Commerce Energy 10Q 2006 Q3 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)


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

For the quarterly period ended April 30, 2006


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

600 Anton Boulevard, Suite 2000, Costa Mesa, California (Address of principal executive offices)		92626 (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. Yesþ Noo

Indicate by check mark whether the registrant is a large accelerated filer, or a non-accelerated filer. (See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act).


Large Accelerated Filero		Accelerated filero		Non-accelerated filerþ

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yeso Noþ

As of June 9, 2006, 29,542,576 shares of the registrant’s common stock were outstanding.

COMMERCE ENERGY GROUP, INC.

Form 10-Q
For the Period Ended April 30, 2006
Index


	Page
Part I — Financial Information		2
Item 1. Financial Statements:		2
Condensed Consolidated Statements of Operations for the three and nine months ended April 30, 2006 and April 30, 2005		2
Condensed Consolidated Balance Sheets as of April 30, 2006 and July 31, 2005		3
Condensed Consolidated Statements of Cash Flows for the nine months ended April 30, 2006 and April 30, 2005		4
Notes to Condensed Consolidated Financial Statements		5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		16
Item 3. Quantitative and Qualitative Disclosures About Market Risk		34
Item 4. Controls and Procedures		34
Part II — Other Information		35
Item 1. Legal Proceedings		35
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		36
Item 5 Other Information		37
Item 6. Exhibits		38
Signatures		41
EXHIBIT 31.1
EXHIBIT 31.2
EXHIBIT 32.1
EXHIBIT 32.2
EXHIBIT 99.1

FORWARD-LOOKING INFORMATION

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

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

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

	•		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;

	•		changes in the restructuring of retail markets which could prevent us from selling electricity and natural gas on a competitive basis;

	•		our dependence upon a limited number of third-party suppliers of electricity and natural gas;

	•		our dependence upon a limited number of local electric and natural gas utilities to transmit and distribute the energy we sell to our customers, and to accurately meter and bill for the energy we supply our customers;

	•		fluctuations in market prices for electricity and natural gas;

	•		our ability to accurately forecast the expected energy needs of our electricity and natural gas customers;

	•		decisions by electricity and natural gas utilities not to raise their rates to reflect higher market cost of electricity and natural gas, thereby adversely affecting our competitiveness;

	•		our ability to successfully compete in new electricity and natural gas markets that we enter;

	•		decisions by our energy suppliers to require us to post additional collateral to support our energy purchases;

	•		our ability to obtain and retain credit necessary to support both current operations and future growth;

	•		our ability to successfully integrate businesses we may acquire;

	•		seasonal weather or force majeure events that adversely impact electricity and natural gas supply and infrastructure and which could prevent us from competitively servicing the demand requirements of our customers; and

	•		our dependence upon independent system operators, regional transmission organizations, natural gas transmission companies, and local distribution companies to properly coordinate and manage their transmission grids and distribution networks, and to accurately and timely calculate and allocate the cost of services to market participants.

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

PART I — FINANCIAL INFORMATION

Item 1.Financial Statements.

COMMERCE ENERGY GROUP, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share amounts)
(Unaudited)


	Three Months Ended					Nine Months Ended
	April 30,					April 30,
	2006		2005			2006			2005
Net revenue	$	57,755	$	68,478		$	194,777		$	188,022
Direct energy costs		49,643		60,767			174,664			164,741

Gross profit		8,112		7,711			20,113			23,281
Selling and marketing expenses		1,420		1,258			3,346			2,986
General and administrative expenses		5,911		7,993			20,367			23,029

Income (loss) from operations		781		(1,540	)		(3,600	)		(2,734	)
Other income and expenses:
Initial formation litigation expenses		—		—			—			(1,601	)
Interest income, net		221		221			710			626

Total other income and expenses		221		221			710			(975	)

Net income (loss)	$	1,002	$	(1,319	)	$	(2,890	)	$	(3,709	)

Income (loss) per common share:
Basic and diluted	$	0.03	$	(0.04	)	$	(0.09	)	$	(0.12	)

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

COMMERCE ENERGY GROUP, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except per share amounts)


	April 30, 2006			July 31, 2005
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	22,761		$	33,344
Accounts receivable, net		26,113			27,843
Inventory		1,131			4,561
Prepaid expenses and other current assets		3,004			3,542

Total current assets		53,009			69,290
Restricted cash and cash equivalents		12,901			8,222
Deposits		7,448			11,347
Property and equipment, net		3,610			2,007
Goodwill		4,801			6,801
Other intangible assets		4,158			4,965

Total assets	$	85,927		$	102,632


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	15,484		$	25,625
Accrued liabilities		7,332			6,946

Total current liabilities		22,816			32,571
Commitments and contingencies [Note 6]
Stockholders’ equity:
Common stock — 150,000 shares authorized with $0.001 par value; 31,436 shares issued and outstanding at July 31, 2005 and 29,558 (unaudited) at April 30, 2006		59,146			62,609
Unearned share-based compensation		(429	)		—
Other comprehensive loss		(168	)		—
Retained earnings		4,562			7,452

Total stockholders’ equity		63,111			70,061

Total liabilities and stockholders’ equity	$	85,927		$	102,632

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)


	Nine Months Ended
	April 30,
	2006			2005
Cash Flows From Operating Activities
Net loss	$	(2,890	)	$	(3,709	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation		801			1,001
Amortization		835			804
Provision for doubtful accounts		1,940			2,502
Impairment of Summit investments		—			5
Stock-based compensation expense		407			72
Deferred income tax provision		—			74
Changes in operating assets and liabilities:
Accounts receivable, net		(210	)		1,209
Inventory		3,430			(1,527	)
Prepaid expenses and other assets		4,407			5,926
Accounts payable		(10,140	)		(10,958	)
Accrued liabilities and other		218			3,914

Net cash used in operating activities		(1,202	)		(687	)
Cash Flows From Investing Activities
Purchase of property and equipment		(2,403	)		(670	)
Business acquisitions, net of cash acquired		—			(14,525	)

Net cash used in investing activities		(2,403	)		(15,195	)
Cash Flows From Financing Activities
Proceeds from exercise of stock options		11			50
Repurchase of stock		(2,310	)		(252	)
Sale of common stock		—			10
Increase in restricted cash and cash equivalents		(4,679	)		(1,899	)

Net cash used in financing activities		(6,978	)		(2,091	)

Decrease in cash and cash equivalents		(10,583	)		(17,973	)
Cash and cash equivalents at beginning of period		33,344			54,065

Cash and cash equivalents at end of period	$	22,761		$	36,092

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

COMMERCE ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share amounts)
(Unaudited)

1. Summary of Significant Accounting Policies

Basis of Presentation

The condensed financial statements for the three and nine months ended April 30, 2006 and 2005 of Commerce Energy Group, Inc. (“the Company”) include its two wholly-owned subsidiaries: Commerce Energy, Inc. (“Commerce”) and Skipping Stone Inc. (“Skipping Stone”). All material inter-company balances and transactions have been eliminated in consolidation.

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 and in the opinion of management, contain all adjustments (consisting of only normal recurring adjustments) necessary to present fairly the Company’s consolidated financial position, results of operations and cash flows for the periods presented. Certain information and note disclosures normally included in consolidated annual financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted in these consolidated interim financial statements, although the Company believes that the disclosures are adequate to make the information presented not misleading. The condensed consolidated results of operations, financial position, and cash flows for the interim periods presented herein are not necessarily indicative of future financial results. These interim condensed consolidated financial statements should be read in conjunction with the annual consolidated financial statements and the notes thereto included in the Company’s most recent Annual Report on Form 10-K for the year ended July 31, 2005.

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 materially differ from management’s estimates and assumptions. In preparing our financial statements and accounting for the underlying transactions and balances, we apply our accounting policies as disclosed in our notes to the condensed consolidated financial statements. The accounting policies relating to accounting for derivatives and hedging activities, inventory, independent system operator costs, allowance for doubtful accounts, revenue and unbilled receivables are those that we consider to be the most critical to an understanding of our financial statements because their application places the most significant demands on our ability to judge the effect of inherently uncertain matters on our financial results.

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)
(Dollars in thousands, except per share amounts)
(Unaudited)

Revenue Recognition

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


	Three Months Ended				Nine Months Ended
	April 30,				April 30,
	2006		2005		2006		2005
Retail electricity sales	$	37,726	$	44,754	$	132,168	$	142,251
Excess electricity sales		74		5,695		6,963		27,742

Total electricity sales		37,800		50,449		139,131		169,993
Retail natural gas sales		19,955		18,029		55,646		18,029

Net revenue	$	57,755	$	68,478	$	194,777	$	188,022

The Company purchases electricity and natural gas under forward physical delivery contracts to supply energy to its retail customers based on projected usage. Excess electricity sales include electricity supply resold back into the wholesale market.

Skipping Stone revenue (which is included in retail electricity sales above), after elimination of inter-company transactions, for the nine months ended April 30, 2006 and 2005 was $1,119 and $1,616, respectively.

Stock-Based Compensation

Effective in the first quarter of fiscal 2006, the Company adopted Statement of Financial Accounting Standards No. 123 (revised 2004),Share-Based Payments(“SFAS 123R”) which revises SFAS No. 123,Accounting for Stock-Based Compensationand supersedes APB Opinion No. 25,Accounting for Stock Issued to Employees.SFAS 123R requires all share-based payments to employees, including grants of employee stock options and restricted stock, be measured at fair value and expensed in the consolidated statement of operations over the service period (generally the vesting period). The Company uses the Black-Scholes option valuation model to value stock options. As a result of the adoption of SFAS 123R, using the modified prospective application, the Company recognized a pre-tax (tax effect minimal) charge (credit) associated with the expensing of stock options vested for the three and nine months ending April 30, 2006 of $(27) and $313, respectively, that is included in general and administrative expenses.

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


	Nine Months Ended
	April 30,
	2006			2005
Weighted-average risk-free interest rate		4.95	%		4.0	%
Average expected life in years		5.12			6.0
Expected dividends	None			None
Expected volatility		0.7731			—

COMMERCE ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollars in thousands, except per share amounts)
(Unaudited)

A summary of option activity under the Commonwealth Energy Corporation 1999 Equity Incentive Plan (the “Incentive Plan”) as of April 30, 2006 and the changes during the quarter then ended is presented below.


