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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-Q

Commission File Number: 000-33069

COMMONWEALTH ENERGY CORPORATION

15901 Red Hill Avenue, Suite 100, Tustin, California 92780
(Address of principal executive offices) (Zip Code)

(714) 258-0470
(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.    x Yes    o No

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

As of February 28, 2003, 27,644,567 shares of the registrant’s common stock were outstanding.

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COMMONWEALTH ENERGY CORPORATION

Form 10-Q

For the Period Ended January 31, 2003

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FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended, reflecting management’s current expectations. Examples of such forward-looking statements include the expectations of the Company with respect to its strategy, expansion opportunities, extension of our business model, customer demand, completion of acquisitions and future growth. Although the Company believes that its expectations are based upon reasonable assumptions, there can be no assurances that the Company’s financial goals will be realized. Such forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause the actual results, performance or achievements of the Company, or industry results, to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Numerous factors may affect the Company’s actual results and may cause results to differ materially from those expressed in forward-looking statements made by or on behalf of the Company. For this purpose, any statements contained herein that are not statements of historical fact may be deemed to be forward-looking statements. Without limiting the foregoing, the words, “believes,” “anticipates,” “plans,” “expects” and similar expressions are intended to identify forward-looking statements. Factors that may cause such differences include: (a) regulatory changes in the states in which the Company operates that could adversely affect our operations; (b) our continued ability to obtain and maintain licenses from the states in which the Company operates; (c) the competitive restructuring of retail marketing may prevent the Company from selling electricity in certain states; (d) our dependence upon a limited number of third parties to (i) generate and supply to us electricity and (ii) to timely perform their contracts with us; (e) our dependence upon a limited number of utilities to (i) transmit and distribute the electricity the Company sells to its customers and (ii) to timely perform their contracts with us, and (f) the Company’s ability to obtain credit necessary to support future growth and profitability. Other important factors discussed in Part I, Item 2, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Factors That May Affect Future Results”, herein, among others, could cause actual results to differ materially from those indicated by forward-looking statements made herein and presented elsewhere by management. Such forward-looking statements represent management’s current expectations and are inherently uncertain. Investors are warned that actual results may differ from management’s expectations. The Company assumes no obligation to update the forward-looking information to reflect actual results or changes in the factors affecting such forward-looking information.

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PART I — FINANCIAL INFORMATION

Item 1. Financial Statements.

COMMONWEALTH ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

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

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COMMONWEALTH ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

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

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COMMONWEALTH ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

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

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COMMONWEALTH ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
JANUARY 31, 2003
(Unaudited)

1. Summary of Significant Accounting Policies

Description of Business

     Commonwealth Energy Corporation (the “Company”) was incorporated on August 15, 1997. The Company’s primary business has been the sale of electric power to retail customers in California, Pennsylvania and, beginning September 2002, in Michigan. In August 2000, the Company began to sell its excess electric power to wholesale customers in California and Pennsylvania. The Company is licensed by the Federal Energy Regulatory Commission (FERC) as a power marketer, by California as an Electric Service Provider, by Pennsylvania as an Electric Generation Supplier and by Michigan as an Alternate Electric Supplier. The Company plans to enter new deregulated electric power markets in the future.

     The electric power sold by the Company to its retail customers is delivered to the Company’s customers by incumbent utilities that are called Utility Distribution Companies ("UDCs") in California and Michigan and an Electric Distribution Company ("EDC") in Pennsylvania. These incumbent utilities measure electric power usage by the Company’s customers and bill the customers on behalf of the Company. There are three UDCs in California, one EDC in Pennsylvania and one UDC in Michigan which conduct these activities on behalf of the Company.

     The Company’s operations have been in one reportable segment, the domestic electricity distribution industry.

Basis of Presentation

     The condensed consolidated interim financial statements of the Company include the accounts of the Company’s wholly-owned subsidiaries and Summit Energy Ventures, LLC (“Summit”). All intercompany transactions have been eliminated in consolidation.

     The condensed consolidated interim financial statements as of January 31, 2003 and for the three and six month periods ended January 31, 2002 and 2003 are unaudited but, in the opinion of management, have been prepared on the same basis as the audited financial statements and reflect all adjustments, consisting of normal recurring accruals necessary for a fair presentation of the information set forth therein. The results of operations for the three and nine month periods ended January 31, 2003 are not necessarily indicative of the operating results to be expected for the full year or any other period.

     These financial statements have been prepared by the Company pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to such regulations, although the Company believes the disclosures provided are adequate to prevent the information presented from being misleading.

     This report on Form 10-Q for the quarter ended January 31, 2003 should be read in conjunction with the audited consolidated financial statements presented in the Company’s Annual Report on Form 10-K for the year ended July 31, 2002.

Estimates and Assumptions

     The preparation of financial statements in conformity with generally accepted accounting principles in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates in the Company’s consolidated financial statements relate to allowance for doubtful accounts, unbilled receivables, independent system operator costs, and legal claims. Actual results could differ from those estimates.

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Revenue and Cost Recognition

     Net revenue from sales of electric power is recognized as the power is delivered to the Company’s customers. Net revenue represents proceeds from energy sales. Direct energy costs include electric power purchased, independent system operator (“ISO”) fees and scheduling coordination fees. The actual ISO costs are not finalized until a settlement process by the ISO is performed of each day’s activities for all grid participants. Prior to the completion of settlement, the Company estimates and accrues for these costs based on preliminary settlement information. Selling and marketing expenses include salaries of sales and marketing personnel and promotional and advertising costs. General and administrative expenses include salaries for corporate support personnel, rent expenses, insurance expenses, bad debt expenses, depreciation expenses and other costs of the corporate office.

     The Company’s net revenue, including green power credits, is derived from sales to the following classes of customers:

Unbilled Receivables

     The Company’s customers are billed monthly at various dates throughout the month. Unbilled receivables represent the amount of electric power delivered to customers at the end of a period, but not yet billed. Unbilled receivables from sales in California are estimated by the Company to be the number of kilowatt hours delivered times 95% of the individual Utility Purchased Energy cost, as published by each individual utility. Unbilled receivables from sales in Pennsylvania and Michigan are estimated in the same manner, except using the average current customer sales price per kilowatt-hour.

