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10-Q/A 1 a13962a3e10vqza.htm AMENDMENT TO FORM 10-Q e10vqza

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q/ A

(Amendment No. 3)


(Mark One)
þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the quarterly period ended January 31, 2005
OR
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the transition period from to

Commission File Number 001-32239

COMMERCE ENERGY GROUP, INC.

(Exact name of registrant as specified in its charter)


Delaware		20-0501090
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

600 Anton Boulevard, Suite 2000, Costa Mesa, California 92626

(Address of principal executive offices) (Zip Code)

(714) 259-2500

(Registrant’s telephone number, including area code)

Not Applicable

(Former name, former address and former fiscal year, if changed since last report)

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

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

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 March 11, 2005, 31,432,523 shares of the registrant’s common stock were outstanding.

EXPLANATORY NOTE

This quarterly report on Form 10-Q/ A (Amendment No. 3) is being filed by the Company to amend the Company’s quarterly report on Form 10-Q for the quarterly period ended January 31, 2005 filed with the Securities and Exchange Commission on March 17, 2005, as initially amended by Amendment No. 1 filed with the Securities and Exchange Commission on June 14, 2005 (“Amendment No. 1”), and as further amended by Amendment No. 2 filed with the Securities and Exchange Commission on July 12, 2005 (“Amendment No. 2”).

We purchase substantially all of our electricity and natural gas supplies for retail customers utilizing forward physical delivery contracts. Additionally, we utilize financial derivatives, primarily swaps and futures, to minimize earnings fluctuations resulting from commodity price market volatility. These physical and financial contracts are classified as derivatives under Statement of Financial Accounting Standard No. 133, Accounting for Derivative Instruments and Hedging Activities, or SFAS No. 133. We account for the majority of our forward physical contracts pursuant to the normal purchase and normal sale exemption under SFAS No. 133, whereby contracted energy costs are recorded at the time of physical delivery. The Company accounted for certain financial derivatives and its electricity forward physical delivery contracts entered into after January 28, 2005 for its Pennsylvania market (PJM-ISO) as cash flow hedges, whereby any related mark to market gain or loss on these contracts was deferred and reported as a component of other comprehensive income (loss) until the period of delivery.

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 requirement of SFAS No. 133 and (b) a forward physical contract and several derivative contracts had been inappropriately accounted for as exempt from hedge accounting under SFAS No. 133.

Without adequate documentation, we were not eligible to apply cash flow hedge accounting under SFAS No. 133 in fiscal 2005. Additionally, the derivative contracts that had been inappropriately accounted for as exempt from hedge accounting must be marked to market. Mark to market gains or losses on these derivatives are required to be reflected in the statement of operations for each period rather than deferred as a component of other comprehensive income (loss) until physical delivery.

We have restated our results for the first, second and third quarters of fiscal 2005 to mark to market these derivatives in the statement of operations for each period. The impact of the restatement on the financial statements for the three and six months ended January 31, 2005 is summarized as follows (in thousands, except per share data):


		Three Months Ended						Six Months Ended
		January 31, 2005						January 31, 2005

		Reported			Restated			Reported			Restated

Condensed Consolidated Statement of Operations Data:
Net revenue		$	61,048		$	61,048		$	119,545		$	119,545
Direct energy costs			51,026			52,639			103,433			103,975

Gross profit			10,022			8,409			16,112			15,570
Net loss			(729	)		(2,342	)		(1,848	)		(2,390	)
Net loss per common share:
	Basic and diluted		(0.02	)		(0.08	)		(0.06	)		(0.08	)


	January 31, 2005

	Reported			Restated

Condensed Consolidated Balance Sheet Data:
Total assets	$	104,917		$	104,917
Accrued liabilities		10,104			10,104
Retained earnings		11,718			11,176
Other comprehensive loss		(542	)		—
Total stockholders’ equity		71,562			71,562

The only change to the Condensed Consolidated Statement of Cash Flows was within cash flows from operating activities. Net cash provided by (used in) operating, investing and financing activities did not change.

This amended Quarterly Report on Form 10-Q/ A (Amendment No. 3) also amends our prior disclosure regarding our evaluation of controls and procedures as of the end of the period covered by this report.

This amendment includes changes to Item 1, Item 2 and Item 4 of Part I and Item 6 of Part II. Except as identified in the prior sentence, no other item included in the original Form 10-Q has been amended, and such items shall remain in effect as of the filing date of the original Form 10-Q. Additionally, this Form 10-Q/ A (Amendment No. 3) does not purport to provide an update or discussion of any other developments at the Company subsequent to its original filing.

COMMERCE ENERGY GROUP, INC.

FORM 10-Q/ A

(Amendment No. 3)

Restated For the Period Ended January 31, 2005

Index


		Page

PART I — FINANCIAL INFORMATION
Item 1.	Financial Statements:
	Condensed Consolidated Statements of Operations for the three and six months ended January 31, 2004 and 2005 (Restated)		2
	Condensed Consolidated Balance Sheets as of July 31, 2004 and January 31, 2005 (Restated)		3
	Condensed Consolidated Statements of Cash Flows for the three and six months ended January 31, 2004 and 2005 (Restated)		4
	Restated Notes to Condensed Consolidated Financial Statements		5
Item 2.	Restated Management’s Discussion and Analysis of Financial Condition and Results of Operations		15
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		29
Item 4.	Restated Controls and Procedures		30
PART II — OTHER INFORMATION
Item 1.	Legal Proceedings		32
Item 2.	Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities		32
Item 4.	Submission of Matters to a Vote of Security Holders		33
Item 6.	Exhibits		33
Signatures			35
EXHIBIT 31.1
EXHIBIT 31.2
EXHIBIT 32.1
EXHIBIT 32.2

FORWARD-LOOKING INFORMATION

A number of the matters and subject areas discussed in this Quarterly Report on Form 10-Q/A (Amendment No. 3) contain forward-looking statements reflecting management’s current expectations. The discussion of such matters and subject areas is qualified by the inherent risks and uncertainties surrounding future expectations generally, and also may differ materially from our actual future experience involving any one or more of such matters and subject areas. We wish to caution readers that all statements other than statements of historical fact included in this Quarterly Report on Form 10-Q/A (Amendment No. 3) regarding our financial position and strategy may constitute forward-looking statements. When used in this document, the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “project,” “plan,” “should,” and similar expressions are intended to be among the statements that identify forward-looking statements. All of these forward-looking statements are based upon estimates and assumptions made by our management, which although believed to be reasonable, are inherently uncertain. Therefore, undue reliance should not be placed on such estimates and statements. No assurance can be given that any of such estimates or statements will be realized and it is likely that actual results will differ materially from those contemplated by such forward-looking statements. Factors that may cause such differences include those set forth in this Quarterly Report on Form 10-Q/A (Amendment No. 3), as well as the following:


	•	regulatory changes in the states in which we operate that could adversely affect our operations;

	•	our continued ability to obtain and maintain licenses from the states in which we operate;

	•	the competitive restructuring of retail marketing may prevent us from selling electricity in certain states;

	•	our dependence upon a limited number of third parties to generate and supply to us electricity;

	•	fluctuations in market prices for electricity;

	•	our dependence on the Independent System Operators in each of the states where we operate, to properly coordinate and manage their electric grids, and to accurately and timely calculate and allocate the charges to the participants for the numerous related services provided;

	•	our ability to obtain credit necessary to support future growth and profitability; and

	•	our dependence upon a limited number of utilities to transmit and distribute the electricity we sell to our customers.