	Options Outstanding
						Weighted
	Number of					Average
	Shares (in			Exercise Price		Exercise
	Thousands)			Per Share		Price
Balance at January 31, 2006		8,022		$	0.05-$3.75	$	2.27
Options cancelled		(157	)	$	1.80	$	1.80
Options exercised		(221	)	$	0.05	$	0.05

Balance at April 30, 2006 (1)		7,644		$	1.00-$3.75	$	2.37


(1)		Options exercisable as of April 30, 2006 were 7,299 with a weighted average exercise price of $2.37.

As of April 30, 2006, there was $342 of total unrecognized compensation cost related to non-vested outstanding stock options, which is expected to be recognized over the period May 1, 2006 through December 1, 2008.

As of January 31, 2006 there were 345,000 shares of restricted stock issued with a total market value of $523. The total unrecognized compensation cost relating to non-vested restricted stock was $429 and will be amortized over the period of February 1, 2006 through August 1, 2009.

Prior to the adoption of SFAS 123R, the Company accounted for its employee stock options under the provision of Accounting Principles Board Opinion No. 25,Accounting for Stock Issued to Employeesand related interpretations. The Company’s compensation cost, net income (loss) or net income (loss) per share, would have reflected a nominal charge if the stock-based compensation plan had been determined based on the fair value method (estimated using Black-Scholes option pricing model) at the grant dates in accordance with Financial Accounting Standards Board Statement No. 123,Accounting for Stock-Based Compensation,of $49 and $59 for the three and nine months ended April 30, 2005.

Amended and Restated 2005 Employee Stock Purchase Plan

At the Company’s Annual Meeting of Stockholders in January 2006 (the “Annual Meeting”), the Company’s stockholders approved the Amended and Restated 2005 Employee Stock Purchase Plan (the “ESPP”). The ESPP allows eligible employees of the Company and its designated affiliates to purchase shares of the Company’s common stock through payroll deductions, subject to an aggregate limit of 3,000,000 shares of common stock that may be purchased under the ESPP. The ESPP is intended to be an “employee stock purchase plan” within the meaning of Section 423 of the Internal Revenue Code of 1986, as amended, thereby allowing participating employees to purchase shares of the Company’s common stock at a discount on a tax-favored basis pursuant to the ESPP. Under the ESPP, twelve monthly offerings (each, an “Offering”) of shares of the Company’s common stock are made each year, generally with each Offering beginning on the first day of each calendar month and ending on the last day of the same calendar month. Eligible employees may participate in one or more of the Offerings by electing to make payroll deductions during the Offering. The Company has registered the shares of common stock under the ESPP on our registration statement on Form S-8 filed with the SEC. The ESPP is in the process of being implemented and no shares have been purchased under the ESPP as of June 13, 2006.

2006 Stock Incentive Plan

At the Annual Meeting, the Company’s stockholders approved the 2006 Stock Incentive Plan (the “SIP”). The principal difference between the SIP and the Incentive Plan relates to the greater flexibility that the SIP provides with respect to the types of awards that can be granted. The Incentive Plan is basically limited to stock option and

COMMERCE ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollars in thousands, except per share amounts)
(Unaudited)

restricted stock grants, while the SIP allows grants pursuant to a variety of awards, including options, share appreciation rights, restricted shares, restricted share units, deferred share units and performance-based awards in the form of stock appreciation rights, deferred shares and performance units. Since the date of the Annual Meeting, no additional awards have been, or will be, made under the Incentive Plan. The SIP provides that no more than 1,453,334 shares of the Company’s common stock may be issued pursuant to Awards under the SIP. The Company has registered the shares of common stock under the SIP on a registration statement on Form S-8 filed with the Securities and Exchange Commission. Awards under the SIP may be made to key employees and directors of the Company or any of its subsidiaries whose participation in the SIP is determined to be in the best interests of the Company by the Compensation Committee of the Board of Directors.

Income Tax

The Company has established valuation allowances to reserve its net deferred tax assets due to the uncertainty that the Company will realize the related tax benefits in the foreseeable future.

Other Comprehensive Income (Loss)

In accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” the Company uses cash flow hedge accounting. The fair value of the derivative contracts are recorded as a current or long-term derivative assets or liabilities. Subsequent changes in the fair value of the derivative assets and liabilities are recorded on a net basis in Other comprehensive income, or OCI, and reflected as direct energy cost in the statement of operations as the related energy is delivered. The net Other comprehensive loss on designated cash flow hedged instruments was $200 and $0 for the nine months ended April 30, 2006 and 2005, respectively.

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 the single operating segment of energy retailing. As Skipping Stone, net of inter-company eliminations, only accounts for approximately 1% of total net revenue, and geographic information is not significant, no segment information is provided.

Accounts Receivable, Net

Accounts receivable, net, is comprised of the following:


	April 30,			July 31,
	2006			2005
Billed	$	20,376		$	22,017
Unbilled		9,862			11,324

	$	30,238		$	33,341
Less allowance for doubtful accounts		(4,125	)		(5,498	)

Accounts receivable, net	$	26,113		$	27,843

Inventory

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

COMMERCE ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollars in thousands, except per share amounts)
(Unaudited)

Recent Accounting Pronouncements

SFAS 154,Accounting Changes and Error Corrections, a replacement of APBO 20 and FASB Statement No. 3 (SFAS 154), applies to all voluntary changes in accounting principles and to changes required by an accounting pronouncement in instances where the pronouncement does not include specific transition provisions. APBO 20 previously required that most voluntary changes in accounting principle be recognized by including in net income of the period of the change the cumulative effect of changing to the new accounting principle. SFAS 154 requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to do so. This statement is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. No such changes have been made by the Company in fiscal 2006.

In February 2006, the FASB issued SFAS 155, an amendment of FASB Statements No. 133 (SFAS 133),Accounting for Derivative Instruments and Hedging Activities,and No. 140 (SFAS 140),Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities. SFAS 155 amends SFAS 133 to allow financial instruments that have embedded derivatives to be accounted for as a whole, if the holder elects to account for the whole instrument on a fair value basis, and provides additional guidance on the applicability of SFAS 133 and SFAS 140 to certain financial instruments and subordinated concentrations of credit risk. SFAS 155 is effective for all hybrid financial instruments acquired or issued by the company on or after January 1, 2007. The Company is currently evaluating the impact SFAS 155 will have on its consolidated financial statements, but does not expect that the impact will be material

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

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


	Three Months Ended					Nine Months Ended
	April 30,					April 30,
	2006		2005			2006			2005
Numerator:
Net income (loss)	$	1,002	$	(1,319	)	$	(2,890	)	$	(3,709	)

Net income (loss) applicable to common stock —basic and diluted	$	1,002	$	(1,319	)	$	(2,890	)	$	(3,709	)


	Three Months Ended				Nine Months Ended
	April 30,				April 30,
	(in thousands)				(in thousands)
	2006		2005		2006		2005
Denominator:
Weighted-average outstanding common shares — basic		30,186		31,199		30,659		30,799
Effect of stock options		142		—		—		—

Weighted-average outstanding common shares — diluted		30,328		31,199		30,659		30,799

COMMERCE ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollars in thousands, except per share amounts)
(Unaudited)

For the three and nine months ended April 30, 2005 and the nine months ended April 30, 2006, the effects of the assumed exercise of all stock options are anti-dilutive; accordingly, such assumed exercises and conversions have been excluded from the calculation of net income (loss) — diluted. If the assumed exercises or conversions had been used, the fully diluted shares outstanding for the three and nine months ended April 30, 2005 would have been 31,596,000 and 31,164,000, and for the nine months ended April 30, 2006 it would have been 30,881,000.

3. Market and Regulatory

The Company currently serves electricity and gas customers in nine states, operating within the jurisdictional territory of twenty different local utilities. Regulatory requirements are determined at the individual state level, and administered and monitored by the Public Utility Commission, or PUC, of each state. Operating rules and rate filings for each utility are unique and, the Company generally treats each utility distribution territory as a distinct market. Among other things, tariff filings by local distribution companies, or LDCs, for changes in their allowed billing rate to their customers in the markets in which the Company operates, significantly impact the viability of the Company’s sales and marketing plans, and its overall operating and financial results. Additionally, the Company is often required to post collateral to satisfy the operating, credit and/or regulatory requirements in each of its markets. As of April 30, 2006, the Company had posted $15,581 of performance bonds, letters of credit and cash to satisfy these requirements.

Electricity

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

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

The CPUC has made several recent determinations, including a Resource Adequacy Requirement and a Renewable Portfolio Standard, which are expected to increase our cost to serve our California electricity customers. Beginning in June 2006 the Resource Adequacy Requirement requires Load Serving Entities, or LSEs, to demonstrate that they have, or have acquired, the capacity to serve their customers including 15-17% excess power reserve margin above the forecasted customer demand. It is uncertain whether the added cost incurred by the Company to meet its resources adequacy requirement will be able to be recovered through our market sensitive sales rates to our customers. The Renewable Portfolio Standard will require the Company to purchase increasing levels of renewable power to supply to our California based customers up to a maximum of 20% of our entire customer load by 2010. Similarly, additional costs to serve customers in California are anticipated from these proceedings; however, the Company cannot predict the impact of these proceedings on the Company’s operating profitability.

In November 2005 the Federal Energy Regulatory Commission (FERC) issued an order requiring all California Scheduling Coordinators (SCs), and all Load Serving Entities (LSEs) who act as their own SCs, which include Commerce Energy, to submit day-ahead schedules that reflect purchased power equal to 95% of their forecasted

COMMERCE ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollars in thousands, except per share amounts)
(Unaudited)

daily demand. This change is expected to result in significant revisions to operating procedures to match the block shapes of the power purchased by SCs to the load shapes utilized by their customers. Failure to achieve the 95% precision required by the order may result in additional charges, penalties and/or operational adjustments. The financial impact on the Company cannot be determined at this time.

Detroit Edison un-bundled their energy and distribution charges in February, 2006. A primary component of this un-bundling included a cost shift of rate responsibility from commercial to residential customers. Also, some costs earlier considered an energy charge was shifted to the distribution side of the customer bill. This resulted in a substantial energy rate decrease for bundled customers, which had a negative impact on the Company’s ability to retain and acquire new commercial customers in the state of Michigan.