Cash and Cash Equivalents

     Cash and cash equivalents consist of cash and short-term investments with original maturities of three months or less.

Property and Equipment

     Property and equipment are carried at cost. Depreciation of property and equipment is provided over their estimated useful lives, generally five to ten years, using the straight-line method. Expenditures for maintenance, repairs and renewals are expensed as incurred. The Company capitalizes certain software development costs incurred on significant projects for internal use in accordance with provision of AICPA Statement of Position 98-1, Accounting for Software Costs. Qualifying internal and external costs, consisting primarily of third-party system development costs incurred during the application development stage are capitalized and amortized on the straight-line method over five years.

Intangible Assets

     Intangible assets are carried at cost. Amortization of intangible assets is provided over their estimated useful life of 2 and 20 years.

Income Taxes

     The Company utilized the liability method of accounting for income taxes as set forth in FASB Statement No. 109, Accounting for Income Taxes. Under the liability method, deferred taxes are determined based on the differences between the financial statement and tax bases of assets and liabilities using currently enacted tax rates.

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Stock-Based Compensation

     At January 31, 2003, the Company has one stock-based employee compensation plan, which is described more fully in Note 8. The Company accounts for this plan under the recognition and measurement principles of APB Opinion No. 25, Accounting for Stock Issued to Employees, and related Interpretations. No stock-based employee compensation costs is reflected in net income for the three and six month periods ending January 31, 2003, as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of grant. The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of FASB Statement No. 123, Accounting for Stock-Based Compensation, to stock-based employee compensation.

Concentration of Credit Risk

     The Company’s concentration of credit risk with respect to accounts receivable is limited due to the large number of customers who are spread primarily throughout California, Pennsylvania and Michigan. In addition, the Company maintains allowances for potential credit losses.

     As of January 31, 2003, 77.1% of the Company’s billed and unbilled receivables are due from a large number of residential and commercial end users in California, Pennsylvania and Michigan who are billed by and make remittances to the UDC’s or the EDC that deliver their electricity which, in turn, forward such remittances to the Company. One of the UDC’s, Pacific Gas and Electric (PG&E), filed for bankruptcy in April 2001 and has withheld from payment to the Company a portion of the remittances due to the Company. The Company has filed a Proof of Claim in PG&E’s bankruptcy proceedings to recover these amounts which approximated $1,104,000 at January 31, 2003. The Company has provided fully for these disputed amounts in its allowance for doubtful accounts. The Company does not have any similar disputes with its other UDC’s.

     The remainder of the Company’s billed and unbilled accounts receivable represent the Company’s direct billing of certain large commercial and industrial customers amounting to $4,260,059. The Company also has receivables from two wholesale customers in the amount of $229,004.

     No customer has accounted for more than 10% of net revenue in the three and six months ended January 31, 2003. During the six months ended January 31, 2003, wholesale energy sales to PJM Interconnection in Pennsylvania represented approximately 12% of the Company’s total net revenue.

Reent Accounting Pronouncements

     On December 31, 2002, the Financial Accounting Standards Board issued FASB Statement No. 148, Accounting for Stock-Based Compensation — Transition and Disclosure (Statement 148). Statement 148 amends FASB Statement No. 123, Accounting for Stock-Based Compensation (Statement 123), to provide alternative methods of transition to Statement 123’s fair value method of accounting for stock-based employee compensation. Statement 148 also amends the disclosure provisions of Statement 123 and APB Opinion No. 28, Interim Financial Reporting, to require disclosure in the summary of significant accounting policies of the effects of an entity’s accounting policy

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with respect to stock-based employee compensation on reported net income and earnings per share in annual and interim financial statements. While Statement 148 does not amend Statement 123 to require companies to account for employee stock options using the fair value method, the disclosure provisions of Statement 148 are applicable to all companies with stock-based employee compensation, regardless of whether they account for that compensation using the fair value method of Statement 123 or the intrinsic value method of Opinion 25. The Company has adopted Statement 148 as of January 31, 2003.

2. Market and Regulatory Risks

California Deregulated Electric Power Markets

     California has been experiencing extreme fluctuations in the cost of wholesale energy since May 2000. During the summer of 2000 and winter of 2001, the price of electricity in wholesale markets reached unprecedented highs. Since the winter of 2001, the price of electricity has returned to near historical levels. In reaction to this crisis, FERC, the California Public Utilities Commission (“CPUC”), the State Legislature and the Governor have proposed a varying number of methods to help restore price stability to the California electricity marketplace. On September 20, 2001, the CPUC issued a ruling suspending “direct access” pursuant to legislation by the California state legislature requiring the CPUC to suspend “direct access” in California. The suspension of “direct access” means that retail electricity suppliers, such as the Company, will not be allowed to actively seek non direct access customers. This ruling permits the Company to keep its current customer base and continue to sign other direct access customers from other providers, but prohibits the Company from signing up new non direct access customers for an undetermined period of time. The Company is actively seeking relief from this ruling.

     In July 2002, the CPUC issued an interim order implementing a Historical Procurement Charge (“HPC”) sought by Southern California Edison (“SCE”). The interim order authorizes SCE to collect $391 million in HPC charges from all DA customers by reducing their Procured Energy Credit (“PE Credit”) $0.027 per kWh beginning July 27, 2002. The lowered PE Credit will continue until an exit fee for direct access (“DA”) customers has been approved by the CPUC, which will then be reduced to $0.01 per kWh until the $391 million is fully collected. For the six months ended January 31, 2003, the HPC charges have impacted the Company’s pretax earnings by a range of $2.6 million to $3.4 million and the Company believes this trend will continue in the same range for the remainder of this fiscal year. The Company is unable to precisely determine the actual HPC charges applied to its customers by SCE because there are different charges by type of customer and this charge is only on the electricity usage above the monthly baseline amount. While these charges have a significant impact on the Company’s revenue and cash flow, the Company does not expect that it will preclude it from participating in the California market. SCE is currently seeking to change the terms of the interim order to seek to recover additional procurement shortfall revenue by increasing the HPC. The CPUC has not yet made a determination with respect to SCE’s request.

