delivered to retail customers and the related energy under the forward physical delivery contracts is recorded as direct energy costs when received from suppliers.

      In January 2005, the Company sold two significant electricity forward physical delivery contracts (on a net cash settlement basis) back to the original supplier in connection with a strategic realignment of its customer portfolio in the Pennsylvania electricity market, or PJM-ISO, which resulted in a gain of $7.2 million in the second quarter of fiscal 2005. As a result of that sale, the normal purchase and normal sale exemption is not currently available for the PJM-ISO

      For forward or future contracts that do not meet the qualifying criteria for normal purchase, normal sale accounting treatment, the Company elects cash flow hedge accounting, where appropriate. Under cash flow hedge accounting, the fair value of the contract is recorded as a current or long-term derivative asset or liability. Subsequent changes in the fair value of the derivative assets and liabilities are recorded on a net basis in Other Comprehensive Income (Loss), or OCI, and reflected as direct energy cost in the statement of operations as the energy is delivered. The net other comprehensive loss on designated cash flow hedged instruments was $0.2 million and $0 for the three months ended October 31, 2005 and 2004, respectively.

      Certain financial derivative instruments (such as swaps, options and futures), designated as economic hedges or as speculative, do not qualify or meet the requirements for normal purchase, normal sale accounting treatment or cash flow hedge accounting and are recorded currently in operating income (loss) and as a current or long-term derivative asset or liability depending on their term. The subsequent changes in the fair value of these contracts may result in operating income (loss) volatility as the fair value of the changes are recorded on a net basis in direct energy cost in the consolidated statement of operations for each fiscal period.

COMMERCE ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In thousands, except per share amounts)

As of October 31, 2005, the mark to market impact of economic hedges, utilized primarily to hedge the Company’s cost of electricity in Pennsylvania, was a gain of $0.9 million. The notional value of these derivatives outstanding at October 31, 2005 was $1.8 million.

      On November 28, 2005, ACN notified Commerce of its intent not to renew the Sales Agency Agreement between ACN and Commerce. As a result of the notice of ACN’s intent not to renew, the Sales Agency Agreement will terminate automatically on February 9, 2006.

      With the termination of the Sales Agency Agreement, ACN’s network of sales representatives will no longer offer Commerce’s electricity and natural gas products after February 9, 2006. Commerce believes that the termination of the Sales Agency Agreement will not materially affect its relationships with existing customers acquired in the ACN Energy Transaction or subsequently acquired through ACN’s network of sales representatives under the Sales Agency Agreement and that its existing internal direct sales force and other indirect sales channels in development will effectively replace ACN’s sales network in its current and future electricity and natural gas retail markets.

      On November 17, 2005, the Company entered into settlement agreements and general releases with each of the Company’s former President, Peter Weigand, and Chief Financial Officer, Richard L. Boughrum. Additionally, Peter Weigand submitted his resignation from the Board, effective November 17, 2005.

      Under the terms of the settlement agreements, the Company agreed to pay Mr. Weigand and Mr. Boughrum lump sum settlement payments totaling $1,060 in April 2006, and agreed to purchase all of their 1,414,479 shares of the Company’s common stock at a price of $1.50 per share, with 120,000 of such shares held by Mr. Weigand being purchased by two of the independent directors of the Company. Payments for the stock by the Company shall be made in several installments, the first installment representing one half of the amount, was paid on November 28, 2005, and the other half of the payment shall be made pursuant to a promissory note to be paid in five equal installments commencing in December 2005. In connection with the purchase of the shares of common stock, all of Mr. Weigand’s and Mr. Boughrum’s stock options, 1,100,000 in the aggregate, were cancelled.

      The above-referenced lump sum settlement payments to be made to Messrs. Weigand and Boughrum in April 2006 pursuant to the Settlement Agreements replaced the monthly severance payments which otherwise would be made under their respective Employment Agreements. Under the settlement agreements, each of Mr. Weigand and Mr. Boughrum, and the Company agreed to mutual general releases of claims that the parties may have had against each other.

      The Company entered into a settlement agreement and general release with Eric Alam, Senior Vice President of Sales and Marketing. Mr. Alam resigned effective December 1, 2005 and agreed to sell to the Company all of his 174,926 shares of stock for $1.50 per share to be paid in two equal installments, in November 2005 and February 2006. In connection with the purchase of his shares of common stock, all 133,000 of Mr. Alam’s stock options were cancelled.