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

PART I — FINANCIAL INFORMATION


Item 1.	*Financial Statements.*

COMMERCE ENERGY GROUP, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)

(Unaudited)


		Three Months Ended						Six Months Ended
		January 31,						January 31,

		2004			2005			2004			2005

					(Restated)						(Restated)
Net revenue		$	47,038		$	61,048		$	105,434		$	119,545
Direct energy costs			43,783			52,639			97,858			103,975

Gross profit			3,255			8,409			7,576			15,570
Selling and marketing expenses			1,008			761			1,978			1,715
General and administrative expenses			5,829			10,043			11,347			15,050
Reorganization and initial public listing expenses			1,028			—			1,146			—

Loss from operations			(4,610	)		(2,395	)		(6,895	)		(1,195	)
Other income and expenses:
	Initial formation litigation expenses		—			(162	)		(585	)		(1,601	)
	Provision for impairment on investments		(4,313	)		—			(4,313	)		—
	Minority interest share of loss		351			—			895			—
	Interest income, net		151			215			281			406

Total other income and expenses			(3,811	)		53			(3,722	)		(1,195	)

Loss before benefit from income taxes			(8,421	)		(2,342	)		(10,617	)		(2,390	)
Benefit from income taxes			768			—			1,842			—

Net loss		$	(7,653	)	$	(2,342	)	$	(8,775	)	$	(2,390	)

Loss per common share:
	Basic	$	(0.28	)	$	(0.08	)	$	(0.32	)	$	(0.08	)

	Diluted	$	(0.28	)	$	(0.08	)	$	(0.32	)	$	(0.08	)

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

COMMERCE ENERGY GROUP, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands)


			July 31,			January 31,
			2004			2005

						(Unaudited)
						(Restated)
ASSETS
Current assets:
	Cash and cash equivalents		$	54,065		$	49,983
	Accounts receivable, net			31,119			32,272
	Income taxes refund receivable			4,423			4,430
	Deferred income tax asset			74			74
	Prepaid expenses and other current assets			5,141			1,278

		Total current assets		94,822			88,037
Restricted cash and cash equivalents				4,008			4,333
Deposits				5,445			6,699
Investments				96			91
Property and equipment, net				2,613			2,253
Goodwill and other intangible assets				3,839			3,504

		Total assets	$	110,823		$	104,917


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
	Accounts payable		$	30,576		$	23,251
	Accrued liabilities			6,141			10,104

		Total current liabilities		36,717			33,355
Stockholders’ equity:
	Common stock — 150,000 shares authorized with $0.001 par value; 30,519 and 30,499 shares issued and outstanding at July 31, 2004 and January 31, 2005, respectively			60,796			60,594
	Unearned restricted stock compensation			(256	)		(208	)
	Retained earnings			13,566			11,176

		Total stockholders’ equity		74,106			71,562

		Total liabilities and stockholders’ equity	$	110,823		$	104,917

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

COMMERCE ENERGY GROUP, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


			Six Months Ended
			January 31,

			2004			2005

						(Restated)
Cash Flows From Operating Activities
Net loss			$	(8,775	)	$	(2,390	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
	Depreciation			761			683
	Amortization			127			336
	Provision for doubtful accounts			1,125			1,318
	Impairment of Summit investments			4,843			5
	Stock-based compensation expense			—			48
	Minority interest share of loss of consolidated entity			(282	)		—
	Changes in operating assets and liabilities:
		Accounts receivable, net		13,249			(2,402	)
		Prepaid expenses and other assets		1,318			1,992
		Accounts payable		(6,685	)		(7,325	)
		Accrued liabilities and other		(258	)		4,505

Net cash provided by (used in) operating activities				5,423			(3,230	)
Cash Flows From Investing Activities
Purchase of property and equipment				(571	)		(325	)

Net cash used in investing activities				(571	)		(325	)
Cash Flows From Financing Activities
Proceeds from exercise of stock				1			50
Cancellation of common stock				—			(252	)
Decrease (increase) in restricted cash and cash equivalents				8,602			(325	)

Net cash provided by (used in) financing activities				8,603			(527	)

Increase (decrease) in cash and cash equivalents				13,455			(4,082	)
Cash and cash equivalents at beginning of period				40,921			54,065

Cash and cash equivalents at end of period			$	54,376		$	49,983

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

COMMERCE ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(In thousands, except per share and per kWh amounts)


1.	Summary of Significant Accounting Policies


	*Basis of Presentation*

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

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


	*Preparation of Interim Condensed Consolidated Financial Statements*

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


	*Uses of Estimates*

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


	*Reclassifications*

Certain amounts in the condensed Consolidated Financial Statements for the comparative prior fiscal period have been reclassified to be consistent with the current fiscal period’s presentation.

COMMERCE ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In thousands, except per share and per kWh amounts)


	*Revenue Recognition*

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


		Three Months Ended				Six Months Ended
		January 31,				January 31,

		2004		2005		2004		2005

Retail energy sales		$	46,034	$	44,807	$	102,181	$	97,499
Excess energy sales			1,004		16,241		3,253		22,046

	Net revenue	$	47,038	$	61,048	$	105,434	$	119,545

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


	*Stock-Based Compensation*

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

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


		Three Months Ended						Six Months Ended
		January 31,						January 31,

		2004			2005			2004			2005

					(Restated)						(Restated)
Net income (loss) as applicable to common stock — basic and diluted		$	(7,679	)	$	(2,342	)	$	(8,827	)	$	(2,390	)
Deduct: Total stock-based compensation expense determined under fair value based method for all awards, net of related tax effects			(9	)		(7	)		(92	)		(10	)

Pro forma net loss — basic and diluted		$	(7,688	)	$	(2,349	)	$	(8,919	)	$	(2,400	)

Net loss per share:
	Basic — as reported	$	(0.28	)	$	(0.08	)	$	(0.32	)	$	(0.08	)

	Basic — pro forma	$	(0.28	)	$	(0.08	)	$	(0.32	)	$	(0.08	)

	Diluted — as reported	$	(0.28	)	$	(0.08	)	$	(0.32	)	$	(0.08	)

	Diluted — pro forma	$	(0.28	)	$	(0.08	)	$	(0.32	)	$	(0.08	)

COMMERCE ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In thousands, except per share and per kWh amounts)


	*Employee Stock Purchase Plan*

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


	*Segment Reporting*

The Company’s chief operating decision makers consist of members of senior management that work together to allocate resources to, and assess the performance of, the Company’s business. These members of senior management currently manage the Company’s business, assess its performance, and allocate its resources as a single operating segment. Because the revenue of the Company’s subsidiary, Skipping Stone, which we acquired in fiscal 2004, accounts for approximately 1% of total net revenue (after elimination of inter-company transactions), and geographic information is not relevant, no segment information is provided.


	*Recent Accounting Standards*

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


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

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

COMMERCE ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In thousands, except per share and per kWh amounts)

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


	Three Months Ended						Six Months Ended
	January 31,						January 31,

	2004			2005			2004			2005

				(Restated)						(Restated)
Numerator:
Netloss	$	(7,653	)	$	(2,342	)	$	(8,775	)	$	(2,390	)
Deduct: Preferred stock dividends		(26	)		—			(52	)		—

Net loss applicable to common stock — basic and diluted	$	(7,679	)	$	(2,342	)	$	(8,827	)	$	(2,390	)


	Three Months Ended				Six Months Ended
	January 31,				January 31,

	2004		2005		2004		2005

			(Restated)				(Restated)
Denominator:
Weighted-average outstanding common shares — basic		27,645		30,534		27,645		30,528
Effect of stock options		—		—		—		—

Weighted-average outstanding common shares — diluted		27,645		30,534		27,645		30,528

For the three and six months ended January 31, 2004, the effects of the assumed exercise of all stock options and the assumed conversion of preferred stock into common stock are anti-dilutive; accordingly, such assumed exercises and conversions have been excluded from the calculation of net loss — diluted. If the assumed exercises or conversions had been used, the fully diluted shares outstanding for the three and six months ended January 31, 2005 would have been 30,881 and 30,888, respectively. If the assumed exercises or conversions had been used, the fully diluted shares outstanding for the three and six months ended January 31, 2004 would have been 29,087 and 29,118, respectively.