Commitments to Purchase Electric Power

     For the California market, the Company’s primary purchase contract with Calpine Power Services Company, to acquire 3,000 MGH of electric power per day expired on June 30, 2002. The Company has entered into a series of new contracts to purchase electricity energy covering approximately 55% of the current load servicing requirements. The Company is obligated to minimum electric purchases of $10.0 million for the year ending July 31, 2003 under these commitments.

     For the Pennsylvania market, the Company has entered into various contractual arrangements for the purchase of electric power through May 2004. The Company is obligated to minimum electric power purchases of $16.1 million for the year ending July 31, 2003, and $20.1 million thereafter under these contracts.

     For the Michigan market, the Company has entered into a two year contract with DTE Energy Trading to purchase the full requirements service product to service the Company’s customer load. This full requirements service product includes energy and all scheduling costs. The Company is obligated to purchase 50 megawatt hours per month.

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     Since the price at which the Company can purchase electric power is fixed during the terms of the contracts, if the price at which the Company can resell this electric power falls below the contract purchase price plus distribution and scheduling costs, the Company would incur operating losses during such periods.

Pennsylvania Operations

     In accordance with its standard customer contract in Pennsylvania, the Company may only charge certain maximum rates for its sales of electric power which, at times, could be less than the Company’s costs of acquiring, distributing and scheduling such electric power. Energy capacity charges for servicing electric power in Pennsylvania market varies significantly from month to month and can affect gross profit margins.

California Green Power Credits

The State of California enacted the Public Purpose Program which established a $540 million fund to provide overall incentives to suppliers of “green” power to initially reduce, among other things, the net costs of such power to certain consumers by $0.015 per kWh which effective July 31, 2000, has been at a rate $0.01 per kWh. The Company received green power credits of $858,629 and $2,072,963 for the three and six months ended January 31, 2002, respectively which were included in the Company’s net revenue. The benefit of these credits was passed through to the Company’s customers in the form of discounted electricity rates. The green power credit program expired December 2001. Nevertheless, the Company has continued to sell electricity to these customers at the discounted rate. The Company did not receive green power credits for the three months ended January 31, 2003. The California legislature is considering legislation which could result in the payment of back green power credits from the date of the expiration of the program in 2001. However, the legislature may also permanently terminate the payment of green power credits for customers and/or use green power credits as incentive to those who produce green power. Until the California legislature acts, there can be no assurance whether the Company will receive any future revenues from the green power credit program.

3. Per Share Information

     The amount of net income used in the calculations of basic and diluted net income per common share includes cumulative preferred dividend requirements of $15,225 and $17,300 for the three months ended January 31, 2003 and 2002, respectively and $32,525 and $35,954 for the six months ended January 31, 2003 and 2002, respectively.

     Basic and diluted net income per common share is computed as follows:

     For all periods presented, the effects of stock options with exercise prices in excess of the estimated fair value of the Company’s common stock and of the exercise of warrants have been excluded from the calculation of diluted earnings per share because the effect of their inclusion would be anti-dilutive.

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4. Investment in Summit Energy Ventures, LLC

     In July 2001, the Company formed Summit Energy Ventures, LLC (“Summit”), a joint venture with Steven Strasser. Summit was formed to enable the Company to diversify its business by making investments in companies that manufacture products that conserve or manage electricity. In July 2001, Commonwealth made the initial capital contribution of $15,000,000 into Summit, which, to date, represents the entire capital contribution to Summit. If Summit invests 75% of the initial $15,000,000 investment, the Company may, solely at its discretion, invest up to an additional $10,000,000 in Summit. For purposes of financial reporting, the consolidated financial statements of the Company include the accounts of Summit as well as those of the Company’s wholly-owned subsidiaries.

     The Company’s joint venture partner in Summit, Steven Strasser, is the president and sole shareholder in Northwest Power Management (“NPM”), the investment manager of Summit. NPM is responsible for managing the funds that the Company has invested in Summit. All investments must be approved by Summit’s investment committee, which is comprised of three individuals, all of whom are appointed by Commonwealth. NPM manages the investment until such time as a decision to sell is made. When a sale of an investment to a third-party buyer is proposed, the Company has the option to buy out Summit’s interest in a specific investment on the same terms as the third-party buyer. The Company pays an annual management fee of $700,000 to the investment manager.

     The Company owns 100% of the preferred membership interest of Summit and 60% of the common membership interest. Steven Strasser owns the other 40% of the common membership interest. The Company’s preferred membership interest entitles the Company to a distribution preference equal to all of the Company’s initial invested capital plus an annual 10% preferred return before any funds are distributed to the holders of the common membership interests; net losses are allocated in accordance with capital contributions. In addition, the Company, as the preferred member, has a right of first refusal in the event of any issuances of new members interests and the right to purchase any of the investments acquired by Summit at any time during the agreement on terms mutually agreeable to both the investment manager and the Company.

     Summit is to exist through June 29, 2006, which date may be extended for up to two additional one year periods by mutual agreement of the parties. Because the Company appoints all of the members of the Summit Investment Committee, and, therefore, controls Summit’s investments, Summit's financial statements are included in the Company’s consolidated financial statements.

     Through January 31, 2003, Summit had made original investments in three energy related companies as follows:

     Based on the percentage ownership levels, the Company accounts for Envenergy, Inc. at cost as an available for sale equity investment, and Turbocor, LLC and Power Efficiency Corporation under the equity method (“APB 18”). Under the equity method of accounting, the Company reports their proportionate amount of income and losses from the investment companies.

     Condensed balance sheet information for Summit at January 31, 2003 and July 31, 2002, which is included in the Company’s consolidated financial statements, is as follows:

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     The effect of Summit’s results of operations for the three months ended January 31, 2003 on the Company’s consolidated results of operations was a net loss of $0.3 million, comprised of $0.1 million of losses in investment companies, $0.2 million of investment management fees paid.

5. Other Current Liabilities

     Other current liabilities are comprised of the following at January 31, 2003 and July 31, 2002:

6. Property and Equipment, Net

     Property and equipment, net is comprised of the following at January 31, 2003 and July 31, 2002:

7. Restricted Cash and Intangible Assets

Restricted Cash

     Restricted cash consists of the following at January 31, 2003 and July 31, 2002:

     The Company is required to pledge an amount equivalent to 45 days of energy purchases under certain contracts for the purchase of electric power. The funds in Summit are committed to the purpose of investing in energy and energy related companies.