Overview

      We are a diversified independent energy marketer of electricity and natural gas to end-use customers. We provide retail electricity and natural gas to residential, commercial, industrial and institutional customers in nine states. Our principal operating subsidiary, Commerce Energy, Inc., is licensed by the Federal Energy Regulatory Commission, or FERC, as a power marketer. In addition to the states in which we currently operate, we are also licensed to supply retail electricity in New York, Maryland, Ohio and licensed to supply retail electricity and natural gas in Virginia.

      We were founded in 1997 as a retail electricity marketer in California and have grown to serve electricity and natural gas customers in nineteen utility markets in nine states. Growth has occurred by a combination of organic means and acquisitions. In the past eighteen months we acquired Skipping Stone Inc., or Skipping Stone, an energy consulting company, and purchased from American Communications Network, Inc. and certain of its subsidiaries, which we refer to collectively as ACN, certain assets of ACN’s retail electric power and natural gas sales business.

      As of October 31, 2005, we delivered electricity to approximately 76,000 customers in California, Pennsylvania, Michigan, New Jersey and Texas; and natural gas to approximately 58,000 customers in California, Georgia, Maryland, New York, Ohio and Pennsylvania. The potential growth of this business depends upon a number of factors, including the degree of deregulation in each state, our ability to acquire new customers and retain existing customers and our ability to acquire energy for our customers at competitive prices and on favorable credit terms.

      The electricity and natural gas we sell to our customers is purchased from third party suppliers under short-term and long-term contracts. 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 the local utilities. The local utilities also provide billing and collection services for many of our customers on our behalf. Additionally, to facilitate load shaping and demand balancing for our customers, we buy and sell surplus electricity and natural gas from and to other market participants when necessary. We utilize third party facilities for the storage of our natural gas.

      As used herein, the “Company,” “we,” “us,” or “our” means Commerce Energy Group, Inc. and its wholly-owned subsidiaries. “Commerce” refers to Commerce Energy, Inc., our principal operating subsidiary.

Acquisitions

      On February 9, 2005, we acquired certain assets of ACN Utility Services, Inc., or ACNU, a subsidiary of American Communications Network, Inc., or ACN, and its retail electricity and natural gas sales business. We collectively refer to the assets and business acquired as the “ACN Energy Assets.” 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 $14.5 million in cash and 930 shares of our common stock, valued at $2.0 million. In addition, as part of the initial purchase price, we were 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 was contingent upon ACN meeting certain sales requirements under a one year, renewable, Sales Agency Agreement between ACN and Commerce (“Sales Agency Agreement”) during the year following the acquisition date, and has been placed in an escrow account. Based on sales results to date, it appears that the contingent consideration will not be earned and goodwill will be reduced by substantially all of the $2.0 million.

      The assets acquired included approximately 80,000 natural gas and electricity residential and small commercial customers, 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 infrastructures. No cash or accounts receivables were acquired in the transaction and none of ACNU’s legal

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, the effective date of the acquisition.

      On April 1, 2004, we acquired Skipping Stone Inc. which provides energy-related consulting and technologies to utilities, electricity generators, natural gas pipelines, wholesale energy merchants, energy technology providers and financial institutions. The aggregate purchase price for all of the outstanding Skipping Stone securities, which consisted of common stock and vested options, was $3.1 million and the assumption of $600,000 of debt, subject to limited restrictions and true-up provisions. The purchase price was paid through the issuance of shares of our common stock valued at $1.92 per share. For the fiscal year ended July 31, 2005, Skipping Stone revenues (after elimination of inter-company transactions) accounted for less than 1% of total net revenue of Commerce.

Investments

      We had three investments in the following early-stage, energy related entities: Encorp, Inc. (“Encorp”), Turbocor B.V. (“Turbocor”) and Power Efficiency Corporation (“PEC”). In July 29, 2005, we sold our ownership interest in Turbocor for $2,000.

      The two remaining companies, which are expected to continue to incur operating losses, have very limited working capital. As a result, continuing operations will be dependent upon these companies securing additional financing to meet their respective immediate capital needs. We have no obligation, and currently no intention, to invest additional funds into these companies. At October 31, 2005, these two remaining investments are carried at a nominal value in goodwill, intangibles and other assets.

Market and Regulatory

      We currently serve electricity and gas customers in nine states, operating within the jurisdictional territory of nineteen different local utilities. Although regulatory requirements are determined at the individual state, and administered and monitored by the Public Utility Commission, or PUC, of each state, operating rules and rate filings for each utility are unique. Accordingly, we generally treat each utility distribution territory as a distinct market. Among other things, tariff filings by local distribution companies, or LDCs, for changes in their allowed billing rate to their customers in the markets in which we operate, significantly impact the viability of our sales and marketing plans, and our overall operating and financial results.