3.	Market and Regulatory


	*California*

The 1996 California Assembly Bill (“AB”) 1890 codified the restructuring of the California electric industry and provided for the right of direct access (“DA”). DA allowed electricity customers to buy their power from a supplier other than the electric distribution utilities beginning January 1, 1998. On April 1, 1998, the Company began supplying customers in California with electricity as an Electric Service Provider (“ESP”).

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

In July 2002, the CPUC authorized Southern California Edison (“SCE”) to implement a Historical Procurement Charge (“HPC”), to repay debt incurred during the energy crisis. This amount is currently being collected by SCE as a $0.01 per kilowatt-hour (“kWh”) surcharge on the retail electricity bill paid by

COMMERCE ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In thousands, except per share and per kWh amounts)

the Company’s customers. SCE estimates that full payment could be achieved as soon as early 2006. While the HPC does not directly impact the Company’s rate design or revenue, it may affect the Company’s ability to retain existing customers or compete for new customers.

Effective January 1, 2003, the CPUC authorized the electric distribution utilities to charge certain DA customers a surcharge to cover state power contract costs. The Direct Access Cost Responsibility Surcharge (the “DA CRS”) is currently fixed at $0.027 per kWh. The DA CRS is only assessed to those DA customers who enrolled in DA on or after February 1, 2001. In the SCE service territory, the $0.027 DA CRS includes the $0.01 HPC. Those customers who were enrolled in DA prior to February 1, 2001, and are in the SCE service territory continue to pay only the $0.01 HPC. While this charge does not directly impact the Company’s rate design or revenue, it may affect the Company’s ability to retain existing customers or compete for new customers.

In December 2003, Pacific Gas and Electric (“PG&E”) and the CPUC reached a settlement in the PG&E bankruptcy. In February 2004, the CPUC approved a rate settlement agreement, which reduced overall customer rates in the PG&E service territory. DA bills have generally declined in the PG&E service territory and the lower rates have affected the Company’s revenue and profitability.

Currently, four important issues are under review at the CPUC, a Resource Adequacy Requirement, a Renewable Portfolio Standard, Utilities Long Term Procurement Plans and the General Rate Cases of the electric distribution utilities. Additional costs to serve customers in California are anticipated from these proceedings; however, the CPUC decisions will determine the distribution of those costs across all load serving entities and ultimately the financial impact on the Company.


	*Pennsylvania*

In 1996, the Electricity Generation Customer Choice and Competition Act was passed. This law allowed electric customers to choose among competitive power suppliers beginning with one third of the State’s consumers by January 1999, two thirds by January 2000, and all consumers by January 2001. The Company began serving customers in the Pennsylvania territory in 1999. There are no current rate cases or filings regarding this territory that are anticipated to impact the Company’s financial results.


	*Michigan*

The Michigan state legislature passed two acts, the Customer Choice Act and Electricity Reliability Act, signed into law on June 3, 2000. Open access, or Choice, became available to all customers of Michigan electric distribution utilities, beginning January 1, 2002. The Company began marketing in Michigan’s Detroit Edison (“DTE”) service territory in September 2002.

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

In November 2004, the MPSC issued the final order in the DTE General Rate case making slight changes in the rates originally approved in the interim order issued in February 2004. The final order reinstated a small percentage of savings of large commercial customers who choose an alternative electric supplier, while generally maintaining the charges for smaller commercial customers. More notable changes were made to rules regarding moving between the local utility and alternative suppliers. New customers electing service from alternative providers must remain outside utility service for a minimum of two years.

COMMERCE ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In thousands, except per share and per kWh amounts)

Additionally, the local utility now requires substantial notice prior to returning to their service. Overall rate and rule changes are not expected to have a significant impact to the Company’s ability to retain its existing customers and obtain new customers.

The Michigan Senate has energy restructuring language before it in various bills, supported by the electric distribution utilities, which could negatively impact competition in the Michigan electric market.


	*New Jersey*

Deregulation activities began in New Jersey in November 1999 when the Board of Public Utilities, or BPU, approved the implementation plan. The Company began marketing in New Jersey in the Public Service Electric and Gas service territory in December 2003.

The Basic Generation Service is the comparable utility price for small and large commercial accounts and includes a reconciliation charge which can change on a monthly basis. Reconciliation charge fluctuations can affect the Company’s ability to remain competitive against the comparable utility pricing.


4.	Investments

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

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


5.	Commitments and Contingencies


	*Commitments*


	Purchase Commitments

On January 28, 2005, the Company made a strategic decision to discontinue service to certain customers in the Pennsylvania service territory, specifically certain residential and small commercial customers. In connection with that decision, the Company sold back future electricity supply commitments related to serving those customers to its energy supplier. The supply commitments would have provided the Company with electricity to serve the discontinued customers’ electricity requirements through May 2006. The transaction occurred in January 2005 and resulted in a gain on the sale of the supply commitments of $9,301, which has been reflected in the Company’s financial statements for its second fiscal quarter ending January 31, 2005. This gain was partially offset by $1,500 of additional costs, to cover the timing and forecasting issues related to realigning the customer portfolio, incurred in the third fiscal quarter of 2005 and $600 of a reserve for additional estimated energy costs in the fourth fiscal quarter of 2005. (See Note 8). The Company will continue to serve remaining customers in the Pennsylvania territory from remaining supply contracts with other wholesale suppliers. After giving effect to the supply commitment that was sold in the

COMMERCE ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In thousands, except per share and per kWh amounts)

Pennsylvania territory and any new supply commitments entered into in the second fiscal quarter, the following is a summary of the Company’s commitments to purchase electric power as of January 31, 2005:


		Fiscal Years Ending

		2005		2006		Total

California		$	24,494	$	18,586	$	43,080
Pennsylvania and New Jersey			6,898		5,079		11,977

	Total	$	31,392	$	23,665	$	55,057


	*Contingencies*


	Employment Settlements

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


	*Litigation*

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

On December 23, 2004, the Company entered into a full and comprehensive Settlement Agreement and Mutual General Release (“Settlement Agreement”) with stockholder and former director of Commonwealth Energy Corporation, Joseph P. Saline, and stockholder Joseph Ogundiji. The Settlement Agreement effectively ended all legal actions between the parties that began in 2001. The Settlement Agreement acknowledges and validates Mr. Saline’s shares of common stock in the Company and provides for a $1,200 settlement payment to Mr. Saline. The Settlement Agreement also provides Mr. Ogundiji with a payment of $222 in settlement of all of his claims and for canceling all of his shares of common stock. In addition, Mr. Saline and Mr. Ogundiji agreed that for the next two years they would submit any future disputes to mediation before commencing litigation or before they take any steps to contact the Company’s stockholders for any reason. The Company accrued $1,200 in October of 2004 for the settlement with Mr. Saline and the $222 settlement for Mr. Ogundiji was recorded as cancellation of stock with no income statement effect.

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

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


6.	Derivative Financial Instruments

The Company’s activities expose it to a variety of market risks, including commodity prices and interest rates. Management has established risk management policies and procedures designed to reduce the

COMMERCE ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In thousands, except per share and per kWh amounts)

potentially adverse effects that the price volatility of these markets may have on its operating results. The Company’s risk management activities, including the use of derivative instruments, are subject to the management, direction and control of an internal risk oversight committee. The Company maintains commodity price risk management strategies that use derivative instruments within strict risk tolerances to minimize significant, unanticipated earnings fluctuations caused by commodity price volatility. Changes in fair market value are recognized currently in earnings unless specific hedge accounting criteria are met.

Supplying electricity to retail customers requires the Company to match customers’ projected demand with fixed price purchases. The Company primarily uses forward physical delivery contracts and financial derivative instruments to minimize significant, unanticipated earnings fluctuations caused by commodity price volatility. In certain markets where the Company operates, entering into forward physical delivery contracts may be expensive relative to derivative alternatives. Financial derivative instruments, primarily swaps and futures, are used to hedge the future purchase price of electricity for the applicable forecast usage protecting the Company from significant price volatility. The Company did not engage in trading activities in the wholesale energy market other than to manage its direct energy cost.


7.	Subsequent Event

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


8.	Restated Quarterly Financial Information (Unaudited)


	*Restatement — Gain on Sale of Electricity Supply Contracts*

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

COMMERCE ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In thousands, except per share and per kWh amounts)

incurred in the third quarter of fiscal 2005 and estimated in the fourth quarter of fiscal 2005 compared to the cost that would have been incurred under the original supply contracts, as reflected below.


	Three Months Ended					Six Months Ended
	January 31, 2005					January 31, 2005

	Reported		Restated			Reported		Restated

Net revenue	$	61,048	$	61,048		$	119,545	$	119,545
Direct energy costs		48,926		51,026			101,333		103,433

Gross profit		12,122		10,022			18,212		16,112
Earnings (loss) from operations	$	1,318	$	(782	)	$	1,447	$	(653	)
Net income (loss)	$	1,371	$	(729	)	$	252	$	(1,848	)
Earnings (loss) per share — basic	$	0.04	$	(0.02	)	$	0.01	$	(0.06	)

Earnings (loss) per share — diluted	$	0.04	$	(0.02	)	$	0.01	$	(0.06	)

Restatement — Accounting for Derivatives

In connection with the preparation of the Company’s consolidated financial statements for the fiscal year ended July 31, 2005, the Company determined that certain forward physical delivery contracts and financial derivatives previously designated as cash flow hedges lacked adequate documentation of the method of measurement and testing of hedge effectiveness to meet the cash flow hedge requirements of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”. Additionally, the Company determined that a forward physical delivery contract and several financial derivative contracts had been inappropriately accounted for as exempt from hedge accounting under SFAS No. 133.

The Company restated its results for the first, second and third quarters of fiscal 2005 to eliminate cash flow hedge accounting and to recognize the mark to market gains or losses on these derivatives in the statement of operations for each period. The impact of the restatement is summarized as follows:


	Three Months Ended						Six Months Ended
	January 31, 2005						January 31, 2005

	Reported			Restated			Reported			Restated

Condensed Consolidated Statement of Operations Data:
Net revenue	$	61,048		$	61,048		$	119,545		$	119,545
Direct energy costs		51,026			52,639			103,433			103,975

Gross profit		10,022			8,409			16,112			15,570
Loss from operations	$	(782	)	$	(2,395	)	$	(653	)	$	(1,195	)
Net loss	$	(729	)	$	(2,342	)	$	(1,848	)	$	(2,390	)
Net loss per common share — basic and diluted	$	(0.02	)	$	(0.08	)	$	(0.06	)	$	(0.08	)

COMMERCE ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In thousands, except per share and per kWh amounts)


	January 31, 2005

	Reported			Restated

Condensed Consolidated Balance Sheet Data:
Total assets	$	104,917		$	104,917
Accrued liabilities		10,104			10,104
Retained earnings		11,718			11,176
Other comprehensive loss		(542	)		—
Total stockholders’ equity		71,562			71,562


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

Overview

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

As of January 31, 2005, we delivered electricity to approximately 94,000 customers in California, Pennsylvania, Michigan and New Jersey. The growth of this business depends upon the degree of deregulation in each state, the availability of energy at competitive prices, credit terms, and our ability to acquire retail or commercial customers.

Our core business is the retail sale of electricity to end-use customers. All of the power we sell to our customers is purchased from third-party power generators under long-term contracts and in the spot market. We do not own electricity generation facilities, with the exception of small experimental renewal energy assets. The electric power we sell is generally metered and delivered to our customers by local incumbent electric distribution utilities, or local utilities. The local utilities also provide billing and collection services for most of our customers on our behalf. To facilitate load shaping and balancing for our retail customer portfolio, we also buy and sell surplus electric power from and to other market participants when necessary.

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

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

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

In fiscal 2004, we consolidated Summit Energy Ventures, or Summit, and its majority interest in Power Efficiency Corporation, or PEC, into our financial results. In the third fiscal quarter of 2004, we terminated our relationship with Summit. We no longer consolidate Summit and PEC in our current fiscal year financial results as we retained a 39.9% interest in PEC. At January 31, 2005, our ownership interest was diluted to 36.4% as a result of an equity linked financing by PEC. Although we currently account for our investment in PEC under the equity method of accounting, in fiscal 2004, we recorded a loss sufficient to reduce our investment basis in PEC to zero and, therefore, it will have no negative impact on our financial results in fiscal 2005 or in the future.

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

Market and Regulatory


	*California*

The 1996 California Assembly Bill, or AB, 1890 codified the restructuring of the California electric industry and provided for the right of direct access, or DA. DA allowed electricity customers to buy their power from a supplier other than the electric distribution utilities beginning January 1, 1998. On April 1, 1998, we began supplying customers in California with electricity as an Electric Service Provider, or ESP.

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

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

Effective January 1, 2003, the CPUC authorized the electric distribution utilities to charge certain DA customers a surcharge to cover state power contract costs. The Direct Access Cost Responsibility Surcharge, or the DA CRS, is currently fixed at $0.027 per kWh. The DA CRS is only assessed to those DA customers who enrolled in DA on or after February 1, 2001. In the SCE service territory, the $0.027 DA CRS includes the $0.01 HPC. Those customers who were enrolled in DA prior to February 1, 2001, and are in the SCE service territory continue to pay only the $0.01 HPC. While this charge does not directly impact our rate design or revenue, it may affect our ability to retain existing customers or compete for new customers.

In December 2003, Pacific Gas and Electric, or PG&E, and the CPUC reached a settlement in the PG&E bankruptcy. In February 2004, the CPUC approved a rate settlement agreement, which reduced overall customer rates in the PG&E service territory. DA bills have generally declined in the PG&E service territory and the lower rates have affected our revenue and profitability.


	*Pennsylvania*

In 1996, the Electricity Generation Customer Choice and Competition Act was passed. This law allowed electric customers to choose among competitive power suppliers beginning with one third of the State’s consumers by January 1999, two thirds by January 2000, and all consumers by January 2001. We began serving customers in the Pennsylvania territory in 1999. There are no current rate cases or filings regarding this territory that are anticipated to impact our financial results.


	*Michigan*

electric distribution utilities, beginning January 1, 2002. We began marketing in Michigan’s Detroit Edison, or DTE, service territory in September 2002.

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


	*New Jersey*

Deregulation activities began in New Jersey in November 1999 when the Board of Public Utilities approved the implementation plan. We began marketing in New Jersey in the Public Service Electric and Gas service territory in December 2003.

The Basic Generation Service is the comparable utility price for small and large commercial accounts and includes a reconciliation charge which can change on a monthly basis. Reconciliation charge fluctuations can affect our ability to remain competitive against the comparable utility pricing.

Critical Accounting Policies and Estimates

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


	•	Purchase and Sale Accounting — In fiscal 2004 and 2005, we purchased substantially all of our power under long-term forward physical delivery contracts for supply to our retail electricity customers. We apply the normal purchase, normal sale accounting treatment to our forward purchase supply contracts and our customer sales contracts. Accordingly, we record revenue generated from our sales contracts as energy is delivered to our retail customers, and direct energy costs are recorded when the energy under our long-term forward physical delivery contracts is delivered. In the first and second quarters of fiscal 2005, we also employed financial hedges using derivative instruments, to hedge our commodity price risks. We intend to use derivative instruments as an efficient way of assisting in managing our price and volume risk in energy supply procurement for our retail customers. Certain derivative instrument treatment may not qualify for hedge treatment and require mark-to-market accounting in accordance

with the Financial Accounting Standards Board, or FASB, Statement of Financial Accounting Standard, or SFAS, No. 133, Accounting for Derivative Instruments and Hedging Activities.

• Independent System Operator Costs — Included in direct energy costs, along with electric power that we purchase, are scheduling coordination costs and other ISO fees and charges. The actual ISO costs are not finalized until a settlement process by the ISO is performed for each day’s activities for all grid participants. Prior to the completion of settlement (which may take from one to several months), we estimate these costs based on historical trends and preliminary settlement information. The historical trends and preliminary information may differ from actual fees resulting in the need to adjust the previously estimated costs.

• Allowance for Doubtful Accounts — We maintain allowances for doubtful accounts for estimated losses resulting from non-payment of customer billings. If the financial condition of our customers were to deteriorate, resulting in an impairment of their ability to make payments, additional allowances may be required.

• Unbilled Receivables — Our customers are billed monthly at various dates throughout the month. Unbilled receivables represent the amount of electric power delivered to customers at the end of a reporting period, but not yet billed. Unbilled receivables from sales are estimated by us to be the number of kilowatt-hours delivered, but not yet billed, multiplied by the current customer average sales price per kilowatt-hour.

• Legal Matters — From time to time, we may be involved in litigation matters. We regularly evaluate our exposure to threatened or pending litigation and other business contingencies and accrue for estimated losses on such matters in accordance with SFAS No. 5, “Accounting for Contingencies.” As additional information about current or future litigation or other contingencies becomes available, management will assess whether such information warrants the recording of additional expense relating to our contingencies. Such additional expense could potentially have a material adverse impact on our results of operations and financial position.

Results of Operations

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


	*Three Months Ended January 31, 2005 Compared to Three Months Ended January 31, 2004*

Net revenue of $61.0 million increased by $14.0 million, or 30%, for the three months ended January 31, 2005 compared to the three months ended January 31, 2004. Gross profit increased $5.1 million to $8.4 million for the three months ended January 31, 2005 compared to $3.3 million for the same prior year period. The revenue and gross profit improvement in the three months ended January 31, 2005 was primarily due to the sale of a portion of our Pennsylvania energy supply for $9.3 million and an increase in excess energy sales of $5.9 million, partly offset by a $1.6 million mark-to-market loss related largely to derivative contracts marked at the end of the quarter. For the quarter ended October 31, 2004, the Company recognized a net mark-to-market gain on its derivatives of $1.1 million. On January 28, 2005, we made a strategic decision to discontinue service to certain residential and small commercial customers in the Pennsylvania territory, and sold back electricity supply commitments to our energy supplier for $9.3 million. This gain was partially offset by $1.5 million and $0.6 million of additional cost, to cover the timing and forecasting issues related to realigning the customer portfolio, incurred in the third fiscal quarter of 2005 and estimated to be incurred in the fourth fiscal quarter of 2005, respectively. The Company’s operating results for the three months ended January 31, 2005 included a loss from operations of $2.4 million compared to a loss of $4.6 million for the same prior year period.


	Net revenue


	*Retail Energy Sales*

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


	*Excess Energy Sales*

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

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

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


	*Direct Energy Costs*

Direct energy costs, which are recognized concurrently with related energy sales, include the aggregated cost of purchased electric power, fees incurred from various energy-related service providers, energy-related taxes that cannot be passed directly through to the customer and any mark-to-market gains or losses on derivative contracts. Our direct energy costs increased to $52.6 million for the three months ended January 31, 2005, an increase of $8.8 million, or 20%, from $43.8 million for the three months ended January 31, 2004.

The increase in direct energy costs occurred primarily in Michigan and California, with a partial offset in Pennsylvania. In Michigan, our average cost per kWh was $0.052 for the three months ended January 31, 2005, as compared to an average cost per kWh of $0.047 for the same period last year. In California, our average cost per kWh was $0.061 for the three months ended January 31, 2005, as compared to an average cost per kWh of $0.056 for the same period in fiscal 2004. In Pennsylvania, our average cost per kWh was $0.061 for the three months ended January 31, 2005, as compared to an average cost per kWh of $0.063 for the same period in fiscal 2004. In addition, increased cost in the current period reflect $2.1 million of

additional costs incurred in the third fiscal quarter 2005 and estimated to be incurred in the fourth fiscal quarter 2005, which was restated in the second fiscal quarter 2005 to offset the $9.3 million gain recognized in this same period. Additionally, the increase in direct energy cost includes $1.6 million of mark to market losses on forward physical contracts previously accounted for as cash flow hedges.


	Selling and Marketing Expenses

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


	General and Administrative Expenses

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


	Reorganization and Initial Public Listing Expenses

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


	Initial Formation Litigation Expenses

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


	Provision for Impairment on Investments

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


	Minority Interest Share of Loss

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


	Benefit from Income Taxes

No provision for, or benefit from, income taxes was recorded for the three months ended January 31, 2005; as compared to the benefit from income taxes of $0.8 million for the three months ended January 31, 2004. In fiscal 2005, we established a valuation allowance equal to our calculated tax benefit because we believed it was not certain that we would realize these tax benefits in the foreseeable future. The current period results are not sufficient to modify this conclusion.


	*Six Months Ended January 31, 2005 Compared to Six Months Ended January 31, 2004*

Net revenue increased $14.1 million, or 13%, to $119.5 million for the six months ended January 31, 2005 as compared to $105.4 million in the six months ended January 31, 2004. Gross profit increased $8.0 million to $15.6 million for the six months ended January 31, 2005 as compared to $7.6 million for the same prior year period. The revenue and gross profit improvement in the six months ended January 31, 2005 was primarily due to the sale of a portion of the future Pennsylvania energy supply for $9.3 million, partially offset by $2.1 million additional cost incurred to cover the timing and forecasting issues related to realigning the customer portfolio, an increase in excess energy sales of $9.5 million and increased gross profit in Michigan and New Jersey due to increased customer base offset by the continuing pressure on gross profit in the California business. The Company’s operating results for the six months ended January 31, 2005 included a loss from operations of $0.7 million compared to a loss of $6.9 million for the same prior year period.


	Net Revenue


	*Retail Energy Sales*

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


	*Excess Energy Sales*

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


	*Direct Energy Costs*

Our direct energy costs increased to $104.0 million for the six months ended January 31, 2005, an increase of $6.1 million, or 6%, from $97.9 million for the six months ended January 31, 2004. The increase in direct energy costs occurred primarily in Michigan and California partially offset by decreases in Pennsylvania related to the New Jersey market. In Michigan, our average cost per kWh was $0.051 for the six months ended January 31, 2005, as compared to an average cost per kWh of $0.047 for the same period last year. In California, our average cost per kWh was $0.060 for the six months ended January 31, 2005, as compared to an average cost per kWh of $0.055 for the same period in fiscal 2004. In Pennsylvania, our average cost per kWh was $0.057 for the six months ended January 31, 2005, as compared to an average cost per kWh of $0.063 for the same period in fiscal 2004.


	Selling and Marketing Expenses

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


	General and Administrative Expenses

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


	Reorganization and Initial Public Listing Expenses

We incurred $1.1 million in the six months ended January 31, 2004 of costs related to our reorganization into a Delaware holding company structure and the initial public listing of our common stock on the American Stock Exchange. Management believed it was appropriate to classify these costs as a separately identified selling, general and administrative expense category, and included expenses such as legal, accounting, auditing, consulting, and printing and reproduction fees that were specific to these activities. We incurred no such expenses in fiscal 2005.


	Initial Formation Litigation Expenses

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


	Minority Interest Share of Loss


	Benefit from Income Taxes

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

Liquidity and Capital Resources

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

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

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

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

The Company does not have open lines of credit for direct unsecured borrowings or letters of credit. Credit terms from our suppliers of electricity often require us to post collateral against our energy purchases and against our mark-to-market exposure with certain of our suppliers. We currently finance these collateral obligations with our available cash. If we are required to post such additional security, a portion of our cash would become restricted, which could adversely affect our liquidity. As of January 31, 2005, we had $4.3 million in restricted cash to secure letters of credit required by our suppliers and $6.5 million in deposits pledged as collateral in connection with energy purchase agreements.