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Intangible Assets

     The Company’s intangible assets represent the net unamortized costs of purchasing, in July 1999, the 1-800-Electric telephone number and the rights to eight internet domain names. The initial cost of these intangible assets was $1.05 million. Amortization expense for these intangible assets was $26,250 for each of the six month periods ended January 31, 2003 and 2002.

     In November 2001, the Company purchased certain rights to hire employees and contractors of their primary information technology vendor, Symcas Technical Services Group, Inc., doing business as Symcas-TSG (“Symcas”). The purchase agreement contained a covenant not to compete prohibiting the principals of Symcas from competing with the Company’s software product or directly or indirectly assisting others to develop a software product similar to the Company’s software product for a period of two years. The cost of $303,028 related to this covenant was capitalized as an intangible asset and is scheduled to be amortized over the two year period ending November 9, 2003. Amortization expense for this intangible asset was $50,505 and $84,175 for the three and six month periods ended January 31, 2003.

8. Shareholders’ Equity

Convertible Preferred Stock

     The Company’s Series A Convertible Preferred Stock provides cumulative dividends which accrue at an annual rate of 10% which are payable when, as and if declared by the Company’s Board of Directors. On December 20, 2002, the Company paid a cash dividend of $0.15 per share on its outstanding Series A Convertible Preferred Stock to the holders of record of the Company’s Series A Convertible Preferred Stock as of December 16, 2002. Cumulative unpaid dividends were $68,395 as of January 31, 2003. Each convertible preferred share is convertible into one share of the Company’s common stock at the shareholder’s discretion and has full voting rights. In addition, preferred shareholders are entitled to preferential liquidation rights over common stock in the amount of $1.00 per share plus an amount equal to all declared but unpaid dividends.

Common Stock

     At January 31, 2003, the Company has reserved the following shares of its common stock for issuance upon conversion of the issued and outstanding shares of convertible preferred stock, exercise of warrants and exercise of outstanding stock options:

Adjustment of Number of Outstanding shares of Series A Preferred and Common Stock

     In December 2002, the Company determined that 166,000 shares of Series A Convertible Preferred Stock and 166,000 shares of Common Stock that had previously been treated as outstanding had not been validly issued. As a result, these shares were removed from the records of the Company and the Company has determined that such shares shall no longer be treated as issued and outstanding for any purpose. Accordingly, the Company has corrected its prior years’ financial statements to reflect the cancellation of 166,000 shares of Series A Preferred and 166,000 shares of Common Stock. The correction does not impact the Company’s financial statements or reported earnings per share.

Stock Options

     The Company’s Board of Directors has approved grants of options to acquire a total of 13,206,325 shares of the Company’s Common Stock to the Company’s employees, outside directors and service providers. As of January 31, 2003, 7,066,500 of these stock options were outstanding.

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     Stock option activity for the six months ended January 31, 2003 is set forth below:

     The Company’s 1999 Equity Incentive Plan (“Plan”) approved by the shareholders provides for the granting of stock options for up to an aggregate of 7,000,000 shares of Common Stock of the Company. In addition, the Company’s Board of Directors has from time to time made individual grants of warrants or options outside the Plan. At January 31, 2003, the Company had granted options to purchase 2,804,500 shares under the Plan and granted options to purchase 4,247,000 shares of Common Stock outside the Plan, in each case after giving effect to expirations and cancellations.

Warrants

     As part of the $15 million credit line agreement dated June 29, 2000, which expired June 29, 2002, the lender received warrants to purchase 100,000 shares of common stock. The warrants are exercisable at $5.50 per share and expire on June 29, 2003. The fair value of the warrants was nominal at their date of issuance.

9. Income Taxes

     For the six months ended January 31, 2003, the Company’s provision for income taxes was comprised of the following:

     The Company’s net deferred tax asset as of January 31, 2003 was $4,848,481 and is net of a valuation allowance of $819,333. Deferred income taxes reflect the net effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes.

     At July 31, 2002, the Company had net operating loss carryforwards of approximately $2,330,000 and $2,071,000 for federal and state income tax purposes, respectively, that begin to expire in years 2018 and 2006, respectively. The timing of the utilization of federal net operating loss carryforwards is subject to an annual limitation due to the “change of ownership” provision of the Tax Reform Act of 1986. As a result of the annual limitation, a portion of these carryforwards may expire before ultimately becoming available to reduce future income tax liabilities.

     On September 11, 2002, the Governor of California signed into law new tax legislation that suspends the use of net operating loss carryforwards into tax years beginning on or after January 1, 2002 and 2003. Should the Company have taxable income for the year ending July 31, 2003, it may utilize to California net operating losses generated in prior years to offset taxable income with respect to income taxes due in California. This suspension will not apply to tax years beginning on or after 2004.

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10. Commitments and Contingencies

Litigation

     From time to time, the Company is involved in legal proceedings, claims, and litigation arising in the ordinary course of business. Management does not believe the outcome of these matters will have a material effect on the Company’s financial condition or its results of operations.

11. Related Party Transactions

     On November 9, 2001, the Company purchased certain rights to hire employees and contractors of their primary information technology vendor, Symcas. Additionally, as part of the same agreement, Symcas transferred interest in and to all of the software that Symcas has developed for the Company. The purchase agreement contained a covenant not to compete prohibiting the principals of Symcas from competing with the Company’s software product or directly or indirectly assisting others to develop a software product similar to the Company’s software product for a period of two years. Symcas previously performed substantially all of the Company’s software development information technology support and maintenance, and procurement of hardware and software. On December 15, 2001, after the close of the agreement with Symcas, the Company hired Linda Guckert, an employee and officer of Symcas, to be the Company’s Vice President of Information Technology. The Company continues to utilize Symcas on a limited basis for its IT maintenance. For the three and six month periods ended January 31, 2003, the Company paid to Symcas a total of $77,987 and $481,175, respectively.