      Currently, we actively market electricity in eleven LDC markets within the five states of California, Pennsylvania, Michigan, New Jersey and Texas.

      On April 1, 1998, we began supplying customers in California with electricity as an Electric Service Provider, or ESP. On September 20, 2001, the California Public Utility Commission, or CPUC, issued a ruling suspending the right of Direct Access, which allowed electricity customers to buy their power from a supplier other than the electric utilities. This suspension, although permitting us to keep current direct access customers and to solicit direct access customers served by other ESPs, prohibits us from soliciting new non-direct access customers for an indefinite period of time.

      Recently, the CPUC has made several important determinations, including a Resource Adequacy Requirement and a Renewable Portfolio Standard. The Resource Adequacy Requirement requires load serving entities, or (LSEs), to demonstrate that they have, or have acquired, the capacity to serve their customers including a 15-17% reserve margin beginning in June 2006, with an initial demonstration due in January 2006. The Renewable Portfolio Standard will require increasing levels of renewable power supplied by LSEs up to 20% by 2010. Additional costs to serve customers in California are anticipated from these proceedings,; however, we cannot predict the impact of these proceedings and the anticipated CPUC implementation rules will determine the distribution of those costs across all LSEs.

      On November 21, 2005 the Federal Energy Regulatory Commission (FERC) issued an order accepting the California Independent System Operator’s (CAISO’s) modification to their tariff amendment number 72. This change requires all California Scheduling Coordinators (SCs), and all Load Serving Entities (LSEs) who act as their own SCs which includes Commerce Energy, to submit day-ahead schedules that reflect purchased power equal to 95 percent of their forecasted daily demand. This may result in significant revisions to operating procedures to match the block shapes of the power purchased by SCs to the load shapes utilized by their customers. Failure to achieve the 95% precision required by the order may result in additional charges, penalties and/or operational adjustments. The financial impact on individual LSE’s including the Company, cannot be determined at this time.

      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 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 cannot predict whether the results would be favorable or unfavorable, or the amount of any resulting adjustment. The payment or receipt of adjustments, if any, will likely be conducted between FERC, the California ISO and our contracted scheduling coordinator for the period in question. Automated Power Exchange (APX). APX served as the direct interface with the now defunct California Power Exchange for the sale and purchase of some volumes of power by us during 2000 and 2001.

      Detroit Edison has to file a plan to un-bundle their energy and distribution charges with the Michigan Public Service Commission (MPSC). A primary component of this filing is a shifting of rate responsibility from commercial to residential customers. If this filing is approved, commercial and industrial customers will receive a substantial energy rate decrease which may have a negative impact on the Company’s ability to retain and acquire new commercial customers in the state.

      There are no current rate cases or filings in the states of Pennsylvania, New Jersey or Texas that are anticipated to impact our financial results.

      Currently, we actively market natural gas in eight LDC markets within the six states of California, Georgia, Maryland, New York, Ohio and Pennsylvania. Due to recent and significant increases in the price of natural gas, a number of LDCs have filed or communicated expectations of filing for approval of rate increases to their customers. Although the impact of these filings cannot currently be estimated, they are not anticipated to adversely impact our financial results.

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.

Results of Operations

      The following table summarizes the results of our operations for the three months ended October 31, 2005 and 2004 (dollars in thousands).

      Operating results for the three months ended October 31, 2005 reflect a loss from operations of $0.1 million compared to income of $1.2 million for the comparable prior year period. Net revenue and gross profit increased $5.9 million and $1.1 million, or 10% and 15%, respectively. Higher gross profit for the three months ended October 31, 2005 as compared to the previous year’s quarterly period, reflects $1.9 million of gross profit attributable to the ACN Energy assets, partly offset by a $0.5 million decrease in the Company’s mark-to-market gains related to its Pennsylvania supply contracts and the impact of lower electricity sales volumes in Michigan.

      The following table summarizes retail net revenues for the three months ended October 31, 2005 and 2004 (dollars in thousands):

      Net revenues for the three months ended October 31, 2005 were $64.4 million, a 10% increase compared to net revenues of $58.5 million for the three months ended October 31, 2004. The increase in net revenue was primarily attributable to the addition of the ACN Energy Assets and higher wholesale market prices for electricity. These net revenue increases were partly offset by the impact of lower sales volumes in the Company’s traditional electricity markets in California, Pennsylvania and Michigan.