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


	*Contractual Obligations*

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

In January 2005, we sold back our electricity supply commitments related to serving certain residential and small commercial customers, in the Pennsylvania territory, to our energy supplier. The supply commitments would have provided us with electricity to serve the discontinued customers’ electricity requirements through May 2006. The transaction occurred in January 2005 and resulted in a gain on the sale of the supply commitments of $9.3 million, which has been reflected in our financial statements for our second fiscal quarter ending January 31, 2005. This gain was partially offset by $2.1 million of additional cost, to cover the timing and forecasting issues related to realigning the customer portfolio, incurred in the third fiscal quarter of 2005 and estimated to be incurred in the fourth fiscal quarter of 2005. We will continue to serve remaining customers in the Pennsylvania territory from remaining supply contracts with other wholesale suppliers. After giving effect to the supply commitment that was sold in the Pennsylvania territory and any new supply commitments entered into in the second fiscal quarter, our contractual commitments for electricity purchase contracts as of January 31, 2005 are $55.1 million, of which $54.8 million is for less than one year and $0.3 million is for more than one year through March 2006.

Subsequent Event

On February 9, 2005, we entered into an agreement with American Communications Network, Inc. (“ACN”), and several of its subsidiaries, ACN Utility Services, Inc. (“ACN Utility”), ACN Energy, Inc. (“ACN Energy”) and ACN Power, Inc. (“ACN Power”, and collectively with ACN Utility and ACN Energy, the “Sellers”) to purchase certain assets of the Sellers’ retail electric power and natural gas sales business, and assume specified liabilities. The Sellers sell retail electric power in Texas and Pennsylvania and sell retail natural gas in California, Ohio, Georgia, New York, Pennsylvania and Maryland. The assets acquired include equipment, gas inventory associated with utility and pipeline storage and transportation agreements and electricity supply, scheduling and capacity contracts, software and other infrastructure plus approximately 80,000 residential and small commercial customers. The initial consideration paid by us was

(a) $6.5 million in cash, plus (b) 930,233 shares of our common stock, valued at $2.0 million, based upon the market price for our common stock as of February 8, 2005, the date immediately prior to the closing date. The shares of common stock will initially be placed in escrow and released upon satisfaction of certain performance targets related to customer growth. ACN was also paid at closing an estimated prepayment amount of approximately $5.5 million as payment for certain working capital and prepayment items relating to the assets being acquired, and are subject to final adjustment and settlement. We have sufficient cash to cover the needs of this acquisition. This transaction was previously reported by us on a current report on Form 8-K filed with the Securities and Exchange Commission on February 10, 2005.

Factors That May Affect Future Results


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

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

Retail energy market restructuring has been and will continue to be a complicated regulatory process, with competing interests advanced not only by relevant state and federal utility regulators, but also by state legislators, federal legislators, local utilities, consumer advocacy groups and other market participants. As a result, the extent to which there are legitimate competitive opportunities for alternative energy suppliers in a given jurisdiction may vary widely and we cannot be assured that regulatory structures will offer us competitive opportunities to sell energy to consumers on a profitable basis. The regulatory process could be negatively impacted by a number of factors, including interruptions of service and significant or rapid price increases. The legislative and regulatory processes in some states take prolonged periods of time. In a number of jurisdictions, it may be many years from the date legislation is enacted until the retail markets are truly open for competition.

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


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

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


	•	Our ability to attract and to retain a critical mass of customers at a reasonable cost;

	•	Our ability to continue to develop and maintain internal corporate organization and systems;


	•	The continued competitive restructuring of retail energy markets with viable competitive market rules; and

	•	Our ability to effectively manage our energy procurement and shaping requirements, and to sell our energy at a sufficient profit margin.


	*We may have difficulty obtaining a sufficient number of customers.*

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

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


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

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


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

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

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


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

Under a Settlement agreement with the California PUC, SCE was authorized to recoup $3.6 billion in debt incurred during the energy crisis of 2000-2001 from all customers. This debt was to be collected under the Procurement Related Obligations Account, or PROACT, from bundled (non direct access) customers and under the HPC from DA customers.

In July 2002, the California PUC issued an interim order implementing the HPC sought by SCE. This interim order authorized SCE to collect $391 million in HPC charges from all DA customers by reducing their Procured Energy Credit, or PE Credit, by $0.027 per kWh beginning July 27, 2002. The lowered PE Credit continued until an exit fee for DA customers was approved by the CPUC. Effective January 1, 2003, it was reduced to $0.01 per kWh. For the fiscal year ended July 31, 2003, we estimated that HPC charges had impacted our sales and pretax earnings by a range of $4.8 million to $6.0 million. We were unable to precisely determine the actual HPC charges applied to our customers by SCE because there were different charges, by customer type, and this charge was only on the electricity usage above the monthly baseline usage allocation.

On September 5, 2003 the CPUC issued Decision 03-09-016 granting SCE’s request to recover additional shortfall and authorizing the HPC balance to be revised to $473 million; however, the $0.01 per kWh monthly charge remained in place. As of August 1, 2003, SCE revised its billing methodology to a “bottoms-up” design effectively doing away with the PE Credit and the net effect of the HPC on our rates. While the HPC no longer discretely impacts our rate calculations, a recent SCE rate reduction indirectly includes the former impact of the HPC. This rate reduction impacted sales and pretax profit in the SCE district. The rate reduction remained in place in 2004 and approximated the effect of the HPC dollar impact of 2003.

In 2003, SCE acknowledged that the PROACT debt was paid in full by bundled customers at the end of July 2003. As a result, on August 1, 2003, all SCE rates were lowered. As a direct result, to retain our customers in the SCE utility district, we lowered our customer rates proportionately. Our estimate of the annual financial impact of this rate reduction is a decline in sales and pretax profit during fiscal 2004, in the range of $3.0 to $3.5 million. This reduction is separate from, and in addition to, the HPC related reduction in 2003.

These changes in the SCE service territory will continue to cause a significant impact on our revenue and cash flow; however, we currently do not expect they will preclude us from continuing to participate in the SCE market.


	*Some suppliers of electricity have been experiencing deteriorating credit quality.*

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


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

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


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

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

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

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


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

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


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

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

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


	•	weather conditions, including hydrological conditions such as precipitation, snow pack and stream flow,

	•	seasonality,

	•	unexpected changes in customer usage,

	•	transmission or transportation constraints or inefficiencies,

	•	planned and unplanned plant or transmission line outages,

	•	demand for electricity,


	•	natural gas, crude oil and refined products, and coal supply availability to generators from whom we purchase electricity,

	•	natural disasters, wars, embargoes and other catastrophic events, and

	•	federal, state and foreign energy and environmental regulation and legislation.


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

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


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

Effective internal controls are necessary for us to provide reliable financial reports and effectively prevent fraud. If we cannot provide reliable financial reports or prevent fraud, our operating results could be harmed. We have in the past discovered, and may in the future discover, areas of our internal controls that need improvement. For example, in January 2005, we sold electricity commodity supply contracts related to a strategic realignment of our customer portfolio in the Pennsylvania electricity market and the discontinuation of service to certain classes of residential and small commercial customers. As a result of timing issues related to realigning the portfolio and inaccurately forecasting the resulting required electricity supply, we had transitional electricity supply obligations which could have been served more cost effectively with the original supply contract rather than with the current market cost of the replacement power. 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 133 and (b) a forward physical contract and several financial derivative contracts had been inappropriately accounted for as exempt from hedge accounting under SFAS 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 controls, or difficulties encountered in their implementation, could harm our operating results or cause us to fail to meet our reporting obligations. Inferior internal controls could also cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our stock.


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

As directed by Section 404 of the Sarbanes-Oxley Act of 2002, the Securities and Exchange Commission adopted rules requiring public companies to include a report of management on our internal controls over financial reporting in our Annual Reports on Form 10-K that contains an assessment by management of the effectiveness of our internal controls over financial reporting. In addition, our independent auditors must attest to and report on management’s assessment of the effectiveness of our internal controls over financial reporting. This requirement will first apply to our Annual Report on Form 10-K for the fiscal year ending July 31, 2006 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. We anticipate that improvements will continue to be made.


Item 3.	*Quantitative and Qualitative Disclosures About Market Risk.*

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

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

Supplying electricity to retail customers requires us to match customers’ projected demand with fixed price purchases. We primarily use forward physical energy purchases and derivative instruments to minimize significant, unanticipated earnings fluctuations caused by commodity price volatility. In certain markets where we operate, entering into forward fixed price contracts may be expensive relative to derivative alternatives. Derivative instruments, primarily swaps and futures, are used to hedge the future purchase price of electricity for the applicable forecast usage protecting us from significant price volatility. We did not engage in trading activities in the wholesale energy market other than to manage our direct energy cost in an attempt to improve the profit margin associated with our customer requirements.

On January 28, 2005, we sold back future electricity supply commitments related to serving certain customers in Pennsylvania to our energy supplier. As a result of the portfolio rebalancing required due to this

sale, the portfolio coverage ratio is more meaningful at February 28, 2005, where we had 87% of our forecast energy load through December 31, 2005 covered through either fixed price power purchases with counterparties, or price protected through financial hedges.


Item 4.	*Controls and Procedures.*

Restatement of Quarterly Periods


	Gain on Sale of Electricity Supply Contracts

In January 2005, we sold electricity commodity supply 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 electricity supply contracts rather than with the replacement power which we subsequently purchased at market prices. In the execution of this portfolio realignment, we observed deficiencies in our internal controls relating to monitoring the operational progress of the realignment. Ernst & Young LLP, our independent registered public accounting firm, advised us on June 8, 2005 that in their opinion, with which we concurred, these internal control deficiencies constituted reportable conditions and collectively, a material weakness in our internal control over financial reporting and that our unaudited condensed consolidated financial statements for the three and six months period ended January 31, 2005 should be restated. As a result of these timing and forecasting issues and internal control deficiencies, on June 14, 2005, we restated our unaudited condensed consolidated financial statements for the three and six months periods ended January 31, 2005 by filing the Quarterly Report on Form 10-Q/A (Amendment No. 1) for the period ended January 31, 2005. The financial impact of this adjustment (principally, reporting a net loss of $729,000 for the three months period ended January 31, 2005 instead of the previously reported net income of $1,371,000 and a net loss of $1,848,000 for the six months period ended January 31, 2005 instead of the previously reported net income of $252,000), and to include additional disclosures in the appropriate period related to these internal control deficiencies. On July 12, 2005, we filed our Quarterly Report on Form 10-Q/ A (Amendment No. 2) for the quarterly period ended January 31, 2005 to clarify the results of our evaluation of controls and procedures for the period ended January 31, 2005.

With respect to the above-referenced deficiencies and material weakness in our internal control over financial reporting, we took the following corrective actions, some of which we began to implement as early as March 2005:


	•	Determined that a major integrated system upgrade was required to replace the current in-house forecasting, meter tracking and sales systems. We have selected several third party software systems that meet our requirements and have made substantial implementation progress;

	•	Established procedures to reconcile demand and load factors among the various in-house systems until the integrated system can be fully implemented;

	•	Established procedures to reconcile meter counts on a weekly basis among the various in-house systems until the integrated system can be fully implemented; and

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

With the exception of the completion of the integrated system upgrades, which we expect to complete by the end of the second quarter of fiscal 2006, we have completed the other corrective actions during the third quarter of fiscal 2005.


	SFAS No. 133

In connection with the preparation of our financial statements for the fiscal year ended July 31, 2005, we determined that certain forward physical contracts and financial derivatives previously 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 Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended (SFAS No. 133). Additionally, we determined

that a forward physical contract and several financial derivative contracts had been inappropriately accounted for as normal purchase and normal sale contracts and thereby erroneously accounted for as exempt from hedge accounting under SFAS No. 133.

Without adequate documentation, we are not eligible to apply cash flow hedge accounting in fiscal 2005. Additionally, the derivative contracts that had been inappropriately accounted for as exempt from hedge accounting must be marked to the market. Mark to market gains or losses on these derivative contracts are required to be reflected in the statement of operations for each period rather than deferred as a component of other comprehensive income (loss) until physical delivery.

As a result, management has determined that the failure to properly document and account for certain of our forward physical contracts and financial derivatives in accordance with the requirements of SFAS No. 133 represented a material weakness in our internal control over financial reporting.

On October 25, 2005, management recommended to the Audit Committee of our Board of Directors that previously reported financial results for the quarterly periods ended October 31, 2004, January 31, 2005 and April 30, 2005 be restated to reflect proper accounting treatment for these derivatives in accordance with SFAS No. 133 and that the quarterly financial statements for the periods ended October 31, 2004, January 31, 2005 and April 30, 2005 should no longer be relied upon. The Audit Committee agreed with management’s assessment and recommendation and on October 26, 2005 recommended the same action to the Board of Directors, which, on the same date, determined that the previously reported quarterly results for fiscal 2005 should be restated to reflect the appropriate accounting for these derivatives. As a result, we are restating our quarterly results for each of the first three quarters in the fiscal year ended July 31, 2005.

We have taken the following corrective actions which we believe will remediate the material weakness in our internal control over financial reporting with respect to appropriate application of the provisions of SFAS No. 133 for our energy supply activities. The remedial actions included the institution of: (a) improved training, education and accounting policies and procedures designed to ensure that all relevant personnel involved in the our utilization of derivative transactions understand and apply cash flow hedge accounting in compliance with SFAS No. 133; and (b) additional senior management oversight procedures designed to ensure such compliance. We expect that this process of remediation will be completed by the end of the first quarter of fiscal 2006.

Evaluation of Disclosure Controls and Procedures

In light of the above-referenced information, we (a) conducted an evaluation of the effectiveness of the design and operation of 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”)) as of the end of the period covered by this Quarterly Report on Form 10-Q/ A (Amendment No. 3); and (b) evaluated (in connection with the evaluation required by paragraph (d) of Rule 13a-15 or 15d-15 of the Exchange Act) whether any change in our internal control over financial reporting occurred during the second quarter ended January 31, 2005 which materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. Each evaluation was done under the supervision and with the participation of management, including our Chief Executive Officer and our Interim Chief Financial Officer.

Based upon the evaluation of the effectiveness of the design of and operation of our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10-Q/ A (Amendment No. 3), our Chief Executive Officer and Interim Chief Financial Officer concluded that, because of the deficiencies referenced above, the Company’s disclosure controls and procedures were not effective as of the end of the quarterly period ended January 31, 2005.

Changes in Internal Control Over Financial Reporting

There were no material changes in our internal controls over financial reporting during the second quarter of fiscal 2005 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. We believe that the change to our internal controls and procedures designed to address the

deficiency related to the gain on sale of electricity supply contracts, the implementation of which commenced during the third quarter of fiscal 2005, and the change to our internal controls and procedures designed to address the deficiency related to the application of SFAS No. 133, the implementation of which commenced during the first quarter of fiscal 2006, each has materially affected our internal control over financial reporting.

PART II — OTHER INFORMATION


Item 1.	*Legal Proceedings.*

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

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

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

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


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

Stock Repurchases

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

Issuer Purchases of Equity Securities

(a)

(b)

(c)

(d)

Maximum

Number (or

Approximate

Dollar

Value) of

Total Number

Shares (or

of Shares

Units) that

Average

(or Units)

may yet be

Price

Purchased as

Purchased

Total Number of

Paid per

Part of Publicly

Under the

Shares (or Units)

Share

Announced Plans

Plans or

Period

Purchased

(or Unit)

or Programs

Programs

November 1 - 30, 2004

—

December 1 - 31, 2004

120,000

(1)

)

—

January 1 - 31, 2005

—

(1)

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


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

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


Item 6.	*Exhibits.*

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


Exhibit
Number			Description

	10	.1	Settlement Agreement and Mutual General Release dated December 23, 2004 by and between Commerce Energy Group, Inc, Commonwealth Energy Corporation, Ian Carter, Robert Perkins, Brad Gates, Joseph P. Saline, Patricia E. Saline and Joseph Ogundiji, previously filed with the Commission as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on December 27, 2004, which is incorporated herein by reference.
	10	.2	Commerce Energy Group, Inc. 2005 Employee Stock Purchase Plan, previously filed with the Commission as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on January 19, 2005, which is incorporated herein by reference.
	10	.3	Asset Purchase Agreement dated as of February 9, 2005 by and among Commonwealth Energy Corporation, ACN Utility Services, Inc., ACN Energy, Inc., ACN Power, Inc. and, as to certain sections thereof only, Commerce Energy Group, Inc. and American Communications Network, Inc., previously filed with the Commission as Exhibit 2.1 to the Company’s Current Report on Form 8-K filed with the Commission on February 10, 2005, which is incorporated herein by reference.
	10	.4	Transition Services Agreement dated as of February 9, 2005 by and between American Communications Network, Inc. and Commonwealth Energy Corporation, previously filed with the Commission as Exhibit 2.2 to the Company’s Current Report on Form 8-K filed with the Commission on February 10, 2005, which is incorporated herein by reference.
	10	.5	Sales Agency Agreement dated as of February 9, 2005 by and among Commonwealth Energy Corporation, Commerce Energy Group, Inc. and American Communications Network, Inc., previously filed with the Commission as Exhibit 2.3 to the Company’s Current Report on Form 8-K filed with the Commission on February 10, 2005, which is incorporated herein by reference.
	10	.6	Escrow Agreement dated as of February 9, 2005 by and among Commonwealth Energy Corporation, ACN Utility Services, Inc., ACN Energy, Inc., ACN Power, Inc., Commerce Energy Group, Inc., American Communications Network, Inc. and Computershare Trust Company, Inc., previously filed with the Commission as Exhibit 2.4 to the Company’s Current Report on Form 8-K filed with the Commission on February 10, 2005, which is incorporated herein by reference.
	10	.7	Summary of Commerce Energy Group, Inc. Management Bonus Program for 2005, previously filed with the Commission as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on March 1, 2005, which is incorporated herein by reference.
	10	.8	Offer Letter for Tom Ulry dated February 28, 2005, previously filed with the Commission as Exhibit 99.1 to the Company’s Current Report on Form 8-K filed with the Commission on March 7, 2005, which is incorporated herein by reference.
	31	.1	Principal Executive Officer Certification required by Rule 13a-14(a) under the Securities Exchange Act of 1934.
	31	.2	Principal Financial Officer Certification required by Rule 13a-14(a) under of the Securities Exchange Act of 1934.


Exhibit
Number			Description

	32	.1	Principal Executive Officer Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
	32	.2	Principal Financial Officer Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

SIGNATURES

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


	COMMERCE ENERGY GROUP, INC.


	By:	/s/ STEVEN S. BOSS



	Steven S. Boss
	Chief Executive Officer
	(Principal Executive Officer)

Date: October 31, 2005


	By:	/s/ LAWRENCE CLAYTON, JR.



	Lawrence Clayton, Jr.
	Interim Chief Financial Officer
	(Principal Financial Officer)

Date: October 31, 2005

EXHIBIT INDEX


Exhibit
Number			Description

	10	.1	Settlement Agreement and Mutual General Release dated December 23, 2004 by and between Commerce Energy Group, Inc, Commonwealth Energy Corporation, Ian B. Carter, Robert C. Perkins, Brad Gates, Joseph P. Saline, Patricia E. Saline and Joseph Ogundiji, previously filed with the Commission as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on December 27, 2004, which is incorporated herein by reference.
	10	.2	Commerce Energy Group, Inc. 2005 Employee Stock Purchase Plan, previously filed with the Commission as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on January 19, 2005, which is incorporated herein by reference.
	10	.3	Asset Purchase Agreement dated as of February 9, 2005 by and among Commonwealth Energy Corporation, ACN Utility Services, Inc., ACN Energy, Inc., ACN Power, Inc. and, as to certain sections thereof only, Commerce Energy Group, Inc. and American Communications Network, Inc., previously filed with the Commission as Exhibit 2.1 to the Company’s Current Report on Form 8-K filed with the Commission on February 10, 2005, which is incorporated herein by reference.
	10	.4	Transition Services Agreement dated as of February 9, 2005 by and between American Communications Network, Inc. and Commonwealth Energy Corporation, previously filed with the Commission as Exhibit 2.2 to the Company’s Current Report on Form 8-K filed with the Commission on February 10, 2005, which is incorporated herein by reference.
	10	.5	Sales Agency Agreement dated as of February 9, 2005 by and among Commonwealth Energy Corporation, Commerce Energy Group, Inc. and American Communications Network, Inc., previously filed with the Commission as Exhibit 2.3 to the Company’s Current Report on Form 8-K filed with the Commission on February 10, 2005, which is incorporated herein by reference.
	10	.6	Escrow Agreement dated as of February 9, 2005 by and among Commonwealth Energy Corporation, ACN Utility Services, Inc., ACN Energy, Inc., ACN Power, Inc., Commerce Energy Group, Inc., American Communications Network, Inc. and Computershare Trust Company, Inc., previously filed with the Commission as Exhibit 2.4 to the Company’s Current Report on Form 8-K filed with the Commission on February 10, 2005, which is incorporated herein by reference.
	10	.7	Summary of Commerce Energy Group, Inc. Management Bonus Program for 2005, previously filed with the Commission as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on March 1, 2005, which is incorporated herein by reference.
	10	.8	Offer Letter for Thomas L. Ulry dated February 28, 2005, previously filed with the Commission as Exhibit 99.1 to the Company’s Current Report on Form 8-K filed with the Commission on March 7, 2005,which is incorporated herein by reference.
	31	.1	Principal Executive Officer Certification required by Rule 13a-14(a) under the Securities Exchange Act of 1934.
	31	.2	Principal Financial Officer Certification required by Rule 13a-14(a) under of the Securities Exchange Act of 1934.
	32	.1	Principal Executive Officer Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
	32	.2	Principal Financial Officer Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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		with the Financial Accounting Standards Board, or FASB, Statement of Financial Accounting Standard, or SFAS, No. 133, Accounting for Derivative Instruments and Hedging Activities.

	•	Independent System Operator Costs — Included in direct energy costs, along with electric power that we purchase, are scheduling coordination costs and other ISO fees and charges. The actual ISO costs are not finalized until a settlement process by the ISO is performed for each day’s activities for all grid participants. Prior to the completion of settlement (which may take from one to several months), we estimate these costs based on historical trends and preliminary settlement information. The historical trends and preliminary information may differ from actual fees resulting in the need to adjust the previously estimated costs.

	•	Allowance for Doubtful Accounts — We maintain allowances for doubtful accounts for estimated losses resulting from non-payment of customer billings. If the financial condition of our customers were to deteriorate, resulting in an impairment of their ability to make payments, additional allowances may be required.

	•	Unbilled Receivables — Our customers are billed monthly at various dates throughout the month. Unbilled receivables represent the amount of electric power delivered to customers at the end of a reporting period, but not yet billed. Unbilled receivables from sales are estimated by us to be the number of kilowatt-hours delivered, but not yet billed, multiplied by the current customer average sales price per kilowatt-hour.

	•	Legal Matters — From time to time, we may be involved in litigation matters. We regularly evaluate our exposure to threatened or pending litigation and other business contingencies and accrue for estimated losses on such matters in accordance with SFAS No. 5, “Accounting for Contingencies.” As additional information about current or future litigation or other contingencies becomes available, management will assess whether such information warrants the recording of additional expense relating to our contingencies. Such additional expense could potentially have a material adverse impact on our results of operations and financial position.