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

     The primary business of Commonwealth Energy Corporation (“Commonwealth”) has been the sale of electric power to residential and commercial end-users in California, Pennsylvania and, beginning in September 2002, in Michigan and the sale of electric power to wholesale customers in California and Pennsylvania. Commonwealth is licensed by Federal Energy Regulatory Commission (“FERC”) as a power marketer and by the California, Michigan, Pennsylvania, New Jersey, New York, Texas and Ohio public utilities commissions as an electric services or electric generation supplier. As used in this Report, the terms “we”, “us”, “our”, “the Company” and “Commonwealth” refer to Commonwealth Energy Corporation, its wholly-owed subsidiaries and Summit Energy Ventures, LLC (“Summit”).

     As of January 31, 2003, we delivered electricity to approximately 85,400 customers in California, Pennsylvania and Michigan. The growth of this business depends upon the deregulated status of each state, the availability of cost-effective energy purchases to us and the acquisition of retail or commercial customers by us.

     We do not have our own electricity generation facilities. The power we sell to our customers is purchased from third-party power generators under long-term contracts and in the spot market. Throughout most of fiscal 2002, substantially all of our electricity was purchased under long-term contracts. During fiscal 2003, we have purchased 78% of our power under long-term contracts and 22% in the spot market.

Critical Accounting Policies and Estimates

     Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amount of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses for each period.

     The following represents a summary of our critical accounting policies, defined as those policies that we believe are: (a) the most important to the portrayal of our financial condition and results of operations, and (b) that require management’s most difficult, subjective or complex judgments, often as a result of the need to make estimates about the effects of matters that are inherently uncertain.

	•		Independent system operator costs — Included in direct energy costs along with electric power purchased and scheduling coordination costs are the independent system operator (“ISO”) fees. The actual ISO costs are not finalized until a settlement process by the ISO is performed of each day’s activities of all grid participants. Prior to the completion of settlement, 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 record additional costs.
	•		Allowance for doubtful accounts — We maintain allowances for doubtful accounts for estimated losses resulting from non-payment of customer billings. If the financial condition of our customers were to deteriorate, resulting in an impairment of their ability to make payments, additional allowances may be required. In addition, if utilities declare bankruptcy, additionally allowances may be required.
	•		Unbilled receivables — Our customers are billed monthly at various dates throughout the month. Unbilled receivables represent the amount of electric power delivered to customers at the end of a period, but not yet billed. Unbilled receivables from sales in California are estimated by the Company as the number of kilowatt-hours delivered times 95% of the individual Utility Purchased Energy cost as published by each individual utility for residential customers. Unbilled receivables from sales in Pennsylvania and Michigan are estimated in the same manner, except using the average current customer sales price per kilowatt-hour. In addition, the estimate of kilowatt-hours delivered to our customers may vary from the actual settlement amounts, resulting in the need to adjust the unbilled receivable amount.
	•		Legal claims — From time to time, we may be involved in litigation relating to claims arising out of our operations in the normal course of business. 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 Statement of Financial Accounting Standards No. 5, “Accounting for Contingencies.” As additional

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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 its contingencies. Such additional expense could potentially have a material impact on our results of operations and financial position.

     We make our estimates and judgments based on, among other things, knowledge of operations, markets, historical trends and likely future changes, and when appropriate, the opinions of advisors with knowledge and experience in certain fields. However, due to the nature of certain assets and liabilities, there are risks and uncertainties associated with some of the estimates and judgments which are required to be made. Actual results could differ from these estimates under different assumptions or conditions.

Results of Operations

Three months ended January 31, 2003 compared to three months ended January 31, 2002

Retail Energy Sales

     Electricity sales to residential and commercial end-users increased by $10.6 million, or 53.5% to $30.4 million for the three months ended January 31, 2003 from $19.8 million for the three months ended January 31, 2002. The increase resulted from an increase in electricity retail sales in California and Pennsylvania due to the acquisition of commercial end-users that the Company began servicing during fiscal 2002 and our entry into the Michigan market in September 2002. The increase in California electricity retail sales was due primarily to an increase in kilowatt-hours billed offset by a decrease in retail energy prices. The average retail price per kWh in California was $0.073 for the three months ended January 31, 2003 compared to $0.083 for the three months ended January 31, 2002. Total kilowatt hours of electricity billed in California for the three months ended January 31, 2003 was 272.3 million compared to 158.7 million for the three months ended January 31, 2002. The increase in Pennsylvania electricity retail sales was due primarily to an increase in kilowatt-hours billed and retail energy prices. The average retail price per kWh in Pennsylvania for the three months ended January 31, 2003 was $0.058 compared to $0.056 for the three months ended January 31, 2002. Total kilowatt hours of electricity billed in Pennsylvania for the three months ended January 31, 2003 was 169.8 million compared to 98.9 million for the three months ended January 31, 2002. Michigan contributed $1.4 million to the increase in retail energy sales during the three months ended January 31, 2003.

     At January 31, 2003, we had approximately 85,400 customers compared to approximately 90,600 customers at January 31, 2002. The number of customers has decreased as a result of the attrition of residential customers in California and Pennsylvania. These customers have been replaced by commercial and light industrial customers who utilized more kilowatts than the residential customers.

Wholesale energy sales

     Wholesale electricity sales decreased by $4.1 million, or 75.1%, to $1.4 million during the three months ended January 31, 2003 from $5.5 million during the three months ended January 31, 2002. The decrease was primarily attributable to increasing our commercial and industrial customer base which reduced the excess kilowatt-hours that had to be sold in the wholesale market in both California and Pennsylvania. The expiration of the Calpine contract reduced the quantity of contracted energy purchased resulting in a decrease of excess kilowatts available for wholesale. Total kilowatt-hours of wholesale electricity sold in California was 10.2 million during the three months ended January 31, 2003 compared to 110.7 million during the three months ended January 31, 2002. Total kilowatt-hours of wholesale electricity sold in Pennsylvania was 40.7 million during the three months ended January 31, 2003 compared to 149.9 million during the three months ended January 31, 2002. The average wholesale price per kWh in California during the three months ended January 31, 2003 was $0.04 compared to $0.02 during the three months ended January 31, 2002. The average wholesale price per kWh in Pennsylvania was $0.02 compared to $0.02 for each of the three month periods ended January 31, 2003 and 2002.