In June, 2006, the Company began enrolling commercial and residential electric customers in the Baltimore Gas & Electric (BGE) service territory in Maryland. BGE bundled utility charges are expected to change to reflect market prices as statutory rate caps are scheduled to be lifted on June 1, 2006 for non-residential customers and July 1, 2006 for residential customers. The expiration of the rate caps is expected to significantly increase the cost to customers for electricity after these dates. The Governor, along with the Maryland Public Service Commission (PSC) and BGE recently announced a plan to help consumers defer the cost increases over an extended period of time. That plan has been challenged by the Mayor and the City of Baltimore asking for a judicial review of the plan. On May 31, 2006 the judge in the case vacated the PSC plan and remanded it back to the PSC for reconsideration. The impact of these regulatory proceedings on the Company’s recent entrance into the BGE service territory cannot be predicted at this time.

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

Natural Gas

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

4. Investments

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

The two remaining companies, which are expected to continue to incur operating losses, have very limited working capital. As a result, continuing operations will be dependent upon these companies continuing to secure additional financing to meet their respective capital needs. The Company has no obligation, and currently no

COMMERCE ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollars in thousands, except per share amounts)
(Unaudited)

intention, to invest additional funds into these companies. At April 30, 2006, these two remaining investments are carried at a nominal value in other intangibles assets.

5. Acquisitions

On February 9, 2005, the Company acquired certain assets of ACN Utility Services, Inc. (“ACNU”), a subsidiary of American Communications Network, Inc. (“ACN”), and its retail electricity and natural gas sales business. ACNU sold retail electricity in Texas and Pennsylvania and sold retail natural gas in California, Georgia, Maryland, New York, Ohio and Pennsylvania. The aggregate purchase price was $14,500 in cash and 930,000 shares of the Company’s common stock, valued at $2,000. In addition, as part of the initial purchase price, the Company was required to fund $2,542 of collateralized letters of credit on the closing date to guarantee our performance to various third parties. The common stock payment, which was contingent upon ACN meeting certain sales requirements under a one year, renewable, Sales Agency Agreement between ACN and the Company (“Agreement”) during the year following the acquisition date, was placed in an escrow account. Based on subsequent sales results, the contingent common stock consideration was not earned and goodwill and stockholders’ equity were both reduced by $2,000 in the quarter ended April 30, 2006.

The assets acquired included approximately 80,000 natural gas and electricity residential and small commercial customers, natural gas inventory associated with utility and pipeline storage and transportation agreements and natural gas and electricity supply agreements, scheduling and capacity contracts, software and other infrastructure. No cash or accounts receivables were acquired in the transaction and none of ACNU’s legal liabilities were assumed. The assets purchased and the operating results generated from the acquisition have been included in the Company’s operations as of February 1, 2005, the effective date of the acquisition.

On November 28, 2005, ACN notified Commerce of its intent not to renew the Agreement and, as a result, it automatically terminated on February 9, 2006. With the termination, ACN’s network of sales representatives no longer offered the Company’s products after February 9, 2006. Commerce believes that the termination of the Agreement will not materially affect its relationships with existing customers acquired in the ACN Energy Transaction or subsequently acquired through ACN’s network of sales representatives under the Agreement.

6. Contingencies

Litigation

On February 24, 2006, ACN delivered to Commerce an arbitration demand claim, alleging that Commerce was liable for significant actual, consequential and punitive damages and restitution on a variety of causes of action including anticipatory breach of contract, unjust enrichment, tortuous interference with prospective economic advantage and prima facie tort with respect to alleged future commissions arising after the termination of the Sales Agency Agreement by ACN, effective February 9, 2006. ACN, Commerce and the Company entered into the Sales Agency Agreement in connection with the Company’s purchase of certain assets of ACN and certain of its subsidiaries in February 2005. This claim was delivered by mail to Commerce but was not filed with the American Arbitration Association (“AAA”).

On March 23, 2006, Commerce filed a Demand for Arbitration with the AAA in New York of its dispute with ACN relating to the Sales Agency Agreement asserting claims for declaratory relief, material breach of contract and breach of the implied covenant of good faith and fair dealing. This Demand for Arbitration seeks compensatory damages in an amount to be determined at the arbitration.

COMMERCE ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollars in thousands, except per share amounts)
(Unaudited)

On May 4, 2006, ACN filed with the AAA in New York its Demand for Arbitration of its dispute with the Commerce. In its Demand, ACN alleges claims against Commerce related to the Sales Agency Agreement for breach of contract and breach of implied duty of good faith and fair dealing, seeking damages and restitution in amounts to be determined at the hearing. Contrary to the demand claim delivered to us on February 24, 2006, ACN did not include claims for tortuous interference with prospective economic advantage and prima facie tort and did not included specific damage amounts in its filed demand. Although the Company cannot predict the ultimate outcome of this matter, it intends to pursue theses claims vigorously in arbitration and currently believes that no loss accrual is warranted related to this matter.

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

COMMERCE ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollars in thousands, except per share amounts)
(Unaudited)

7. Derivative Financial Instruments

The Company’s activities expose it to a variety of market risks, principally from commodity prices. Management has established risk management policies and procedures designed to reduce the potentially adverse effects that the price volatility of these markets may have on its operating results. The Company’s risk management activities, including the use of derivative instruments such as forward physical delivery contracts and financial swaps, options and futures contracts, are subject to the management, direction and control of an internal risk oversight committee. The Company maintains commodity price risk management strategies that use these derivative instruments, within approved risk tolerances, to minimize significant, unanticipated earnings fluctuations caused by commodity price volatility.

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

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

For forward or future contracts that do not meet the qualifying criteria for normal purchase, normal sale accounting treatment, the Company elects cash flow hedge accounting, where appropriate. Under cash flow hedge accounting, the fair value of the contract is recorded as a current or long-term derivative asset or liability. Subsequent changes in the fair value of the derivative assets and liabilities are recorded on a net basis in Other comprehensive income, or OCI, and reflected as direct energy cost in the statement of operations as the energy is delivered.

The amounts recorded in OCI at April 30, 2006 and July 31, 2005 related to cash flow hedges are summarized in the following table:


	April 30,			July 31,
	2006			2005
Current assets	$	150		$	—
Current liabilities		(1,342	)		—
Deferred gains		1,024			—

Other comprehensive loss	$	(168	)	$	—

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

COMMERCE ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollars in thousands, except per share amounts)
(Unaudited)

energy cost in the consolidated statement of operations for each fiscal period. For the three months and nine months ending April 30, 2006, the impact of financial derivatives accounted for as mark-to-market resulted in a loss of $1,100 and $3,300, respectively. The mark-to-market loss resulted largely from inaccuracies in determining exposure in our natural gas portfolio resulting in ineffective hedging of underlying price exposure. The notional value of these derivatives outstanding at April 30, 2006 was $2,300. As of April 30, 2006, the Company had total derivative assets of $200 included in Prepaid expenses and other, and $3,400 of total derivative liabilities included in Accrued liabilities.

8. Settlement Agreements with Former Officers

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

Under the terms of the settlement agreements, the Company agreed to pay Mr. Weigand and Mr. Boughrum lump sum settlement payments totaling $1,060 in April 2006, and agreed to purchase all of their 1,414,479 shares of the Company’s common stock at a price of $1.50 per share, with 120,000 of such shares held by Mr. Weigand being purchased by two of the independent directors of the Company. Payments for the stock by the Company were made in several installments, with the last payment made in April 2006. Under the settlement agreements, the parties agreed to mutual general releases of claims that they may have had against each other, and all of Mr. Weigand’s and Mr. Boughrum’s stock options, 1,100,000 in the aggregate, were cancelled.

In December 2005 and in February 2006, the Company entered into settlement and general release agreements with two executive officers. In connection with these agreements, the Company repurchased 184,926 shares of stock owned by these former executive officers for $1.50 per share and cancelled 178,000 stock options outstanding.

9. Subsequent Events

Secured Borrowing Facility

On June 8, 2006, the Company entered into a three-year credit agreement with a commercial lender. The facility provides for up to $50,000 for the issuance of letters of credit and for revolving working capital loans. The availability of letters of credit and loans under the facility is limited by a borrowing base consisting of the majority of the Company’s cash, receivables and natural gas inventories. Letters of credit issued under the facility are charged fees of 1.5-1.75%, while loans bear interest at a domestic bank rate plus 0.25% or at the Company’s option, LIBOR plus 2.75%.

The credit agreement contains typical covenants that restrict certain activities including, among others, limitations on capital expenditures, disposal of property and equipment, additional indebtedness, transactions with affiliates and restrictions on the issuance of capital stock and dividend payments. The credit agreement also contains customary events of default. If an event of default occurs under the credit agreement, the lenders may, among other things, suspend or terminate their commitments and declare all loans immediately due and payable.

Office Closure and Transition

On May 15, 2006, the Company announced plans to transition operational functions currently performed in Detroit, Michigan to a new office in Dallas, Texas. This realignment and transition of employees and operational functions is expected to be completed by October 2006 and result in additional expenses for one-time severance, retention and relocation costs of approximately $400. The financial impact of these costs will be reflected partly in the fourth quarter of fiscal 2006 and the remainder in the first quarter of fiscal 2007.

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

Overview

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

We were founded in 1997 as a retail electricity marketer in California and have grown to serve electricity and natural gas customers in twenty utility markets in nine states. Growth has occurred both organically and through acquisitions. In April 2004, we acquired Skipping Stone Inc., or Skipping Stone, an energy consulting company, and in February 2005, we purchased from American Communications Network, Inc. and certain of its subsidiaries, which we refer to collectively as ACN, certain assets of ACN’s retail electric power and natural gas sales business.

As of April 30, 2006, we delivered electricity to approximately 70,000 customers in California, Pennsylvania, Michigan, New Jersey and Texas; and natural gas to approximately 55,000 customers in California, Georgia, Maryland, New York, Ohio and Pennsylvania. The potential growth of our business depends upon a number of factors, including the degree of deregulation in each state, our ability to acquire new and retain existing customers, and our ability to acquire energy for our customers at competitive prices and on reasonable credit terms.

The electricity and natural gas we sell to our customers is purchased from third party suppliers under both short and long-term contracts. We do not own electricity generation or delivery facilities, natural gas producing properties or pipelines. The electricity and natural gas we sell is generally metered and always delivered to our customers by the local utilities. The local utilities also provide billing and collection services for many of our customers on our behalf. Additionally, to facilitate load shaping and demand balancing for our customers, we buy and sell surplus electricity and natural gas from and to other market participants when necessary. We utilize third party facilities for the storage of our natural gas.