      Retail electricity sales for the three months ended October 31, 2005 were $49.6 million, a 5% decrease from the same period in 2004. For the three months ending October 31, 2005, we sold 551 million kWh, at an average retail price per kWh of $0.090, as compared to 775 million kWh sold at an average retail price per kWh of $0.067 in the same prior year period. California sales were 205 million kWh at an average price per kWh of $0.086, compared to 246 million kWh sold at an average price per kWh of $0.076. Pennsylvania and New Jersey sales were 190 million kWh at an average price per kWh of $0.094, compared to 319 million kWh at an average price of $0.067. Sales in Michigan decreased to 110 million kWh at an average price per kWh of $0.072 in 2005, compared to 209 million kWh at an average price per kWh of $0.057. Texas sales were 46 million kWh at an average price per kWh of $0.136.

      We acquired our natural gas business in six states in February 2005. For the three months ending October 31, 2005, natural gas sales were $8.9 million. We sold approximately 0.7 million dekatherms, or DTH, during this period at an average price of $12.48 per DTH.

      Excess energy sales decreased slightly to $5.4 million in the three months ended October 31, 2005 compared to $5.8 million in 2004.

      We had approximately 76,000 retail electricity customers at October 31, 2005, a decrease of 24% from 100,000 at October 31, 2004. This customer attrition in our retail electricity markets largely reflects the impact of increased sales prices to our customers resulting from higher wholesale electricity supply and transmission costs without corresponding price increases from incumbent utilities due to the lack of market responsive ratemaking and a lagging regulatory approval process. The majority of the decline in our retail electricity

customers occurred in our Pennsylvania market whereby, beginning in April 2005, we returned approximately 21,000 residential and small commercial customers to the incumbent utility since we could no longer offer competitive service. Additionally, the decline in our customer base is partly attributed to our focus on increasing our commercial and industrial base. We also had approximately 58,000 natural gas customers at October 31, 2005.

      Direct energy costs, which are recognized concurrently with related energy sales, include the commodity cost of natural gas and electricity, electricity transmission costs from the ISOs, transportation costs from LDCs and pipelines, other fees and costs incurred from various energy-related service providers and energy-related taxes that cannot be passed directly through to the customer.

      Direct energy costs for the three months ended October 31, 2005 totaled $48.4 million and $7.7 million for electricity and natural gas, respectively.

      Electricity costs averaged $0.077 per kWh for the three months ended October 31, 2005, as compared to $0.058 per kWh for the same period last year. Direct energy costs for natural gas for the three months ended October 31, 2005 averaged $10.83 per DTH.

      Selling and marketing expenses were $0.7 million for the three months ended October 31, 2005, a decrease of $0.3 million from $1.0 million for the three months ended October 31, 2004. Lower selling and marketing expenses primarily resulted from a reduction in salary costs.

      General and administrative expenses were $7.6 million for the three months ended October 31, 2005, an increase of $2.6 million from $5.0 million for the three months ended October 31, 2004. The increase reflects $1.8 million of added direct costs related to the acquired operations of the ACN energy assets; $0.6 million in higher legal, board and other expenses primarily incurred in connection with severance agreements to former executives, and $0.2 million resulting from the adoption of SFAS 123R.

      In the three months ended October 31, 2004, we incurred $1.4 million of initial formation litigation costs related to Commonwealth Energy Corporation’s formation. 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.

      No provision for, or benefit from income taxes was recorded for the three months ended October 31, 2005 or 2004. Starting in fiscal 2004, and continuing through the current period, 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.

Liquidity and Capital Resources

      As of October 31, 2005, cash and cash equivalents decreased to $21.2 million, compared to $33.3 million at July 31, 2005. This decrease of $12.1 million was the result of using cash to increase $4.0 million in prepaid gas, $3.6 million in gas inventory, $1.9 million in other energy deposits, and to reduce accounts payable by $2.7 million. These changes in part reflect the seasonal nature of natural gas sales that require inventory buildup and the funding of additional purchases going into the winter months. Restricted cash and cash

equivalents were $8.3 million, compared to $8.2 million at July 31, 2005. 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 three months ended October 31, 2005 was $11.5 million, compared to the cash flow provided by operations of $0.1 million in the three months ended October 31, 2004 primarily because of the items discussed in the preceding paragraph.

      Cash flow used in investing activities for the three months ended October 31, 2005 consisted of capital expenditures.

      The Company does not have open lines of credit for direct unsecured borrowings or letters of credit. Credit terms from our suppliers of electricity often require us to post collateral against our energy purchases and against our mark-to-market exposure with certain of our suppliers. We currently finance these collateral obligations with our available cash. If we are required to post such additional security, a portion of our cash would become restricted, which could adversely affect our liquidity. As of October 31, 2005, we had $8.3 million in restricted cash to secure letters of credit required by our suppliers and $13.2 million in deposits pledged as collateral in connection with energy purchase agreements.

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

      For the three months ended October 31, 2005, we have entered into additional electricity purchase contracts in the normal course of doing business for $44.7 million. These contracts are for less than one year and are with various suppliers.

Factors That May Affect Future Results

      The Federal Energy Regulatory Commission, or FERC, has maintained a strong commitment to the deregulation of wholesale electricity markets. The new provisions of EPA 2005 should serve to further enhance the reliability of the electric transmission grid which our electric marketing operations depend on for delivery of power to our customers. This movement at the federal level has in part helped spur deregulation measures in the states at the retail level. Twenty-three states and the District of Columbia have either enacted enabling legislation or issued a regulatory order to implement retail access. In 18 of these states, retail access is either currently available to some or all customers, or will soon be available. However, in many of these markets the market rules adopted have not resulted in energy service providers being able to compete successfully with the local utilities and customer switching rates have been low. Our business model depends on other favorable markets opening under viable competitive rules in a timely manner. In any particular market, there are a number of rules that will ultimately determine the attractiveness of any market. Markets that we enter may have both favorable and unfavorable rules. If the trend towards competitive restructuring of retail energy markets does not continue or is delayed or reversed, our business prospects and financial condition could be materially adversely impaired.

      Retail energy market restructuring has been and will continue to be a complicated regulatory process, with competing interests advanced not only by relevant state and federal utility regulators, but also by state legislators, federal legislators, local utilities, consumer advocacy groups and other market participants. As a result, the extent to which there are legitimate competitive opportunities for alternative energy suppliers in a given jurisdiction may vary widely and we cannot be assured that regulatory structures will offer us competitive opportunities to sell energy to consumers on a profitable basis. The regulatory process could be negatively impacted by a number of factors, including interruptions of service and significant or rapid price

increases. The legislative and regulatory processes in some states take prolonged periods of time. In a number of jurisdictions, it may be many years from the date legislation is enacted until the retail markets are truly open for competition.

      Other aspects of EPA 2005, such as the repeal of PUHCA 1935 and replacing it with PUHCA 2005, also may impact our business to the extent FERC does not continue the SEC’s precedent of not regulating electric and gas marketers under PUHCA. A rulemaking implementing PUHCA 2005 is currently pending before FERC. If marketers and their parent companies and affiliates are to be regulated under PUHCA 2005, FERC may have access to their books and records and has oversight of their affiliate transactions. Various parties participating in FERC rulemaking have urged FERC not to so regulate marketers and other entities that do not own or operate gas or electric facilities.

      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 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:

      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 have developed our own systems and processes to operate our back-office functions, including customer enrollment, metering, forecasting, settlement and billing. We are currently in the process of replacing a number of our internally developed legacy software systems with vendor-developed systems. Problems that arise with the performance of such 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. Any interruption of these services could also be disruptive to our business. As we transition from our own systems to new vendor-developed systems, we may incur duplicative expenses for a period of time and we may experience installation and integration issues with the new systems or delays in the implementation of the 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 expect we must meet by no later than fiscal year ending July 31, 2007.

      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 the 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.

      As of October 31, 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.

      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 continue to monitor the credit quality of our energy suppliers to attempt to reduce the impact of any potential counterparty default. As of October 31, 2005, the majority of our counterparties are rated investment grade or above by the major rating agencies. These ratings are subject to change at any time with no advance warning. A deterioration in the credit quality of our energy suppliers could have an adverse impact on our sources of electricity purchases.

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

      We are dependent on local utilities for maintenance of the infrastructure through which electricity 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. The local utility’s systems and procedures may limit or slow down our ability to add customers.

      In some states, we are 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 or unable to confirm the accuracy of the information provided by the local utility. In addition, we are unable to control when we receive customer payments from the local utility. If we do not receive payments from the local utility on a timely basis, our working capital may be impaired. In the event we do not receive timely or accurate usage data, our ability to generate timely and accurate bills to our customers will be adversely affected which, in turn, will impact the ability of our customers to pay bills in a timely manner.

      The rules under which we operate are imposed upon us by federal and state regulators, the regional ISOs 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 cannot predict whether the results would be favorable or unfavorable for us nor can we predict the amount of such adjustments. The payment or receipt of adjustments, if any, will likely be conducted between FERC, the California ISO and our contracted scheduling coordinator for the period in question, Automated Power Exchange, or APX. APX served as the direct interface with the now defunct California Power Exchange for the sale and purchase of some volumes of power by the Company during 2000 and 2001.

      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 Through 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 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.

      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.

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

      We recently completed an acquisition of assets in connection with the ACN Energy Transaction. The ultimate success of this acquisition will depend, in part, on our ability to realize the anticipated synergies, cost savings and growth opportunities from integrating the assets and the relationships acquired in the ACN Energy Transaction into our existing businesses.

      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. In the execution of this portfolio realignment, we observed deficiencies in our internal controls relating to monitoring the operational progress of the realignment. These internal control deficiencies constituted reportable conditions, and collectively, a material weakness that caused us to restate our second quarter reported results. In connection with the preparation of our consolidated financial statements for the fiscal year ended July 31, 2005, we determined that (a) certain electricity forward physical contracts and financial derivatives designated as cash flow hedges lacked adequate documentation of our method of measurement and testing of hedge effectiveness to meet the cash flow hedge requirements of SFAS No. 133 and (b) a forward physical contract and several financial derivative contracts had been inappropriately accounted for as exempt from hedge accounting under SFAS No. 133. These errors in the proper application of the provisions of SFAS No. 133 required us to restate our previously reported results for each of the first three quarters in fiscal 2005 and led us to conclude and report the existence of a material weakness in our internal controls over financial reporting. We purchase substantially all of our power and natural gas under forward physical delivery contracts, which are defined as commodity derivative contracts under SFAS No. 133. We also utilize other financial derivatives, primarily swaps, options and futures, to hedge our price risks. Accordingly, proper accounting for these contracts is very important to our overall ability to report timely and accurate financial results.

      We have 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 conditions and material weaknesses in fiscal 2004 and 2005, we are continuing to work to improve our internal controls, particularly in the area of energy accounting. We cannot be certain that these measures will ensure that we implement and maintain adequate controls over our financial processes and reporting in the future. Any failure to implement required new or improved controls, or difficulties encountered in their implementation, could harm our operating results or cause us to fail to meet our reporting obligations. Inferior internal controls could also cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our stock.

      As directed by Section 404 of the Sarbanes-Oxley Act of 2002, the Securities and Exchange Commission adopted rules requiring public companies to include a report of management on our internal controls over financial reporting in our Annual Reports on Form 10-K that contains an assessment by management of the effectiveness of our internal controls over financial reporting. In addition, our independent auditors must attest to and report on management’s assessment of the effectiveness of our internal controls over financial reporting. This requirement may first apply to our Annual Report on Form 10-K for the fiscal year ending July 31, 2006 if the aggregate market value of the voting and non-voting common equity held by non-affiliates is $75 million or more as of the last business day of January 2006. If not, such requirement will first apply to our Annual Report on Form 10-K for the fiscal year ending July 31, 2007. 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 October 31, 2005. We anticipate that improvements will continue to be made.

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

      There have been no material changes to information called for by this Item 3 from the disclosures set forth in Part II, Item 7A in the Company’s Annual Report on Form 10-K for the year ended July 31, 2005.

      As of October 31, 2005, we had 90% of our forecasted fixed-priced energy load through July 31, 2006 covered through either fixed price power purchases with counterparties, or price protected through financial hedges.

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

      Our Chief Executive Officer and our Chief Financial Officer have concluded, based upon their evaluation as of the end of the period covered by this report, that our disclosure controls and procedures (as defined under Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) are effective to ensure that all information required to be disclosed by the Company in the reports filed or submitted by it under the 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 Chief Executive Officer and the Chief Financial Officer, as appropriate, and allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

      We believe that the change to our internal control over financial reporting designed to address the deficiencies related to the application of Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended (SFAS No. 133), the implementation of which commenced and was completed during the first quarter of fiscal 2006, has materially affected our internal control over financial reporting. There were no other material changes in our internal controls over financial reporting that occurred during the first quarter of fiscal 2006 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

Item 6. Exhibits.

      The exhibits listed below are hereby filed with the Commission as part of this Report.

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.

EXHIBIT INDEX

      The exhibits listed below are hereby filed with the Commission as part of this Report.