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Green power credit

     Green power credit revenue represents funds received from the State of California pursuant to the Public Purpose Program, which established a fund to provide overall incentives to suppliers of “green” power. Green power credit revenue decreased by $0.9 million, or 100.0%, to zero for the three months ended January 31, 2003 from $0.9 million for the three months ended January 31, 2002. The green power credit decrease is due to the expiration of the California green power credit program in December 2001. The California legislature is considering legislation which could result in the payment of back green power credits from the date of the expiration of the program in 2001. However, the legislature may also permanently terminate the payment of green power credits for customers and/or use green power credits as incentive to those who produce green power. Until the California legislature acts, there can be no assurance whether the Company will receive any future revenues from the green power credit program.

Direct energy costs

     Direct energy costs consist of the cost of electric power, scheduling and ISO costs. Direct energy costs increased to $23.9 million for the three months ended January 31, 2003, an increase of $5.6 million, or 31.1%, from $18.3 million for the three months ended January 31, 2002. The increase is the result of increased direct energy costs in California and Michigan during the three months ended January 31, 2003, partially offset by decreased direct energy costs in Pennsylvania. Michigan contributed $1.1 million to the increase in direct energy costs. The increase in direct energy costs in California was due to an increase in the price paid by the Company per kWh purchased, partially offset by a decrease in kilowatt-hours acquired. Total kilowatt-hours purchased in California during the three months ended January 31, 2003 was 273.3 million, at an average price of $0.04 per kWh compared to purchases made during the three months ended January 31, 2002 of 298.1 million at an average price of $0.03 per kWh. Spot market purchases in California were $1.4 million during the three months ended January 31, 2003 compared to $0.4 million during the three months ended January 31, 2002 also contributing to the increase in direct energy costs. The decrease in direct energy costs in Pennsylvania resulted from a decrease in the number of kilowatt-hours purchased. The decrease in kilowatt-hours purchased was due primarily to the expiration of an energy contract that was not replaced. Total kilowatt-hours purchased in Pennsylvania during the three months ended January 31, 2003 was 226.2 million at an average price of $0.04 per kWh compared to purchases during the three months ended January 31, 2002 of 257.4 million kilowatt-hours at an average price of $0.04 per kWh. An increase in scheduling costs to deliver energy to our customers in California and Pennsylvania also contributed to the increase in direct energy costs. California scheduling costs increased to $0.8 million for the three months ended January 31, 2003 from negative $2.4 million for the three months ended January 31, 2002. Pennsylvania scheduling costs increased to $1.5 million for the three months ended January 31, 2003 from $1.0 million for the three months ended January 31, 2002.

Selling and marketing expenses

     Selling and marketing expenses increased $0.1 million, or 12.4%, to $1.0 million for the three months ended January 31, 2003 from $0.9 million for the three months ended January 31, 2002. The increase is primarily a result of an increase in marketing activities as the Company entered the Michigan market. Marketing and payroll costs increased by $0.1 million due to the establishment of a Michigan sales office.

General and administrative expenses

     General and administrative expenses increased to $6.1 million for the three months ended January 31, 2003, an increase of $0.8 million, or 14.3% from $5.3 million for the three months ended January 31, 2002. This increase was primarily the result of increased legal expenses of $0.5 million, Pennsylvania gross receipt taxes of $0.4 million, amortization expense of $0.1 million, bad debt expense of $0.1 million and insurance costs of $0.1 million. These increases were offset by a decrease in payroll expenses of $0.5 million. The increase in legal expenses was related to increased litigation defense costs in the David James, et al and Joseph Saline cases, and costs related to the most recent proxy contest. Pennsylvania gross receipts tax increased due to the increase in retail sales in Pennsylvania. The increase in amortization expense was the result of software development costs for the TRIUMPH system. The increase in bad debt expense was the result of higher billings due to increased retail sales. Insurance expense increased as a result of higher premiums for directors and officers insurance. The decrease in payroll expenses was the result of bonuses paid during the three months ended January 31, 2002 which were not paid during the three months ended January 31, 2003.

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Interest income, net

     Interest income decreased by less than $0.1 million, or 12.1% to $0.2 million for the three months ended January 31, 2003 from $0.3 million for the three months ended January 31, 2002. The decrease was attributable to the decrease in cash flow available for investments provided from operations and by lower yields on short-term investments during the three months ended January 31, 2003.

Equity Investments

     We recorded a loss in our equity investments in Summit of $0.1 million for the three months ended January 31, 2003 compared to no income or loss for the three months ended January 31, 2002. The loss on equity investments related to a decrease in the value of Summit’s percentage ownership in Power Efficiency Corporation which is accounted for under the equity method.

Provision for income taxes

     The provision for income taxes decreased by $0.7 million, or 78.7%, to $0.2 million for the three months ended January 31, 2003 compared to $0.9 million for the three months ended January 31, 2002. The decrease was due primarily to the decrease in net income before taxes to $0.8 million for the three months ended January 31, 2003 compared to $2.0 million for the three months ended January 31, 2002. This decrease was partially offset by an increase in the tax provision rate to 42% for the three months ended January 31, 2003 from 36% for the three months ended January 31, 2002.

Net income

     Net income decreased to $0.6 million for the three months ended January 31, 2003, a decrease of $0.5 million, or 36.4%, from the $1.1 million net income for the three months ended January 31, 2002. This decrease in net income was primarily attributable to increases of $0.1 in gross margin, $0.1 in selling and marketing expenses, $0.8 in general and administrative expenses, $0.1 in stock based compensation, and $0.1 loss in equity investments, offset by a decrease of $0.7 in tax provisions.

Six months ended January 31, 2003 compared to six months ended January 31, 2002

Retail Energy Sales

     Electricity sales to residential and commercial end-users increased by $24.2 million, or 62.8% to $62.7 million for the six months ended January 31, 2003 from $38.5 million for the six months ended January 31, 2002. The increase resulted from an increase in electricity retail sales in California and Pennsylvania due to the acquisition of commercial end-users that the Company began servicing during fiscal 2002 and our entry into the Michigan market in September 2002. The increase in California electricity retail sales was due primarily to an increase in kilowatt-hours billed offset by a decrease in retail energy prices. The average retail price per kWh in California was $.077 for the six months ended January 31, 2003 compared to $.085 for the six months ended January 31, 2002. Total kilowatt hours of electricity billed in California for the six months ended January 31, 2003 was 554.1 million compared to 303.6 million for the six months ended January 31, 2002. The increase in Pennsylvania electricity retail sales was due primarily to an increase in kilowatt-hours billed and retail energy prices. The average retail price per kWh in Pennsylvania for the six months ended January 31, 2003 was $.057 compared to $.056 for the six months ended January 31, 2002. Total kilowatt hours of electricity billed in Pennsylvania for the six months ended January 31, 2003 was 375.0 million compared to 217.5 million for the six months ended January 31, 2002. Michigan contributed $1.6 million to the increase in retail energy sales during the six months ended January 31, 2003.