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

Acquisitions

ACN Energy Transaction

On February 9, 2005, the Company acquired certain assets of ACN Utility Services, Inc. (“ACNU”), a subsidiary of American Communications Network, Inc. (“ACN”), and its retail electricity and natural gas sales business. ACNU sold retail electricity in Texas and Pennsylvania and sold retail natural gas in California, Georgia, Maryland, New York, Ohio and Pennsylvania. The aggregate purchase price was $14.5 million in cash and 930,000 shares of the Company’s common stock, valued at $2.0 million. In addition, as part of the initial purchase price, the Company was required to fund $2.5 million of collateralized letters of credit on the closing date to guarantee our performance to various third parties. The common stock payment was contingent upon ACN meeting certain sales requirements under a one year, renewable, Sales Agency Agreement between ACN and the Company, or the Sales Agency Agreement, during the year following the acquisition date, and was placed in an escrow account. Based on sales results the contingent common stock consideration was not earned and goodwill and stockholders’ equity were both reduced by $2.0 million in the quarter ended April 30, 2006. On November 28, 2005, ACN notified the Company of its intent not to renew the Sales Agency Agreement and, as a result, the Sales Agency Agreement was terminated effective February 9, 2006.

The assets acquired included approximately 80,000 natural gas-and-electricity residential and small commercial customers, natural gas inventory associated with utility and pipeline storage and transportation agreements and natural gas and electricity supply agreements, scheduling and capacity contracts, software and other infrastructure. No cash or accounts receivables were acquired in the transaction and none of ACNU’s liabilities were assumed. The assets purchased and the operating results generated from the acquisition have been included in our operations as of February 1, 2005, the effective date of the acquisition.

With the termination of the Sales Agency Agreement, ACN’s network of sales representatives no longer offered our electricity and natural gas products after February 9, 2006. Although we believe that the termination of the Sales Agency Agreement will not materially affect our relationships with existing customers acquired in the ACN Energy Transaction or subsequently acquired through ACN’s network of sales representatives under the Sales Agency Agreement, there is no assurance that we can continue to maintain the relationship with these customers.

Investments

The two remaining companies, which are expected to continue to incur operating losses, have limited working capital. As a result, continuing operations will be dependent upon these companies securing additional financing to meet their respective capital needs. We have no obligation, and currently no intention, to invest additional funds into these companies. At April 30, 2006, these two remaining investments are carried at a nominal value in Other intangibles assets.

Market and Regulatory

The Company currently serves electricity and gas customers in nine states, operating within the jurisdictional territory of twenty different local utilities. Although regulatory requirements are determined at the individual state level, and administered and monitored by the Public Utility Commission, or PUC, of each state, operating rules and rate filings for each utility are unique and the Company generally treats each utility distribution territory as a distinct market. Among other things, tariff filings by local distribution companies, or LDCs, for changes in their allowed billing rate to their customers in the markets in which the Company operates, significantly impact the viability of the Company’s sales and marketing plans, and its overall operating and financial results. Additionally, the Company is often required to post collateral to satisfy the operating, credit and/or regulatory requirements in each of its markets. As of April 30, 2006, the Company had posted $15.5 million of performance bonds, letters of credit and cash to satisfy these requirements.

Electricity

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

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

meet its resources adequacy requirement will be able to be recovered through our market sensitive sales rates to our customers. The Renewable Portfolio Standard will require the Company to purchase increasing levels of renewable power to supply to our California based customers up to a maximum of 20% of our entire customer load by 2010. Similarly, additional costs to serve customers in California are anticipated from these proceedings; however, the Company cannot predict the impact of these proceedings on the Company’s operating profitability.

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

In California, the FERC and other regulatory and judicial bodies continue to examine the behavior of market participants during the California Energy Crisis of 2000 and 2001, and to recalculate what market clearing prices should or might have been under alternative scenarios of behavior by market participants. In the event the historical costs of market operations were to be reallocated among market participants, we cannot predict whether the results would be favorable or unfavorable, or the amount of any resulting adjustment. The payment or receipt of adjustments, if any, will likely be conducted between FERC, the California ISO and our contracted scheduling coordinator for the period in question, Automated Power Exchange (APX). APX served as the direct interface with the now defunct California Power Exchange for the sale and purchase of some volumes of power by us during 2000 and 2001.

Detroit Edison un-bundled their energy and distribution charges in February 2006. A primary component of this un-bundling is to shift rate responsibility from commercial to residential customers. As a result, the commercial and industrial customers will receive a substantial energy rate decrease which may have a negative impact on the Company’s ability to retain and acquire new commercial customers in the state.

In June 2006, the Company began enrolling commercial and residential electric customers in the Baltimore Gas & Electric (BGE) service territory in Maryland. BGE bundled utility charges are expected to change to reflect market prices as statutory rate caps are scheduled to be lifted on June 1, 2006 for non-residential customers and July 1, 2006 for residential customers. The expiration of the rate caps is expected to significantly increase the cost to customers for electricity after these dates. The Governor, along with the Maryland Public Service Commission (PSC) and BGE recently announced a plan to help consumers defer the cost increases over an extended period of time. That plan has been challenged by the Mayor and the City of Baltimore asking for a judicial review of the plan. On May 31, 2006, the judge in the case vacated the PSC plan and remanded it back to the PSC for reconsideration. The impact of these regulatory proceedings on the Company’s recent entrance into the BGE service territory cannot be determined at this time.

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

Natural Gas

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

Critical Accounting Policies and Estimates

The following discussion and analysis of our financial condition and operating results are based on our condensed 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. The accounting policies discussed below are those that we consider to be most critical to an understanding of our financial statements because their application places the most significant demands on our ability to judge the effect of inherently uncertain matters on our financial results. For all of these policies, we caution that future events rarely develop exactly as forecast, and the best estimates routinely require adjustment.

	•		Accounting for Derivative Instruments and Hedging Activities— We purchase substantially all of our power and natural gas under forward physical delivery contracts for supply to our retail customers. These forward physical delivery contracts are defined as commodity derivative contracts under Statement of Financial Accounting Standard, or SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”. Using the exemption available for qualifying contracts under SFAS No. 133, we apply the normal purchase and normal sale accounting treatment to a majority of our forward physical delivery contracts. Accordingly, we record revenue generated from customer sales as energy is delivered to our retail customers and the related energy cost is recorded as direct energy costs concurrently.

			As a result of a sale on January 28, 2005 of two significant electricity forward physical delivery contracts (on a net cash settlement basis) back to the original supplier, the normal purchase and normal sale exemption was determined to not be available in our Pennsylvania market, or the PJM-ISO. Accordingly, we designate forward physical delivery contracts entered into for the PJM-ISO, and certain other forward fixed price purchases and financial derivatives as cash flow hedges, whereby mark-to-market accounting gains or losses are deferred and reported as a component of Other comprehensive income (loss) until the time of physical delivery and the fair value of the contracts is recorded as a current or long-term derivative asset or liability. Subsequent changes in the fair value of the derivative assets and liabilities are recorded on a net basis in Other comprehensive income (loss) and subsequently reclassified to direct energy cost in our consolidated Statement of Operations as the power is delivered. To the extent that the hedges are not effective, the ineffective portion of the changes in fair market value is recorded currently in direct energy costs. We intend to continue to use financial derivative instruments (such as swaps, options and futures) as an effective way of assisting in managing our price risk in energy supply procurement. Additionally, we utilize cash flow hedge accounting, where appropriate. We anticipated the normal purchase and normal sale exception will again be available to us starting in fiscal 2007.

			We also utilize other financial derivatives, primarily swaps, options and futures to hedge our commodity price risks. Certain derivative instruments, which are designated as economic hedges or as speculative, do not qualify for hedge accounting treatment and require current period mark-to-market accounting in accordance with SFAS No. 133, with fair market value being used to determine the related income or expense that is recorded each quarter in the statement of operations. As a result, the changes in fair value of derivatives that do not meet the requirements of normal purchase and normal sales accounting treatment or cash flow hedge accounting are recorded in operating income (loss) and as a current or long-term derivative asset or liability. The subsequent changes in the fair value of these contracts could result in operating income (loss) volatility as the fair value of the changes are recorded on a net basis in direct energy costs in our consolidated statement of operations for each period.

	•		Independent System Operator Costs— Included in direct energy costs, along with electricity that we purchase, are scheduling coordination costs, certain real-time net power purchase and sale cost, 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 costs resulting in the need to adjust the previous estimates.

	•		Transportation and Delivery Costs— Included in direct energy costs, along with natural gas that we purchase, are interstate pipeline costs and various non-by-passable utility service charges. These fees are recognized in the month incurred and settled in the following months.

	•		Allowance for Doubtful Accounts— We maintain an allowance for doubtful accounts based on 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 on a cycle basis as their meters are read. Unbilled receivables represent the amount of electricity and natural gas delivered to customers through the end of each calendar month, but not yet billed. Unbilled receivables from sales are estimated by us to be the number of kilowatt-hours or dekatherms delivered, but not yet billed, multiplied by the current average sales price per kilowatt-hour or dekatherms as applicable.

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

	•		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 assesses whether such information warrants the recording of additional expense. Such additional expense could potentially have a material adverse impact on our results of operations and financial position. See “Factors That May Affect Future Results – Our results of operations and financial condition could be affected by pending and future litigation.”

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 April 30, 2006 Compared to Three Months Ended April 30, 2005

The following table summarizes the results of our operations for the three months ended April 30, 2006 and 2005 (dollars in thousands).


	Three Months Ended April 30,
	2006					2005
	Dollars		% Revenue			Dollars			% Revenue
Retail electricity sales	$	37,273		65	%	$	44,334			65	%
Natural gas sales		19,955		35	%		18,029			26	%
Excess electricity sales		74		—			5,695			8	%
Other		453		—			420			1	%

Net revenue		57,755		100	%		68,478			100	%
Direct energy costs		49,643		86	%		60,767			89	%

Gross profit		8,112		14	%		7,711			11	%
Selling and marketing expenses		1,420		2	%		1,258			2	%
General and administrative expenses		5,911		10	%		7,993			11	%

Income (loss) from operations	$	781		2	%	$	(1,540	)		(2	%)

The income (loss) from operations for the three months ended April 30, 2006 improved $2.3 million from the comparable prior year period reflecting a $0.4 million increase in gross profit and $1.9 million reduction in operating expenses.

Gross profit for the third quarter of fiscal 2006 totaled $8.1 million, a 5% increase from $7.7 million in the third quarter of fiscal 2005. For the third quarter of fiscal 2006, gross profit was comprised of $3.7 million from electricity and $4.4 million from natural gas. Gross profit from electricity for the third quarter of fiscal 2006 declined $1.0 million from the comparable quarter of fiscal 2005, reflecting lower retail sales volumes partly offset by higher variable sales prices during the third quarter of fiscal 2006. Gross profit for natural gas increased $1.4 million, a 47% increase from the third quarter of fiscal 2005 reflecting higher gross profit margin on month-to-month variable contracts. Operating expenses (comprised of both selling and marketing expenses and general and administrative expenses) for the third quarter of fiscal 2006 declined 21% from the comparable quarter of fiscal 2005, reflecting lower bad debt expenses and corporate costs partly offset by higher marketing and customer acquisition costs.

Net revenue

The following table summarizes retail net revenues for the three months ended April 30, 2006 and 2005 (dollars in thousands):


	Three Months Ended April 30,
	2006					2005
	Dollars		% Revenue			Dollars		% Revenue
Retail Electricity Sales:
California	$	14,963		26	%	$	13,710		21	%
Pennsylvania/New Jersey		14,748		26	%		20,032		29	%
Michigan		3,458		6	%		7,125		10	%
All Other States, principally Texas		4,104		7	%		3,467		5	%

Total Retail Electricity Sales		37,273		65	%		44,334		65	%

Natural Gas Sales:
California		6,366		11	%		4,379		6	%
Ohio		9,006		16	%		8,582		13	%
Georgia		2,711		5	%		2,989		4	%
All Other States		1,872		3	%		2,079		3	%

Total Natural Gas Sales		19,955		35	%		18,029		26	%
Excess Electricity Sales		74		—			5,695		8	%
Other		453		—			420		1	%

Net Revenue	$	57,755		100	%	$	68,478		100	%

Net revenues for the three months ended April 30, 2006 were $57.8 million, a $10.7 million decrease from the prior comparable quarter driven primarily by the impact of a $9.0 million decrease in retail electricity sales in Pennsylvania and Michigan and a decrease of $5.6 million in wholesale excess electricity sales. These decreases were partially offset by higher retail electricity sales in California and Texas and higher natural gas sales revenues.

Retail electricity sales for the three months ended April 30, 2006 were $7.1 million below the same period in 2005 reflecting the impact of a 41% decrease in sales volume, partly offset by higher sales prices. For the three months ending April 30, 2006, we sold 372 million kilowatt hours, or kWh, at an average retail price per kWh of $0.100, as compared to 621 million kWh sold at an average retail price per kWh of $0.071 for the comparable prior year period. California sales were 181 million kWh at an average price per kWh of $0.083; compared to 173 million kWh sold at an average price per kWh of $0.079. Pennsylvania and New Jersey sales were 123 million kWh at an average price per kWh of $0.120, compared to 305 million kWh at an average price of $0.066. Sales in Michigan decreased to 36 million kWh at an average price per kWh of $0.097, compared to 111 million kWh at an average price per kWh of $0.064. Texas sales were 32 million kWh at an average price per kWh of $0.130 compared to 32 million kWh at an average price per kWh of $0.106. The $5.6 million decrease in wholesale excess electricity sales for the three months ended April 30, 2006 compared to the same period in 2005 reflects primarily the impact of shorter term forward supply commitments due to higher wholesale electricity prices, increased price volatility and conversion of many customers to month-to-month variable-priced contracts.

For the three months ending April 30, 2006, natural gas sales were $20.0 million compared to $18.0 million during the comparable period in 2005. We sold approximately 1.6 million dekatherms, or DTH, during the current period at an average price of $12.12 per DTH compared to 1.8 million DTH at an average price of $9.87 per DTH during this same period in 2005.

We had approximately 125,000 retail electricity and natural gas customers at April 30, 2006, a decrease of 17% from 150,000 at April 30, 2005. The majority of the decline in our retail customers occurred in our Pennsylvania electricity market where, beginning in April 2005, we returned approximately 21,000 residential and small commercial customers to the incumbent utility as we could no longer offer competitive service. This attrition in our

retail customer base also reflects the impact of increased sales prices to our customers resulting from our passing on higher wholesale energy supply and transmission costs, without corresponding price increases from incumbent utilities due to the lack of market responsive ratemaking and a lagging regulatory approval process. Additionally, the decline in our customer base is partly attributed to our primary sales and marketing focus on increasing our commercial customer base without a corresponding focus on smaller volume residential customers.

Direct Energy Costs

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

Direct energy costs for the three months ended April 30, 2006 totaled $33.9 million and $15.6 million for electricity and natural gas, respectively, compared to $45.7 million and $15.0 million, respectively, in the same in the prior fiscal year period.

Electricity costs averaged $0.090 per kWh for the three months ended April 30, 2006, as compared to $0.064 per kWh for the same period last year. Direct energy costs for natural gas for the three months ended April 30, 2006 averaged $9.45 per DTH as compared to $8.25 per DTH in the same period in the prior fiscal year.

Operating Expenses

Selling and marketing expenses for the three months ended April 30, 2006 were $0.2 million, or 13%, higher than the comparable three months ended April 30, 2005 due primarily to higher telemarketing, advertising and direct mail cost related to the Company’s increased customer acquisition initiatives partly offset by lower commission expenses. Sales commissions decreased $0.4 million due primarily to the cancellation of the Sales Agency Agreement between ACN and the Company effective February 9, 2006. General and administrative expenses decreased $2.1 million, or 26%, from the comparable quarter of fiscal 2005 reflecting lower bad debt and legal expenses and other corporate costs.

Benefit from Income Taxes

No provision for, or benefit from, income taxes was recorded for the three months ended April 30, 2006 or 2005. We provided valuation allowances equal to our calculated tax due to the uncertainty that we would realize these tax benefits in the foreseeable future.

Nine Months Ended April 30, 2006 Compared to Nine Months Ended April 30, 2005

The following table summarizes the results of our operations for the nine months ended April 30, 2006 and 2005 (dollars in thousands).


	Nine Months Ended April 30,
	2006						2005
	Dollars			% Revenue			Dollars			% Revenue
Retail electricity sales	$	131,049			67	%	$	140,635			75	%
Natural gas sales		55,646			28	%		18,029			9	%
Excess electricity sales		6,963			4	%		27,742			15	%
Other		1,119			1	%		1,616			1	%

Net revenue		194,777			100	%		188,022			100	%
Direct energy costs		174,664			90	%		164,741			88	%

Gross profit		20,113			10	%		23,281			12	%
Selling and marketing expenses		3,346			2	%		2,986			1	%
General and administrative expenses		20,367			10	%		23,029			12	%

Loss from operations	$	(3,600	)		(2	%)	$	(2,734	)		(1	%)

The loss from operations for the nine months ended April 30, 2006 increased $0.9 million from the comparable prior year period; due primarily to a $3.2 million decrease in gross profit, partly offset by lower operating expenses. Gross profit for the nine months ended April 30, 2006 was $20.1 million, a 14% decrease from $23.3 million for the same period in fiscal 2005. The decrease largely reflects the impact of a $7.2 million gain in January 2005 from the sale of the electricity forward supply contracts in Pennsylvania, partly offset by higher gross profit for the nine months ended April 30, 2006 in California and Pennsylvania due to higher electricity sale prices. Operating expenses decreased $2.3 million, or 9%, as lower severance and employment related settlement costs were partly offset by added direct costs related to the acquired operations of the ACN Energy assets in February 2005.

Net Revenue

The following table summarizes retail net revenues for the nine months ended April 30, 2006 and 2005 (dollars in thousands):


	Nine Months Ended April 30,
	2006					2005
	Dollars		% Revenue			Dollars		% Revenue
Retail Electricity Sales:
California	$	49,051		25	%	$	46,784		25	%
Pennsylvania/New Jersey		49,884		26	%		59,924		32	%
Michigan		18,047		9	%		30,460		16	%
All Other States, principally Texas		14,067		7	%		3,467		2	%

Total Retail Electricity Sales	$	131,049		67	%	$	140,635		75	%


Natural Gas Sales:
California		19,360		10	%	$	4,379		2	%
Ohio		22,939		12	%		8,582		4	%
Georgia		7,816		4	%		2,989		2	%
All Other States		5,531		3	%		2,079		1	%

Total Natural Gas Sales		55,646		29	%		18,029		9	%
Excess Electricity Sales		6,963		3	%		27,742		15	%
Other		1,119		1	%		1,616		1	%

Net Revenue	$	194,777		100	%	$	188,022		100	%

Net revenues for the nine months ended April 30, 2006 increased 4% from the comparable prior year period. The increase in net revenue was primarily attributable to the February 2005 addition of ACN Energy Assets partly offset by lower sales volumes in the Company’s traditional electricity markets in Pennsylvania and Michigan and lower excess electricity sales. Excess electricity sales for the nine months ended April 30, 2006 decreased to $7.0 million, compared to $27.7 million for the comparable period in 2005. This decrease reflects a sale in January 2005 of $9.3 million of electricity supply contracts in Pennsylvania and lower sales of electricity in California and Pennsylvania in the wholesale supply markets.

Retail electricity sales for the nine months ended April 30, 2006 were $131.0 million, $9.6 million below the comparable period in 2005, reflecting the impact of a 35% decrease in sales volume partly offset by higher sales prices. For the nine months ended April 30, 2006, we sold 1,343 million kWh, at an average retail price per kWh of $0.098, as compared to 2,077 million kWh sold at an average retail price per kWh of $0.068 in the same prior year period. California sales were 557 million kWh at an average price per kWh of $0.088 compared to 609 million kWh sold at an average price per kWh of $0.077. Pennsylvania and New Jersey sales were 457 million kWh at an average price per kWh of $0.109, compared to 925 million kWh at an average price of $0.065. Sales in Michigan decreased to 222 million kWh at an average price per kWh of $0.082 compared to 510 million kWh at an average price per kWh of $0.060. Texas sales were 108 million kWh at an average price per kWh of $0.130 compared to 33 million kWh at an average price per kWh of $0.106.

We acquired our natural gas business in six states in February, 2005. Natural gas sales increased to $55.6 million for the nine months ended April 30, 2006 as compared to $18.0 million for the comparable prior year period. During the nine months ended April 30, 2006, we sold approximately 4.5 million DTH at an average price of $12.41 per DTH compared to 1.8 million DTH at an average price of $9.87 per DTH in 2005.

Direct Energy Costs

pipelines, other fees and costs incurred from various energy-related service providers and energy-related taxes that cannot be passed directly through to the customer.

Direct energy costs for the nine months ended April 30, 2006 totaled $123.1 million and $51.3 million for electricity and natural gas, respectively.

Electricity costs averaged $0.086 per kWh for the nine months ended April 30, 2006, as compared to $0.062 per kWh for the same period last year. Direct energy costs for natural gas for the nine months ended April 30, 2006 averaged $11.45 per DTH.

Operating Expenses

Selling and marketing expenses for the nine months ended April 30, 2006 were $0.4 million higher than the comparable nine months ended April 30, 2005 due to increased advertising, marketing and telemarketing customer acquisition expenses, partly offset by lower salary expenses. General and administrative expenses for the nine months ended April 30, 2006 decreased $2.7 million from the nine months ended April 30, 2005 reflecting a decrease of $4.1 million in employment related settlements and severance costs and lower bad debt and corporate expenses, offset in part by added direct costs related to the acquired operations of the ACN energy assets.

Initial Formation Litigation Expenses

In the nine months ended April 30, 2005, we incurred $1.6 million of initial formation litigation costs related to Commonwealth Energy Corporation’s formation compared to no such costs in the nine months ended April 30, 2006. 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.

Benefit from Income Taxes

No provision for, or benefit from income taxes was recorded for the nine months ended April 30, 2006 or 2005. Starting in fiscal 2004, and continuing through the current period, we established a valuation allowance equal to our calculated tax benefit, because we believed it was not certain that we would realize these tax benefits in the foreseeable future.

Liquidity and Capital Resources

Our principal source of liquidity for funding our ongoing operations is our existing cash and cash equivalents. As of April 30, 2006, unrestricted cash and cash equivalents were $22.8 million compared to $33.3 million at July 31, 2005. This decrease of $10.5 million primarily reflects the use of unrestricted cash to fund a $4.7 million increase in restricted cash securing letters of credit, a $10.0 million decrease in accounts payable, $2.3 million repurchase of stock held by former officers and $2.3 million of capital expenditures offset by cash provided by a $3.9 million decrease in cash deposits with energy suppliers and utilities, a $3.4 million decrease in natural gas inventory and a $2.0 million decrease in net accounts receivable. Restricted cash and cash equivalents were $12.9 million, compared to $8.2 million at July 31, 2005.

Cash flow provided by operations for the nine months ended April 30, 2006 was $0.2 million, compared to cash flow used in operations of $0.7 million in the nine months ended April 30, 2005. Capital expenditures for the nine months ended April 30, 2006 were comprised primarily of expenditures related to the development and enhancement of information technology systems.

Credit terms from our suppliers of electricity often require us to post collateral against our energy purchases and against our mark-to-market exposure with certain of our suppliers. We currently finance these collateral obligations with our available cash. If we are required to post such additional security, a portion of our cash would become

restricted, which could adversely affect our liquidity. As of April 30, 2006, we had $12.9 million in restricted cash to secure letters of credit required by suppliers and other entities, and $7.4 million in deposits used as collateral in connection with energy purchase agreements.

On June 8, 2006, Commerce and the Company entered into a three-year credit agreement with Wachovia Capital Finance Corporation (Western) as agent and lender. The facility provides for up to $50 million for the issuance of letters of credit and for revolving working capital loans. The availability of letters of credit and loans under the facility is limited by the size of our borrowing base comprised of the majority of the Company’s cash, receivables and natural gas inventories. Letters of credit issued under the facility are charged fees of 1.5-1.75%, while loans bear interest at LIBOR plus 2.75% or at the borrower’s option, a domestic bank rate plus 0.25%.

The credit facility is guaranteed by the Company and collateralized by the assets of Commerce and the Company. Under the credit facility, the Company pledged 100% of the common stock of its two operating subsidiaries, Commerce and Skipping Stone Inc., as collateral to secure the credit facility. The asset-based facility restricts our ability to pay cash dividends on our common stock and contains standard representations and warranties, covenants and events of defaults for a facility of this size.

Based upon our current plans, level of operations and business conditions, we believe that our restricted and unrestricted cash and cash equivalents, cash generated from operations and recently completed credit facility 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

As of April 30, 2006, we have forward purchase contract commitments (entered into in the normal course of doing business) for $43.5 million in electricity and $4.0 million in gas. These contracts are for one year or less and are with various suppliers.

Factors That May Affect Future Results

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

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

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

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

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

We 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;

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

	•		our ability to obtain and retain credit at a reasonable cost to support future growth and profitability.

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 commodities as critical to their well-being as electricity and natural gas. A major focus of our marketing efforts will be to convince customers that we are a reliable provider with sufficient resources to meet our commitments. If our marketing strategy is not successful, our business, results of operations and financial condition could be materially adversely affected.

We depend upon internally developed, and, in the future will rely on vendor-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. We are currently in the process of replacing a number of our internally developed legacy software systems with vendor-developed systems. Problems that arise with the

performance of such back-office functions could result in increased expenditures, delays in the launch of our commercial operations into new markets, or unfavorable customer experiences that could materially adversely affect our business strategy. Any interruption of these services could also be disruptive to our business. As we transition from our own systems to new vendor-developed systems, we may incur duplicative expenses for a period of time and we may experience installation and integration issues with the new systems or delays in the implementation of the new systems. If we experience some or all of these new system implementation risks, we may not be able to establish a sufficient operating history for Sarbanes-Oxley 404 Attestation requirements, which we expect we must meet by no later than fiscal year ending July 31, 2007.

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

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

The terms of our credit facility may restrict our financial and operational flexibility.

The terms of our credit facility restrict, among other things, our ability to incur additional indebtedness, pay cash dividends or make certain other restricted payments, consummate certain asset sales, enter into certain transactions with affiliates, merge or consolidate with any other person or sell, assign, transfer, lease, convey, or otherwise dispose of all or substantially all of our assets. Further, the Company and its subsidiaries are required, under certain circumstances, to maintain specified financial ratios and satisfy certain financial tests. Our ability and our subsidiaries’ ability to meet those financial ratios and tests can be affected by events beyond our and their control, and there can be no assurance that we or they will meet those tests. Substantially all of our assets and the assets of our subsidiaries are pledged as security under our credit facility.

If our net worth declines, our energy suppliers who extend credit to us may demand that we post letters of credit or other additional collateral to support extensions of credit to us, which could adversely affect our liquidity and our operations.

Credit terms from our energy suppliers often require us to post collateral against our energy purchases and against our mark-to-market exposures with certain of our suppliers. If our net worth declines, our suppliers could require us to post additional collateral to support our energy purchases. Such action could adversely affect our liquidity and our operations.

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

As the price of the electricity and natural gas we purchase under term contracts is fixed for the term of the contracts, if the market price of wholesale electricity or natural gas 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.

Some suppliers of electricity have been experiencing deteriorating credit quality.

We continue to monitor the credit quality of our energy suppliers to attempt to reduce the impact of any potential counterparty default. As of April 30, 2006, 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. Deterioration in the credit quality of our energy suppliers could have an adverse impact on our sources of electricity purchases.

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

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

We are dependent on local utilities for maintenance of the infrastructure through which electricity and natural gas is delivered to our customers. We are limited in our ability to control the level of service the utilities provide to our customers. Any infrastructure failure that interrupts or impairs delivery of electricity or natural gas to our customers could have a negative effect on the satisfaction of our customers with our service, which could have a material adverse effect on our business. Regulations in many markets require that the services of reading our customers’ energy meters and the billing and collection process be retained by the local utility. The local utility’s systems and procedures may also limit or slow down our ability to add customers.

We are required to rely on utilities with whom we compete to provide us accurate and timely data.

In some states, we are required to rely on the local utility to provide us with our customers’ energy usage data and to pay us for our customers’ usage based on what the local utility collects from our customers. We may be

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

We are subject to federal and state regulations in our electricity and natural gas marketing business and the rules and regulations of regional Independent System Operators, or ISOs, in our electricity business.

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

In California, the FERC and other regulatory and judicial bodies continue to examine the behavior of market participants during the California Energy Crisis of 2000 and 2001, and to recalculate what market clearing prices should have or might have been under alternative scenarios of behavior by market participants. In the event the historical costs of market operations were to be reallocated among market participants, we cannot predict whether the results would be favorable or unfavorable for us nor can we predict the amount of such adjustments. The payment or receipt of adjustments, if any, will likely be conducted between FERC, the California ISO and our contracted scheduling coordinator for the period in question, Automated Power Exchange, or APX. APX served as our direct interface with the now defunct California Power Exchange for the sale and purchase of some volumes of power by us during 2000 and 2001.

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

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

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

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

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

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

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

	•		seasonality;

	•		unexpected changes in customer usage;

	•		transmission or transportation constraints or inefficiencies;

	•		planned and unplanned plant or transmission line outages;

	•		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 successfully integrating and managing acquired businesses and in realizing anticipated economic, operational and other benefits in a timely manner

In February 2005, we completed an acquisition of customers and related operational assets in connection with the ACN Energy Transaction. We expect that similar acquisitions of customers and related assets will be key aspects of our growth strategy. The ultimate success of an acquisition will depend, in part, on our ability to realize the anticipated synergies, cost savings and growth opportunities from integrating the assets and the relationships acquired into our existing business.

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 No. 133 and (b) a forward physical contract and several financial derivative contracts had been inappropriately accounted for as exempt from hedge accounting under SFAS No. 133. These errors in the proper application of the provisions of SFAS No. 133 required us to restate our previously reported results for each of the first three quarters in fiscal 2005 and led us to conclude and report the existence of a material weakness in our internal controls over financial reporting. We purchase substantially all of our power and natural gas under forward physical delivery contracts, which are defined as commodity derivative contracts under SFAS No. 133. We also utilize other financial derivatives, primarily swaps, options and futures, to hedge our price risks. Accordingly, proper accounting for these contracts is critical 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 2005, we are continuing to improve our internal controls, particularly in the area of energy accounting. We cannot be certain that these measures will ensure that we implement and maintain adequate controls over our financial processes and reporting in the future. Any failure to

implement required new or improved controls, or difficulties encountered in their implementation, could harm our operating results or cause us to fail to meet our reporting obligations. Inferior internal controls could also cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our stock.

Investor confidence and share value may be adversely impacted if our independent registered public accountants are unable to provide us with the attestation of the adequacy of our internal controls over financial reporting as of July 31, 2007, as applicable, 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, or the SEC, 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 registered public accountants must attest to and report on management’s assessment of the effectiveness of our internal controls over financial reporting. This requirement is expected to 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 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 and as a complement to our existing overall program of internal controls over financial reporting. As a result of this on-going review, we have made numerous improvements to the design and effectiveness of our internal controls over financial reporting through the period ended April 30, 2006. We anticipate that improvements will continue to be made.

Our results of operations and financial condition could be affected by pending and future litigation.

On February 24, 2006, American Communication Network, Inc. (“ACN”) delivered to Commerce a Demand for Arbitration, alleging that Commerce is liable for significant actual, consequential and punitive damages and restitution on a variety of causes of action including anticipatory breach of contract, unjust enrichment, tortuous interference with prospective economic advantage and prima facie tort relating to alleged future commissions arising after the termination of the Sales Agency Agreement by ACN, effective February 9, 2006. ACN, Commerce and the Company entered into the Sales Agency Agreement in connection with the Company’s purchase of certain assets of ACN and certain of its subsidiaries in February 2005. This claim was delivered by mail to Commerce but was not filed with the American Arbitration Association (“AAA”).

On March 23, 2006, Commerce filed a Demand for Arbitration with the AAA in New York of its dispute with ACN relating to the Sales Agency Agreement asserting claims for declaratory relief, material breach of contract and breach of the implied covenant of good faith and fair dealing. The Demand for Arbitration seeks compensatory damages in an amount to be determined at the arbitration hearing.

On May 4, 2006, ACN filed with the AAA in New York its Demand for Arbitration of its dispute with the Company. In its Demand, ACN alleges claims against Commerce related to the Sales Agency Agreement for breach of contract and breach of implied duty of good faith and fair dealing, seeking damages and restitution in amounts to be determined at the hearing. Contrary to the demand claim delivered to us on February 24, 2006, ACN did not

include claims for tortuous interference with prospective economic advantage and prima facie tort and did not included specific damage amounts in this filed demand.

Item 3.Quantitative and Qualitative Disclosures about Market Risk.

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

As of April 30, 2006, we had 94% of our forecasted fixed-priced energy load through July 31, 2006 covered through either fixed price power purchases with counterparties, or price protected through financial hedges.

Item 4.Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

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

Changes in Internal Control Over Financial Reporting

In connection with the above-referenced evaluation, no change in the Company’s internal control over financial reporting occurred during the period covered by this Report that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II — OTHER INFORMATION

Item 1.Legal Proceedings.

As previously reported in the Company’s Quarterly Report on Form 10-Q filed with the SEC on March 16, 2006, on February 24, 2006, the Company received a Demand for Arbitration from American Communication Network, Inc. (“ACN”) relating to the Sales Agency Agreement entered into by Commerce Energy, Inc., the Company’s wholly-owned subsidiary(“Commerce”), the Company and ACN in connection with the Company’s purchase of certain assets of ACN and certain of its subsidiaries in February 2005. The Demand relates to alleged future commissions arising after the termination of the Sales Agency Agreement by ACN, effective February 9, 2006. The Demand for Arbitration alleged claims for anticipatory breach of contract, unjust enrichment, tortuous interference with prospective economic advantage and prima facie tort alleging actual and compensatory damages estimated to be no less than $32,395,438, restitution estimated to be no less than $6,776,009 and punitive damages estimated to be no less than $45,395,438. This claim was delivered by mail to the Company but was not filed with the American Arbitration Association (“AAA”).

On March 23, 2006, the Company filed a Demand for Arbitration with the AAA in New York of its dispute with ACN relating to the Sales Agency Agreement asserting claims for declaratory relief, material breach of contract and breach of the implied covenant of good faith and fair dealing. The Demand for Arbitration seeks compensatory damages in an amount to be determined at the arbitration hearing.

On May 4, 2006, ACN filed with the AAA in New York its Demand for Arbitration of its dispute with Commerce. In its Demand, ACN alleges claims against Commerce related to the Sales Agency Agreement for breach of contract and breach of the implied duty of good faith and fair dealing, seeking damages and restitution in amounts to be determined at the hearing. In contrast to the above-referenced Demand for Arbitration delivered to the Company on February 24, 2006, ACN did not include claims for tortuous interference with prospective economic advantage and prima facie tort and did not included specific damage amounts in this filed Demand.

The Company intends to pursue the claims vigorously.

Item 2.Unregistered Sales of Equity Securities and Use of Proceeds.

Stock Repurchases

The following table sets forth our common stock repurchases for the three months ended April 30, 2006:

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)

Announced Plans

Plans or

Period

Purchased

(or Unit)

or Programs

Programs

February 1 — 28, 2006

—

March 1 — 31, 2006

10,000

(1)

.001

—

April 1 — 30, 2006

59,000

(2)

1.79

—


(1)		The Company exercised its right of repurchase pursuant to the terms of a restricted stock award agreement relating to shares of restricted common stock issued pursuant to the Commonwealth Energy Corporation 1999 Equity Incentive Plan, as amended (the “Commonwealth Incentive Plan”). Pursuant to the exercise of that repurchase right, the Company purchased 10,000 shares of the Company’s common stock at $.001 per share.

(2)		Of the aggregate 59,000 shares of the Company’s common stock repurchased, 4,000 shares of restricted common stock were repurchased at $.001 per share pursuant to the Company’s exercise of its repurchase right under a restricted stock award agreement related to shares of the Company’s common stock issued pursuant to the Commonwealth Incentive Plan; and the remaining 55,000 shares of the Company’s common stock were purchased at $1.92 per share in a settlement of a dissenter’s rights dispute relating back to the reorganization of the Company into a holding company structure which was effective on July 6, 2004.

Cancellation of Shares

On April 28, 2006, the Company cancelled 930,233 shares of its common stock (the “Shares”) returning such shares to the status of authorized but unissued shares. The Shares were initially deposited into an escrow account in connection with the Company’s purchase of certain assets of American Communications Network, Inc. (“ACN”) and certain of its subsidiaries. ACN was eligible to earn the Shares pursuant to the terms of certain of the acquisition agreements. None of the Shares were earned, the escrow agreement was terminated and the Shares were released to the Company.

Item 5.Other Information.

On June 8, 2006, the Compensation Committee of the Board of Directors of the Company awarded 40,000 shares of restricted common stock of the Company to Thomas L. Ulry, Senior Vice President of Operations of the Company, under the Commerce Energy Group, Inc. 2006 Stock Incentive Plan, or the Plan, pursuant to a Restricted Share Award Agreement (for U.S. Employees) dated June 8, 2006, or the Restricted Share Award Agreement. The 40,000 shares of restricted Common Stock will vest as follows, with any unvested shares being forfeited to the Company on the date that Mr. Ulry ceases to be an employee of the Company: 10,000 shares on June 8, 2006 and 10,000 shares on each of January 1, 2007, 2008 and 2009.

The foregoing summary of the Restricted Share Award Agreement is not complete and is qualified in its entirety by reference to the Restricted Share Award Agreement which is attached as Exhibit 99.1 to this Quarterly Report on Form 10-Q and incorporated herein by reference.

Item 6.Exhibits.

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


Exhibit
Number		Description
3.1		Amended and Restated Certificate of Incorporation of Commerce Energy Group, Inc., previously filed with the SEC on July 6, 2004 as Exhibit 3.3 to Commerce Energy Group, Inc.’s Registration Statement on Form 8-A and incorporated herein by reference.

3.2		Certificate of Designation of Series A Junior Participating Preferred Stock of Commerce Energy Group, Inc. dated July 1, 2004 previously filed with the SEC on July 6, 2004 as Exhibit 3.4 to Commerce Energy Group, Inc.’s Registration Statement on Form 8-A and incorporated herein by reference.

3.3		Amended and Restated Bylaws of Commerce Energy Group, Inc., previously filed with the SEC on July 6, 2004 as Exhibit 3.6 to Commerce Energy Group, Inc.’s Registration Statement on Form 8-A and incorporated herein by reference.

10.1		Commerce Energy Group, Inc. Amended and Restated 2005 Employee Stock Purchase Plan, previously filed with the SEC on February 1, 2006 as Exhibit 99.1 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.2		Commerce Energy Group, Inc. 2006 Stock Incentive Plan, previously filed with the SEC on February 1, 2006 as Exhibit 99.2 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.3		Commerce Energy Group, Inc. Amended and Restated Non-Employee Director Compensation Policy, effective January 27, 2006, previously filed with the SEC on February 1, 2006 as Exhibit 99.3 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.4		Commerce Energy Group, Inc. Amended and Restated Non-Employee Director Compensation Policy, effective March 10, 2006, previously filed with the SEC on March 16, 2006 as Exhibit 99.1 to Commerce Energy Group, Inc.’s Quarterly Report on Form10-Q for the Quarterly Period ended January 31, 2006 and incorporated herein by reference.

10.5		Settlement Agreement and General Release dated April 12, 2006, by and among Commerce Energy Group, Inc., Commerce Energy, Inc. and Andrew V. Coppola, previously filed with the SEC on April 18, 2006 as Exhibit 99.1 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.6		Form of Subscription Agreement for the Commerce Energy Group, Inc. Amended and Restated 2005 Employee Stock Purchase Plan, previously filed with the SEC on April 20, 2006 as Exhibit 4.7 to Commerce Energy Group, Inc.’s Registration Statement on Form S-8 (File No. 333-133442) and incorporated herein by reference.

10.7		Form of Notice of Withdrawal for the Commerce Energy Group, Inc. Amended and Restated 2005 Employee Stock Purchase Plan, previously filed with the SEC on April 20, 2006 as Exhibit 4.8 to Commerce Energy Group, Inc.’s Registration Statement on Form S-8 (File No. 333-133442) and incorporated herein by reference.

10.8		Form of a Stock Option Award Agreement for U.S. Employees pursuant to the Commerce Energy Group, Inc. 2006 Stock Incentive Plan, previously filed with the SEC on April 20, 2006 as Exhibit 4.10 to Commerce Energy Group, Inc.’s Registration Statement on Form S-8 (File No. 333-133442) and incorporated herein by reference.


Exhibit
Number		Description
10.9		Form of a Non-Qualified Stock Option Agreement for Non-Employee Directors pursuant to the Commerce Energy Group, Inc. 2006 Stock Incentive Plan, previously filed with the SEC on April 20, 2006 as Exhibit 4.11 to Commerce Energy Group, Inc.’s Registration Statement on Form S-8 (File No. 333-133442) and incorporated herein by reference.

10.10		Form of a Restricted Share Award Agreement for U.S. Employees pursuant to the Commerce Energy Group, Inc. 2006 Stock Incentive Plan, previously filed with the SEC on April 20, 2006 as Exhibit 4.12 to Commerce Energy Group, Inc.’s Registration Statement on Form S-8 (File No. 333-133442) and incorporated herein by reference.

10.11		Form of a Restricted Share Award Agreement for Non-Employee Directors pursuant to the Commerce Energy Group, Inc. 2006 Stock Incentive Plan, previously filed with the SEC on April 20, 2006 as Exhibit 4.13 to Commerce Energy Group, Inc.’s Registration Statement on Form S-8 (File No. 333-133442) and incorporated herein by reference.

10.12		Form of a Restricted Share Unit Award Agreement pursuant to the Commerce Energy Group, Inc. 2006 Stock Incentive Plan, previously filed with the SEC on April 20, 2006 as Exhibit 4.14 to Commerce Energy Group, Inc.’s Registration Statement on Form S-8 (File No. 333-133442) and incorporated herein by reference.

10.13		Form of a SAR Award Agreement pursuant to the Commerce Energy Group, Inc. 2006 Stock Incentive Plan, previously filed with the SEC on April 20, 2006 as Exhibit 4.15 to Commerce Energy Group, Inc.’s Registration Statement on Form S-8 (File No. 333-133442) and incorporated herein by reference.

10.14		Form of Performance Unit and Performance Stock Award pursuant to the Commerce Energy Group, Inc. 2006 Stock Incentive Plan, previously filed with the SEC on April 20, 2006 as Exhibit 4.16 to Commerce Energy Group, Inc.’s Registration Statement on Form S-8 (File No. 333-133442) and incorporated herein by reference.

10.15		Form of Deferral Election Agreement for Deferred Share Units to the Commerce Energy Group, Inc. pursuant to the Commerce Energy Group, Inc. 2006 Stock Incentive Plan, previously filed with the SEC on April 20, 2006 as Exhibit 4.17 to Commerce Energy Group, Inc.’s Registration Statement on Form S-8 (File No. 333-133442) and incorporated herein by reference.

10.16		Commerce Energy Group, Inc. Amended and Restated Non-Employee Director Compensation Policy, effective May 12, 2006, previously filed with the SEC on May 18, 2006 as Exhibit 99.1 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.17		Amended and Restated Form of Non-Qualified Stock Option Award Agreement (for Non-Employee Directors) pursuant to the Commerce Energy Group, Inc. 2006 Stock Incentive Plan, previously filed with the SEC on May 18, 2006 as Exhibit 99.2 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.18		Form of Restricted Share Award Agreement (for Non-Employee Directors), Initial Grant pursuant to the Commerce Energy Group, Inc. 2006 Stock Incentive Plan, previously filed with the SEC on May 18, 2006 as Exhibit 99.4 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.


Exhibit
Number		Description
31.1		Principal Executive Officer Certification required by Rule 13a-14(a) of the Securities Exchange Act of 1934.

31.2		Principal Financial Officer Certification required by Rule 13a-14(a) of the Securities Exchange Act of 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.

99.1		Restricted Share Award Agreement (for U.S. Employees) pursuant to the Commerce Energy Group, Inc. 2006 Stock Incentive Plan for Thomas L. Ulry dated June 8, 2006.

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.

Date: June 14, 2006	By:	/s/ STEVEN S. BOSS

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

Date: June 14, 2006	By:	/s/ LAWRENCE CLAYTON, JR.

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

EXHIBIT INDEX


Exhibit
Number		Description
3.1		Amended and Restated Certificate of Incorporation of Commerce Energy Group, Inc., previously filed with the SEC on July 6, 2004 as Exhibit 3.3 to Commerce Energy Group, Inc.’s Registration Statement on Form 8-A and incorporated herein by reference.

3.2		Certificate of Designation of Series A Junior Participating Preferred Stock of Commerce Energy Group, Inc. dated July 1, 2004 previously filed with the SEC on July 6, 2004 as Exhibit 3.4 to Commerce Energy Group, Inc.’s Registration Statement on Form 8-A and incorporated herein by reference.

3.3		Amended and Restated Bylaws of Commerce Energy Group, Inc., previously filed with the SEC on July 6, 2004 as Exhibit 3.6 to Commerce Energy Group, Inc.’s Registration Statement on Form 8-A and incorporated herein by reference.

10.1		Commerce Energy Group, Inc. Amended and Restated 2005 Employee Stock Purchase Plan, previously filed with the SEC on February 1, 2006 as Exhibit 99.1 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.2		Commerce Energy Group, Inc. 2006 Stock Incentive Plan, previously filed with the SEC on February 1, 2006 as Exhibit 99.2 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.3		Commerce Energy Group, Inc. Amended and Restated Non-Employee Director Compensation Policy, effective January 27, 2006, previously filed with the SEC on February 1, 2006 as Exhibit 99.3 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated here by reference.

10.4		Commerce Energy Group, Inc. Amended and Restated Non-Employee Director Compensation Policy, effective March 10, 2006, previously filed with the SEC on March 16, 2006 as Exhibit 99.1 to Commerce Energy Group, Inc.’s Quarterly Report on Form10-Q for the Quarterly Period ended January 31, 2006, and incorporated herein by reference.

10.5		Settlement Agreement and General Release dated April 12, 2006, by and among Commerce Energy Group, Inc., Commerce Energy, Inc. and Andrew V. Coppola, previously filed with the SEC on April 18, 2006 as Exhibit 99.1 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.6		Form of Subscription Agreement for the Commerce Energy Group, Inc. Amended and Restated 2005 Employee Stock Purchase Plan, previously filed with the SEC on April 20, 2006 as Exhibit 4.7 to Commerce Energy Group, Inc.’s Registration Statement on Form S-8 (File No. 333-133442) and incorporated herein by reference.

10.7		Form of Notice of Withdrawal for the Commerce Energy Group, Inc. Amended and Restated 2005 Employee Stock Purchase Plan, previously filed with the SEC on April 20, 2006 as Exhibit 4.8 to Commerce Energy Group, Inc.’s Registration Statement on Form S-8 (File No. 333-133442) and incorporated herein by reference.

10.8		Form of a Stock Option Award Agreement for U.S. Employees pursuant to the Commerce Energy Group, Inc. 2006 Stock Incentive Plan, previously filed with the SEC on April 20, 2006 as Exhibit 4.10 to Commerce Energy Group, Inc.’s Registration Statement on Form S-8 (File No. 333-133442) and incorporated herein by reference.


Exhibit
Number		Description
10.9		Form of a Non-Qualified Stock Option Agreement for Non-Employee Directors pursuant to the Commerce Energy Group, Inc. 2006 Stock Incentive Plan, previously filed with the SEC on April 20, 2006 as Exhibit 4.11 to Commerce Energy Group, Inc.’s Registration Statement on Form S-8 (File No. 333-133442) and incorporated herein by reference.

10.10		Form of a Restricted Share Award Agreement for U.S. Employees pursuant to the Commerce Energy Group, Inc. 2006 Stock Incentive Plan, previously filed with the SEC on April 20, 2006 as Exhibit 4.12 to Commerce Energy Group, Inc.’s Registration Statement on Form S-8 (File No. 333-133442) and incorporated herein by reference.

10.11		Form of a Restricted Share Award Agreement for Non-Employee Directors pursuant to the Commerce Energy Group, Inc. 2006 Stock Incentive Plan, previously filed with the SEC on April 20, 2006 as Exhibit 4.13 to Commerce Energy Group, Inc.’s Registration Statement on Form S-8 (File No. 333-133442) and incorporated herein by reference.

10.12		Form of a Restricted Share Unit Award Agreement pursuant to the Commerce Energy Group, Inc. 2006 Stock Incentive Plan, previously filed with the SEC on April 20, 2006 as Exhibit 4.14 to Commerce Energy Group, Inc.’s Registration Statement on Form S-8 (File No. 333-133442) and incorporated herein by reference.

10.13		Form of a SAR Award Agreement pursuant to the Commerce Energy Group, Inc. 2006 Stock Incentive Plan, previously filed with the SEC on April 20, 2006 as Exhibit 4.15 to Commerce Energy Group, Inc.’s Registration Statement on Form S-8 (File No. 333-133442) and incorporated herein by reference.

10.14		Form of Performance Unit and Performance Stock Award pursuant to the Commerce Energy Group, Inc. 2006 Stock Incentive Plan, previously filed with the SEC on April 20, 2006 as Exhibit 4.16 to Commerce Energy Group, Inc.’s Registration Statement on Form S-8 (File No. 333-133442) and incorporated herein by reference.

10.15		Form of Deferral Election Agreement for Deferred Share Units to the Commerce Energy Group, Inc. pursuant to the Commerce Energy Group, Inc. 2006 Stock Incentive Plan, previously filed with the SEC on April 20, 2006 as Exhibit 4.17 to Commerce Energy Group, Inc.’s Registration Statement on Form S-8 (File No. 333-133442) and incorporated herein by reference.

10.16		Commerce Energy Group, Inc. Amended and Restated Non-Employee Director Compensation Policy, effective May 12, 2006, previously filed with the SEC on May 18, 2006 as Exhibit 99.1 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.17		Amended and Restated Form of Non-Qualified Stock Option Award Agreement (for Non-Employee Directors) pursuant to the Commerce Energy Group, Inc. 2006 Stock Incentive Plan, previously filed with the SEC on May 18, 2006 as Exhibit 99.2 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.18		Form of Restricted Share Award Agreement (for Non-Employee Directors), Initial Grant pursuant to the Commerce Energy Group, Inc. 2006 Stock Incentive Plan, previously filed with the SEC on May 18, 2006 as Exhibit 99.4 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.


Exhibit
Number		Description
31.1		Principal Executive Officer Certification required by Rule 13a-14(a) of the Securities Exchange Act of 1934.

31.2		Principal Financial Officer Certification required by Rule 13a-14(a) of the Securities Exchange Act of 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.

99.1		Restricted Share Award Agreement (for U.S. Employees) pursuant to the Commerce Energy Group, Inc. 2006 Stock Incentive Plan for Thomas L. Ulry dated June 8, 2006.

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. freshman Avg

Commerce Energy (CMNR) Inactive 10-Q2006 Q3 Quarterly report

Content analysis