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Wholesale energy sales

     Wholesale electricity sales decreased by $11.1 million, or 79.8%, to $2.8 million during the six months ended January 31, 2003 from $13.8 million during the six months ended January 31, 2002. The decrease was primarily attributable to increasing our commercial and industrial customer base which reduced the excess kilowatt-hours that had to be sold in the wholesale market in both California and Pennsylvania. The expiration of the Calpine contract reduced the quantity of contracted energy purchased resulting in a decrease of excess kilowatts available for wholesale. Total kilowatt-hours of wholesale electricity sold in California was 36.5 million during the six months ended January 31, 2003 compared to 228.7 million during the six months ended January 31, 2002. Total kilowatt-hours of wholesale electricity sold in Pennsylvania was 74.5 million during the six months ended January 31, 2003 compared to 318.2 million during the six months ended January 31, 2002. The average wholesale price per kWh in California during the six months ended January 31, 2003 was $0.03 compared to $0.02 during the six months ended January 31, 2002. The average wholesale price per kWh in Pennsylvania during the six months ended January 31, 2003 was $0.02 compared to $0.03 during the six months ended January 31, 2002.

Green power credit

     Green power credit revenue decreased by $2.1 million, or 100.0%, from $2.1 million for the six months ended January 31, 2002 to zero for the six months ended January 31, 2003. The green power credit decrease is due to the expiration of the green power credit program in December 2001. The California legislature is considering legislation which could result in the payment of back green power credits from the date of the expiration of the program in 2001. However, the legislature may also permanently terminate the payment of green power credits for customers and/or use green power credits as incentive to those who produce green power. Until the California legislature acts, there can be no assurance whether the Company will receive any future revenues from the green power credit program.

Direct energy costs

     Direct energy costs consist of the cost of electric power, scheduling and ISO costs. Direct energy costs increased to $49.4 million for the six months ended January 31, 2003, an increase of $6.3 million, or 14.7%, from $43.1 million for the six months ended January 31, 2002. The increase is the result of increased direct energy costs in California and Michigan during the six months ended January 31, 2003, partially offset by decreased direct energy costs in Pennsylvania. Michigan contributed $1.2 million to the increase in direct energy costs. The increase in direct energy costs in California was due to an increase in the price paid by the Company per kWh purchased, partially offset by a decrease in kilowatt-hours acquired. Total kilowatt-hours purchased in California during the six months ended January 31, 2003 was 589.6 million, at an average price of $0.04 per kWh compared to purchases made during the six months ended January 31, 2002 of 587.7 million at an average price of $0.03 per kWh. Spot market purchases in California were $1.6 million during the six months ended January 31, 2003 compared to spot market sales of $0.1 million during the six months ended January 31, 2002 also contributing to the increase in direct energy costs. The decrease in direct energy costs in Pennsylvania resulted from a decrease in the number of kilowatt-hours purchased. The decrease in kilowatt-hours purchased was due primarily to the expiration of an energy contract that was not replaced. Total kilowatt-hours purchased in Pennsylvania during the six months ended January 31, 2003 was 458.4 million at an average price of $0.04 per kWh compared to purchases during the six months ended January 31, 2002 of 542.7 million kilowatt-hours at an average price of $0.04 per kWh. An increase in scheduling costs for energy delivered to our customers in California offset by decreased scheduling costs in Pennsylvania also contributed to the increase in direct energy costs. California scheduling costs increased to $1.4 million for the six months ended January 31, 2003 from negative $1.8 million for the six months ended January 31, 2002. California scheduling costs were higher during the six months ended January 31, 2003 due to a settlement of ISO costs below prior estimates during the six months ended January 31, 2002. Pennsylvania scheduling costs decreased to $3.8 million for the six months ended January 31, 2003 from $4.2 million for the six months ended January 31, 2002. The decrease was due primarily to the reduction in capacity costs for the six months ended January 31, 2003 compared to January 31, 2002.

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Selling and marketing expenses

     Selling and marketing expenses increased $0.5 million, or 30.7%, to $2.3 million for the six months ended January 31, 2003 from $1.8 million for the six months ended January 31, 2002. The increase was primarily a result of an increase of $0.5 million in marketing activities as the Company entered the Michigan market.

General and administrative expenses

     General and administrative expenses increased to $11.5 million for the six months ended January 31, 2003, an increase of $1.3 million, or 12.7% from $10.2 million for the six months ended January 31, 2002. This increase was primarily the result of increased legal expenses of $0.8 million, Pennsylvania gross receipt taxes of $1.0 million, amortization expense of $0.2 million, bad debt expense of $0.1 million and insurance costs of $0.2 million. These increases were offset by a decrease in consulting expenses of $0.3 million. The increase in legal expenses was related to increased litigation defense costs in the David James, et al and Joseph Saline cases, and costs related to the most recent proxy contest. Pennsylvania gross receipts tax increase was due to the increase in retail sales in Pennsylvania. The increase in amortization expense was the result of software development costs for the TRIUMPH system. The increase in bad debt expense was due to higher billings. Insurance expense increased as a result of higher premiums for directors and officers insurance. The decrease in consulting expenses was the result of hiring software development employees who were formerly consultants to the Company.

Interest income, net

     Interest income decreased by $0.2 million, or 27.4% to $0.4 million for the six months ended January 31, 2003 from $0.6 million for the six months ended January 31, 2002. The decrease was attributable to the decrease in cash flow available for investments provided from operations and by lower yields on short-term investments during the six months ended January 31, 2003.

Equity Investments

     We recorded a loss in our equity investments in Summit of $0.4 million for the six months ended January 31, 2003 compared to no income or loss for the six months ended January 31, 2002. The loss on equity investments related to a decrease in the value of Summit’s percentage ownership in Turbocor, LLC and Power Efficiency Corporation which are accounted for under the equity method.

Litigation awards

     The litigation award was $2.2 million for the six months ended January 31, 2003 compared to no litigation awards for the six months ended January 31, 2002. The litigation award loss related to the jury award in the David James, et al, v. Commonwealth Energy Corporation case. (See Part II, Item 1, “Legal Proceedings”.) Of the $2.7 million awarded on December 10, 2002, $0.5 million had been reserved during fiscal 1999.

Provision for income taxes

     The provision for income taxes decreased by $0.2 million, or 85.0%, to less than $0.1 million for the six months ended January 31, 2003 compared to $0.3 million for the six months ended January 31, 2002. The decrease was due primarily to the decrease in net income before taxes to $0.1 million for the six months ended January 31, 2003 compared to $0.7 million for the six months ended January 31, 2002. This decrease was partially offset by an increase in the tax provision rate to 42% for the six months ended January 31, 2003 from 40% for the six months ended January 31, 2002.

Net income

     Net income decreased to $0.1 million for the six months ended January 31, 2003, a decrease of $0.3 million, or 75%, from the $0.4 million net income for the six months ended January 31, 2002. This decrease in net income was primarily attributable to increases of $2.0 million in general and administrative expenses, $0.5 million in sales and marketing expenses, $0.1 million in net interest income, $2.2 million in losses from the above-referenced litigation

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award, and $0.4 million in losses from the Company’s equity investment in Summit, offset by an increase of $4.7 million in gross margin and a decrease of $0.2 million in tax provisions.

Liquidity and Capital Resources

     As of January 31, 2003, cash and cash equivalents were $49.0 million, compared to $43.0 million at July 31, 2002. Our principal sources of liquidity to fund ongoing operations for the six months ended January 31, 2003 were cash provided by operations and existing cash and cash equivalents.

     Cash flow provided by operations for the six months ended January 31, 2003 was $5.8 million, an increase of $9.5 million compared with cash used in operations for the six months ended January 31, 2002 of $3.7 million. Cash was provided primarily by a decrease in net accounts receivable of $3.4 million, and increases in depreciation and amortization of $0.7 million, provision for doubtful accounts of $0.7 million, accrued expenses of $2.9 million and income taxes payable of $0.9 million. Cash used in operations consisted of decreases in deferred income taxes of $0.9 million, accounts payable of $1.7 million, and increases in deposits and prepaids of $0.5 million.

     Cash flow used in investing activities for the six months ended January 31, 2003 was $0.5 million, a decrease of $5.5 million compared with cash used in investing activities of $6.0 million for the six months ended January 31, 2002. Cash used in investments consisted of $0.3 million for the development of TRIUMPH and acquisition of computer software and $0.1 for acquisition costs related to hiring of Symcas personnel and $0.5 million increase in Turbocor, LLC investment by Summit offset by $0.4 million for Summit’s share of losses in Turborcor, LLC and Power Efficiency Corporation.

     Cash flow provided by financing activities for the six months ended January 31, 2003 was $0.6 million, a decrease of $1.3 million compared to cash provided by $1.9 million for the six months ended January 31, 2002. Interest paid on restricted cash of $0.8 million was offset by cash used in the repurchase of preferred stock of $0.1 million and dividends paid on preferred stock of $0.1 million.

     As a result of market conditions in California during fiscal 2002, the creditworthiness of several participants in the marketplace with whom we conduct business deteriorated significantly. PG&E withheld payments of approximately $1.1 million from its remittances to us. Although we have filed a proof of claim in PG&E’s bankruptcy proceedings to recover these amounts, there is no assurance that we will recover any of the payments withheld. Accordingly, we have established an allowance for doubtful accounts in the amount of these withholdings.

     As of January 31, 2003, $15 million in cash was invested in Summit. Under certain circumstances, we may, at our discretion, invest an additional $10 million in Summit. We are not obligated to make any further investment in Summit. In the event that the investment manager desires to cause Summit to issue membership interests to any other party, we shall have the right of first refusal to make the additional capital contribution on terms not less favorable as those proposed to such other party.

     From time-to-time, the power generator may require us to post security in the form of a letter of credit to hedge against our defaulting on the contract and purchasing lower cost energy on the market. If we are required to post such security a portion of our cash would become restricted, which could adversely affect our liquidity. As of December 31, 2003, we had $7.8 million in restricted cash to secure letters of credit required by our suppliers.

     On January 4, 2002, the Board of Directors of the Company approved a $10 million stock repurchase program. Under this program, the Company may purchase up to $10 million of its common stock, options and warrants, from time to time over an 18 month period, in open market or privately negotiated, subject to market conditions and other factors. As of January 31, 2003, no purchases of common stock, options or warrants have been made pursuant to this authority.

     In July 2002, the California Public Utilities Commission (the “CPUC”) issued an interim order implementing a Historical Procurement Charge (“HPC”) sought by Southern California Edison (“SCE”). The interim order authorizes SCE to collect $391 million in HPC charges from all direct access (“DA”) customers by reducing their Procured Energy Credit (“PE Credit”) to $0.027 per kWh beginning July 27, 2002. The lowered PE Credit will continue until an exit fee for DA customers has been approved by the CPUC,

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which will then be reduced to $0.01 per kWh until the $391 million is fully collected. For the six months ending January 31, 2003, the HPC charges have impacted the Company’s pretax earnings by a range of $2.6 million to $3.4 million and the Company believes this trend will continue in the same range for the remainder of this fiscal year. The Company is unable to precisely determine the actual HPC charges applied to its customers by SCE because there are different charges by type of customer and this charge is only on the electricity usage above the monthly baseline amount. While these charges have a significant impact on the Company’s revenue and cash flow, the Company does not expect that it will preclude it from participating in the California market. SCE is currently seeking to change the terms of the interim order to seek to recover additional procurement shortfall revenue by increasing the HPC. The CPUC has not yet made a determination with respect to SCE’s request.

     The following table shows our contractual cash obligations and commercial commitments as of January 31, 2003: