Commerce Energy Group, Inc.

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 January 31, 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. Yes þ No o

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 Filer o Accelerated filer o Non-accelerated filer þ

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

As of March 14, 2006, 30,266,809 shares of the registrant’s common stock were outstanding.

FORWARD-LOOKING INFORMATION

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

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

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

	•		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						Six Months Ended
	January 31,						January 31,
	2006			2005			2006			2005
Net revenue	$	72,654		$	61,048		$	137,022		$	119,545
Direct energy costs		68,892			52,639			125,020			103,975

Gross profit		3,762			8,409			12,002			15,570
Selling and marketing expenses		1,228			761			1,926			1,715
General and administrative expenses		6,847			10,043			14,456			15,050

Loss from operations		(4,313	)		(2,395	)		(4,380	)		(1,195	)
Other income and expenses:
Initial formation litigation expenses		—			(162	)		—			(1,601	)
Interest income, net		201			215			488			406

Net loss	$	(4,112	)	$	(2,342	)	$	(3,892	)	$	(2,390	)

Loss per common share:
Basic and diluted	$	(0.13	)	$	(0.08	)	$	(0.13	)	$	(0.08	)

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

COMMERCE ENERGY GROUP, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except per share amounts)


	January 31, 2006			July 31, 2005
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	13,380		$	33,344
Accounts receivable, net		38,111			27,843
Inventory		4,079			4,561
Prepaid expenses and other		8,394			3,542

Total current assets		63,964			69,290
Restricted cash and cash equivalents		10,479			8,222
Deposits		9,939			11,347
Investments		91			91
Property and equipment, net		2,857			2,007
Goodwill		6,801			6,801
Other intangible assets		4,348			4,874

Total assets	$	98,479		$	102,632


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	23,230		$	25,625
Accrued liabilities		11,966			6,946

Total current liabilities		35,196			32,571
Commitments and contingencies [see 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 30,322 (unaudited) at January 31, 2006		60,928			62,609
Share-based compensation		(183	)		—
Other comprehensive loss		(1,022	)		—
Retained earnings		3,560			7,452

Total stockholders’ equity		63,283			70,061

Total liabilities and stockholders’ equity	$	98,479		$	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)


	Six Months Ended
	January 31,
	2006			2005
Cash Flows From Operating Activities
Net loss	$	(3,892	)	$	(2,390	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation		544			683
Amortization		553			336
Provision for doubtful accounts		(268	)		1,318
Impairment of Summit investments		—			5
Stock-based compensation expense		863			48
Changes in operating assets and liabilities:
Accounts receivable, net		(10,000	)		(2,402	)
Inventory		482			—
Prepaid expenses and other assets		(3,471	)		1,992
Accounts payable		(2,395	)		(7,325	)
Accrued liabilities and other		3,998			4,505

Net cash used in operating activities		(13,586	)		(3,230	)
Cash Flows From Investing Activities
Purchase of property and equipment		(1,394	)		(325	)

Net cash used in investing activities		(1,394	)		(325	)

Cash Flows From Financing Activities
Proceeds from exercise of stock		—			50
Cancellation of common stock		—			(252	)
Issuance of restricted stock		(523	)		—
Repurchase of stock		(2,204	)		—
Increase in restricted cash and cash equivalents		(2,257	)		(325	)

Net cash used in financing activities		(4,984	)		(527	)

Decrease in cash and cash equivalents		(19,964	)		(4,082	)
Cash and cash equivalents at beginning of period		33,344			54,065

Cash and cash equivalents at end of period	$	13,380		$	49,983

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

COMMERCE ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(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 six months ended January 31, 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.

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				Six Months Ended
	January 31,				January 31,
	2006		2005		2006		2005
Retail electricity sales	$	44,352	$	44,807	$	94,442	$	97,499
Excess electricity sales		1,540		16,241		6,889		22,046

Total electricity sales		45,892		61,048		101,331		119,545
Retail natural gas sales		26,762		––		35,691		––

Net revenue	$	72,654	$	61,048	$	137,022	$	119,545

The Company purchases electricity under forward physical delivery contracts to supply electricity to its retail energy 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 six months ended January 31, 2006 and 2005 was $666 and $594, respectively, representing approximately 1% of total net revenue for each period.

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 Compensation and supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees. SFAS 123R requires all share-based payments to employees, including grants of employee stock options, be measured at fair value and expensed in the consolidated statement of operations over the service period (generally the vesting period). The Company uses the Black-Scholes option valuation model to value stock options. As a result of the adoption of SFAS 123R, using the modified prospective application, the Company recognized a pre-tax (tax effect minimal) charge associated with the expensing of stock options vested for the three and six months ending January 31, 2006 of $110 and $341, respectively. This expense is included in general and administrative expenses.

The fair value of options granted is estimated on the date of grant using the Black-Scholes model based on the 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.


	Six Months Ended
	January 31,
	2006			2005
Weighted-average risk-free interest rate		4.12	%		4.0	%
Average expected life in years		5.28			6.0
Expected dividends	None			None
Expected Volatility		0.7773			0.7773

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 January 31, 2006 and the changes during the quarter then ended is presented below.


	Options Outstanding
								Weighted-
						Weighted		Average
	Number of					Average		Fair Value
	Shares (in			Exercise Price		Exercise		of Common
	Thousands)			Per Share		Price		Stock
Balance at October 31, 2005		9,135		$	0.05-$3.75	$	2.23
Options granted (1)		120		$	1.68	$	1.68	$	1.68
Options cancelled (2)		(1,233	)	$	1.92	$	1.92

Balance at January 31, 2006 (3)		8,022		$	0.05-$3.75	$	2.27


(1)		Options were granted with exercise prices greater than the fair value of the Company’s common stock at the respective dates of grant.

(2)		See Note 8 on cancellation of former officers’ options.

(3)		Options exercisable as of January 31, 2006 were 7,652 with a weighted average exercise price of $2.29.

As of January 31, 2006, there was $190 of total unrecognized compensation cost related to non-vested outstanding stock options, which is expected to be recognized over the period February 1, 2006 through August 1, 2007.

As of January 31, 2006 there were 345,000 shares of restricted stocks issued with a total market value of $523. The total unrecognized compensation cost relating to non-vested restricted stocks is nominal 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 Employees and related interpretations. The Company’s compensation cost, net loss or loss per share, would have reflected a nominal changes if the stock-based compensation plan had been determined based on the fair value method (estimated using Black-Scholes option pricing model) at the grant dates in accordance with Financial Accounting Standards Board Statement No. 123, Accounting for Stock-Based Compensation, for the six months ended January 31, 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 (the “Code”), 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 Board of Directors intends to register the shares of common stock that will become available for issuance under the ESPP on a registration statement on Form S-8 to be filed with the SEC.

COMMERCE ENERGY GROUP, INC.

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

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 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. The Company will not make additional awards with respect to the shares of common stock that remain available for grant under the Incentive Plan as of the date of the Annual Meeting. 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 Board of Directors intends to register the shares of Common Stock that will become available for issuance under the SIP on a registration statement on Form S-8 to be filed with the SEC. 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 energy is delivered. The net Other comprehensive loss on designated cash flow hedged instruments was $1.0 million and $0 for the six months ended January 31, 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:


	January 31,			July 31,
	2006			2005
Billed	$	29,074		$	22,017
Unbilled		14,267			11,324

	$	43,341		$	33,341
Less allowance for doubtful accounts		(5,230	)		(5,498	)

Accounts receivable, net	$	38,111		$	27,843

COMMERCE ENERGY GROUP, INC.

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

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.

2. Basic and Diluted Loss per Common Share

Basic loss per common share was computed by dividing net loss available to common stockholders, by the weighted average number of common shares outstanding during the period. Diluted 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 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 loss and the denominator (common shares in thousands) used in the computation of basic and diluted loss per common share:


	Three Months Ended						Six Months Ended
	January 31,						January 31,
	2006			2005			2006			2005
Numerator:
Net loss	$	(4,112	)	$	(2,342	)	$	(3,892	)	$	(2,390	)

Net loss applicable to common stock —basic and diluted	$	(4,112	)	$	(2,342	)	$	(3,892	)	$	(2,390	)


	Three Months Ended				Six Months Ended
	January 31,				January 31,
	(in thousands)				(in thousands)
	2006		2005		2006		2005
Denominator:
Weighted-average outstanding common shares — basic		30,464		30,534		30,881		30,528
Effect of stock options		—		—		—		—

Weighted-average outstanding common shares — diluted		30,464		30,534		30,881		30,528

For the three and six months ended January 31, 2005, the effects of the assumed exercise of all stock options are anti-dilutive; accordingly, such assumed exercises and conversions have been excluded from the calculation of net loss — diluted. If the assumed exercises or conversions had been used, the fully diluted shares outstanding for the three and six months ended January 31, 2005 would have been 30,845,000 and 30,867,000, and for January 31, 2006 it would have been 30,734,000 and 31,157,000, respectively.

3. Market and Regulatory

The Company currently serves electricity and gas customers in nine states, operating within the jurisdictional territory of nineteen 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. Accordingly, the Company generally treats each utility distribution territory as a distinct market. Among other things, tariff filings by local distribution companies, or LDCs, for changes in their allowed billing rate to their customers in the markets in which the Company operates, significantly impact the viability of the Company’s sales and marketing plans, and its overall operating and financial results.

COMMERCE ENERGY GROUP, INC.

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

Electricity

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

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

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

On November 21, 2005 the Federal Energy Regulatory Commission (FERC) issued an order requiring 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 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 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.

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”. In July 29, 2005, we sold our ownership interest in Turbocor for $2,000.

COMMERCE ENERGY GROUP, INC.

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

The two remaining companies, which are expected to continue to incur operating losses, have very limited working capital. As a result, continuing operations will be dependent upon these companies securing additional financing to meet their respective immediate capital needs. The Company has no obligation, and currently no intention, to invest additional funds into these companies. At January 31, 2006, these two remaining investments are carried at a nominal value in goodwill, intangibles and other 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 sells retail electricity in Texas and Pennsylvania and sells retail natural gas in California, Georgia, Maryland, New York, Ohio and Pennsylvania. The aggregate purchase price was $14,500 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 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, and has been placed in an escrow account.

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

Based on sales results the contingent consideration will not be earned and goodwill will be reduced by substantially all of the $2,000. On November 28, 2005, ACN notified Commerce of its intent not to renew the Agreement between ACN and Commerce. As a result of ACN’s intent not to renew, the Agreement terminated automatically, on February 9, 2006.

With the termination of the Agreement, ACN’s network of sales representatives will not offer 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, and that it’s existing internal direct sales force and other developing sales channels should replace ACN’s sales network in the future.

6. Contingencies

Litigation

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

On February 24, 2006 the Company received a Demand for Arbitration from ACN under the Sales Agency Agreement previously entered into by Commerce and the Company with respect to alleged future commissions arising after the termination of the Sales Agency Agreement by ACN, effective February 9, 2006. The Demand for Arbitration alleges 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 $32,287, restitution estimated to be no less than $6,776 and punitive damages estimated to be no less than $45,395. The Company intends to vigorously defend this matter.

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 January 31, 2006 and July 31, 2005 related to cash flow hedges are summarized in the following table:


	January 31,			July 31,
	2006			2005
Current assets	$	396		$	—
Current liabilities		(1,809	)		—
Deferred gains		391			—

Other comprehensive loss	$	(1,022	)	$	—

Certain financial derivative instruments (such as swaps, options and futures), designated as economic hedges or as speculative, do not qualify or meet the requirements for normal purchase, normal sale accounting treatment or cash flow hedge accounting and are recorded currently in operating income (loss) and as a current or long-term derivative asset or liability depending on their term. The subsequent changes in the fair value of these contracts may result in operating income (loss) volatility as the fair value of the changes are recorded on a net basis in direct energy cost in the consolidated statement of operations for each fiscal period. For the three months ending January 31, 2006, the impact of financial derivatives accounted for as mark-to-market resulted in a loss of $3.1 million. The mark-to-market loss resulted largely from inaccuracies in determining exposure in our natural gas portfolio resulting

COMMERCE ENERGY GROUP, INC.

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

in ineffective hedging of underlying price exposure. The notional value of these derivatives outstanding at January 31, 2006 was $16.6 million. As of January 31, 2006, the Company had total derivative assets of $600 included in Prepaid expenses and other, and $5,100 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 shall be made in several installments, the first installment representing one half of the amount, was paid on November 28, 2005, and the other half of the payment shall be made pursuant to a promissory note to be paid in five equal installments commencing in December 2005. In connection with the term of the settlement agreements, all of Mr. Weigand’s and Mr. Boughrum’s stock options, 1,100,000 in the aggregate, were cancelled.

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

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

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

As of January 31, 2006, we delivered electricity to approximately 71,000 customers in California, Pennsylvania, Michigan, New Jersey and Texas; and natural gas to approximately 57,000 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 customers and retain existing customers, and our ability to acquire energy for our customers at competitive prices and on favorable credit terms.

The electricity and natural gas we sell to our customers is purchased from third party suppliers under 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 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 has been placed in an escrow account. Based on sales results the contingent consideration will not be earned and goodwill will be reduced by substantially all of the $2.0 million. On November 28, 2005, ACN notified the Company of its intent not to renew the Sales Agency Agreement between ACN and us. As a result of ACN’s intent not to renew, the Sales Agency Agreement terminated automatically, on 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, scheduling and capacity contracts, software and other infrastructures. 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 will no longer offer 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 very limited working capital. As a result, continuing operations will be dependent upon these companies securing additional financing to meet their respective immediate capital needs. We have no obligation, and currently no intention, to invest additional funds into these companies. At January 31, 2006, these two remaining investments are carried at a nominal value in goodwill, intangibles and other assets.

Market and Regulatory

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

Electricity

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

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

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

On November 21, 2005 the Federal Energy Regulatory Commission (FERC) issued an order accepting the California Independent System Operator’s (CAISO’s) modification to their tariff amendment number 72. This change requires all California Scheduling Coordinators (SCs), and all Load Serving Entities (LSEs) who act as their own SCs which includes Commerce Energy, to submit day-ahead schedules that reflect purchased power equal to 95% 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.

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 consolidated financial statements. The preparation of this Form 10-Q requires us to make estimates and assumptions that affect the reported amount of assets and liabilities, disclosure of contingent assets and liabilities at the date of our financial statements, and the reported amount of revenue and expenses during the reporting period. Actual results may differ from those estimates and assumptions. In preparing our financial statements and accounting for the underlying transactions and balances, we apply our accounting policies as disclosed in our notes to the condensed consolidated financial statements. The accounting policies discussed below are those that we consider to be 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 has not been available in our Pennsylvania market, or the PJM-ISO through January 31, 2006. 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 in the third quarter of fiscal 2006.

			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.

			We determined that our documentation during fiscal 2005 was inadequate for the contracts that were designated for cash flow hedge accounting treatment pursuant to the provisions of SFAS No. 133, resulting in current period mark-to-market accounting for all of our electricity forward physical contracts and financial derivatives which had previously been designated as cash flow hedges in fiscal 2005.

	•		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 utility service charges. These fees are recognized in the month incurred and settled in the following month.

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

	•		Unbilled Receivables — Our customers are billed monthly during the month on a sequential basis or on a meter read cycle. Unbilled receivables represent the amount of electricity and natural gas delivered to customers through the end of each reporting period, but not yet billed. Unbilled receivables from sales are estimated by us to be the number of kilowatt-hours or dekatherms delivered, but not yet billed, multiplied by the current 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. On February 24, 2006, we received a Demand for Arbitration relating to the Sales Agency Agreement between American Communications Network, or ACN, and Commerce Energy, Inc. alleging the Commerce is liable for actual, consequential, restitution and punitive damages on a variety of causes of actions with respect to alleged future commissions arising after the termination of the Sales Agency Agreement by ACN. At this time, management believes that no accrual for this matter is warranted. 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 January 31, 2006 Compared to Three Months Ended January 31, 2005

The following table summarizes the results of our operations for the three months ended January 31, 2006 and 2005 (dollars in thousands).


	Three Months Ended January 31,
	2006						2005
	Dollars			% Revenue			Dollars			% Revenue
Retail electricity sales	$	44,134			61	%	$	44,213			73	%
Natural gas sales		26,762			37	%		—			—
Excess electricity sales		1,540			2	%		16,241			26	%
Other		218			—			594			1	%

Net revenue		72,654			100	%		61,048			100	%
Direct energy costs		68,892			95	%		52,639			86	%

Gross profit		3,762			5	%		8,409			14	%
Selling and marketing expenses		1,228			2	%		761			1	%
General and administrative expenses		6,847			9	%		10,043			17	%

Loss from operations	$	(4,313	)		(6	%)	$	(2,395	)		(4	%)

The loss from operations for the three months ended January 31, 2006 increased $1.9 million from the comparable prior year period reflecting a $4.6 million decline in gross profit partly offset by a $2.7 million reduction in operating expenses. Gross profit for the three months ended January 31, 2005 includes a gain of $7.2 million resulting from a January, 2005 sale of electricity supply contracts for the Pennsylvania market.

Gross profit for the second quarter of fiscal 2006 totaled $3.8 million, a 55% decrease from $8.4 million in the second quarter of fiscal 2005. For the second quarter of fiscal 2006, gross profit was comprised of $5.1 million from electricity and a loss of $1.3 million from natural gas. Gross profit from electricity for the second quarter of fiscal 2006 declined $3.3 million from the comparable quarter of fiscal 2005, reflecting the impact of the gain on sale of the Pennsylvania electricity supply contracts of $7.2 million in the second quarter of fiscal 2005 and partly offset by higher variable electricity sales prices during the second quarter of fiscal 2006. The gross margin loss in the natural gas includes a mark-to-market loss of $2.7 million on supply contracts entered in December 2005, which decreased in market value due to a significant decline in natural gas prices in January 2006. The decline in market value and related loss on these contracts required mark-to-market accounting treatment under SFAS 133. The reduction in quarter over quarter operating expenses primarily reflects lower employment related settlement and severance costs.

Net revenue

The following table summarizes retail net revenues for the three months ended January 31, 2006 and 2005 (dollars in thousands):


	Three Months Ended January 31,
	2006					2005
	Dollars		% Revenue			Dollars		% Revenue
Retail Electricity Sales:
California	$	16,405		23	%	$	14,287		23	%
Pennsylvania/New Jersey		17,223		24	%		18,565		30	%
Michigan		6,740		9	%		11,361		19	%
All Other States, principally Texas		3,766		5	%		—		—

Total Retail Electricity Sales		44,134		61	%		44,213		72	%

Natural Gas Sales:
California		8,568		12	%		—		—
Ohio		11,312		16	%		—		—
Georgia		3,943		5	%		—		—
All Other States		2,939		4	%		—		—

Total Natural Gas Sales		26,762		37	%		—		—
Excess Electricity Sales		1,540		2	%		16,241		27	%
Other		218		—			594		1	%

Net Revenue	$	72,654		100	%	$	61,048		100	%

Net revenues for the three months ended January 31, 2006 increased 19% from the prior comparable quarter. This increase reflects a $30.5 million increase in net revenues from markets (primarily natural gas) added in the February 2005 acquisition of the ACN Energy assets and customers, partly offset by a $9.3 million decrease in revenues related to the January 2005 sale of electricity contracts in Pennsylvania.

Retail electricity sales for the three months ended January 31, 2006 were $44.1 million just slightly below the same period in 2005, as higher sales prices offset a 38% decrease in sales volume. For the three months ending January 31, 2006, we sold 421 million kWh, at an average retail price per kWh of $0.105, as compared to 681 million kWh sold at an average retail price per kWh of $0.065 for the comparable prior year period. California sales were 171 million kWh at an average price per kWh of $0.096; compared to 190 million kWh sold at an average price per kWh of $0.075. Pennsylvania and New Jersey sales were 143 million kWh at an average price per kWh of $0.120, compared to 301 million kWh at an average price of $0.062. Sales in Michigan decreased to 76 million kWh at an average price per kWh of $0.088 in 2006, compared to 190 million kWh at an average price per kWh of $0.060. Texas sales were 31 million kWh at an average price per kWh of $0.122.

We acquired our natural gas business in six states in February 2005. For the three months ending January 31, 2006, natural gas sales were $26.8 million. We sold approximately 2.1 million dekatherms, or DTH, during this period at an average price of $12.60 per DTH.

We had approximately 71,000 retail electricity customers at January 31, 2006, a decrease of 24% from 94,000 at January 31, 2005. The majority of the decline in our retail electricity customers occurred in our Pennsylvania 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 customer attrition in our retail electricity also largely reflects the impact of increased sales prices to our customers resulting from higher wholesale electricity supply and transmission costs without corresponding price increases from incumbent utilities due to the lack of market responsive ratemaking, and a lagging regulatory approval process. Additionally, the decline in our customer base is partly attributed to our focus on increasing our commercial and industrial base. We also had approximately 57,000 natural gas customers at January 31, 2006.

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 January 31, 2006 totaled $40.9 million and $28.0 million for electricity and natural gas, respectively.

Electricity costs averaged $0.093 per kWh for the three months ended January 31, 2006, as compared to $0.066 per kWh for the same period last year. This increase of $.027 per kWh or 41% was due to large increases in wholesale electricity pricing driven primarily by increased wholesale natural gas (used to produce much of the electricity we buy) prices. Direct energy costs for natural gas for the three months ended January 31, 2006 averaged $13.20 per DTH.

Operating Expenses

Selling and marketing expenses for the three months ended January 31, 2006 were $0.5 million higher than the comparable three months ended January 31, 2005 due primarily to increased commission costs. General and administrative expenses decreased $3.2 million from the comparable quarter of fiscal 2005 reflecting a $4.1 million decrease in employment related settlements and severance costs and lower legal expenses, offset in part by $1.6 million of added direct costs related to the acquired operations of the ACN energy assets.

Initial Formation Litigation Expenses

In the three months ended January 31, 2005, we incurred $0.2 million of initial formation litigation costs related to our initial formation compared to no such costs during the three months ended January 31, 2006. Initial formation litigation expenses include legal and litigation costs associated with the initial capital raising efforts by former 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 three months ended January 31, 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.

Six Months Ended January 31, 2006 Compared to Six Months Ended January 31, 2005

The following table summarizes the results of our operations for the six months ended January 31, 2006 and 2005 (dollars in thousands).


	Six Months Ended January 31,
	2006						2005
	Dollars			% Revenue			Dollars			% Revenue
Retail electricity sales	$	93,776			68	%	$	96,304			81	%
Natural gas sales		35,691			26	%		—			—
Excess electricity sales		6,889			5	%		22,046			18	%
Other		666			1	%		1,195			1	%

Net revenue		137,022			100	%		119,545			100	%
Direct energy costs		125,020			91	%		103,975			87	%

Gross profit		12,002			9	%		15,570			13	%
Selling and marketing expenses		1,926			1	%		1,715			1	%
General and administrative expenses		14,456			11	%		15,050			13	%

Loss from operations	$	(4,380	)		(3	%)	$	(1,195	)		(1	%)

The loss from operations for the six months ended January 31, 2006 increased $3.2 million from the comparable prior year period due primarily to a decline in gross profit. Gross profit for the six months ended January 31, 2006 was $12 million, a 23% decrease from $15.6 million for the same period in fiscal 2005. The decrease was primarily due to the $7.2 million gain on the sale of the electricity forward supply contracts in Pennsylvania in January 2005 offset by higher electricity sale prices in California and Pennsylvania and a $0.6 million gross profit contribution from the ACN Energy assets. Operating expenses decreased slightly as lower severance and employment related settlement costs were largely offset by added direct costs related to the acquired operations of the ACN energy assets.

Net Revenue

The following table summarizes retail net revenues for the six months ended January 31, 2006 and 2005 (dollars in thousands):


	Six Months Ended January 31,
	2006					2005
	Dollars		% Revenue			Dollars		% Revenue
Retail Electricity Sales:
California	$	34,089		25	%	$	33,075		28	%
Pennsylvania/New Jersey		35,135		25	%		39,893		33	%
Michigan		14,589		11	%		23,336		20	%
All Other States, principally Texas		9,963		7	%		—		—

Total Retail Electricity Sales	$	93,776		68	%	$	96,304		81	%


Natural Gas Sales:
California		12,994		9	%		—		—
Ohio		13,934		10	%		—		—
Georgia		5,107		4	%		—		—
All Other States		3,656		3	%		—		—

Total Natural Gas Sales		35,691		26	%		—		—
Excess Electricity Sales		6,889		5	%		22,046		18	%
Other		666		1	%		1,195		1	%

Net Revenue	$	137,022		100	%	$	119,545		100	%

Net revenues for the six months ended January 31, 2006 were $137.0 million, a 15% increase compared to net revenues of $119.5 million for the six months ended January 31, 2005. The increase in net revenue was primarily

attributable to the addition of the ACN Energy Assets partly offset by the impact of lower sales volumes in the Company’s traditional electricity markets in Pennsylvania and Michigan.

Retail electricity sales for the six months ended January 31, 2006 were $93.8 million, a 3% decrease from the same period in 2005. For the six months ending January 31, 2006, we sold 972 million kWh, at an average retail price per kWh of $0.097, as compared to 1,456 million kWh sold at an average retail price per kWh of $0.066 in the same prior year period. California sales were 376 million kWh at an average price per kWh of $0.091; compared to 436 million kWh sold at an average price per kWh of $0.076. Pennsylvania and New Jersey sales were 334 million kWh at an average price per kWh of $0.105, compared to 620 million kWh at an average price of $0.064. Sales in Michigan decreased to 186 million kWh at an average price per kWh of $0.078 in 2006, compared to 399 million kWh at an average price per kWh of $0.058. Texas sales were 76 million kWh at an average price per kWh of $0.130.

We acquired our natural gas business in six states in February, 2005. For the six months ending January 31, 2006, natural gas sales were $35.7 million. We sold approximately 2.8 million dekatherms, or DTH, during this period at an average price of $12.57 per DTH.

Excess electricity sales decreased to $6.9 million in the six months ended January 31, 2006 compared to 22.0 million during the same period in 2005. This decrease reflects a one-time sale in January 2005 of $9.3 million of electricity supply contracts in Pennsylvania and lower sales of excess electricity in California and Pennsylvania.

We had approximately 71,000 retail electricity customers at January 31, 2006, a decrease of 24% from 94,000 at January 31, 2005. This customer attrition in our retail electricity markets largely reflects the impact of increased sales prices to our customers resulting from higher wholesale electricity supply and transmission costs without corresponding price increases from incumbent utilities due to the lack of market responsive ratemaking and a lagging regulatory approval process. The majority of the decline in our retail electricity customers occurred in our Pennsylvania market whereby, beginning in April 2005, we returned approximately 21,000 residential and small commercial customers to the incumbent utility since we could no longer offer competitive service. Additionally, the decline in our customer base is partly attributed to our focus on increasing our commercial and industrial base. We also had approximately 57,000 natural gas customers at January 31, 2006.

Direct Energy Costs

Direct energy costs for the six months ended January 31, 2006 totaled $89.3 million and $35.7 million for electricity and natural gas, respectively.

Electricity costs averaged $0.084 per kWh for the six months ended January 31, 2006, as compared to $0.062 per kWh for the same period last year. Direct energy costs for natural gas for the six months ended January 31, 2006 averaged $12.60 per DTH.

Operating Expenses

Selling and marketing expenses for the six months ended January 31, 2006 were $0.2 million higher than the comparable six months ended January 31, 2005 due to added commission costs related to the acquisition of the ACN operations slightly offset by lower payroll expenses. General and administrative expenses for the six months ended January 31, 2006 decreased $0.6 million from the six months ended January 31, 2005. This decrease reflects $4.1 million in employment related settlements and severance costs for the second quarter fiscal 2005 and lower payroll expenses related to a reduction in headcount in 2006, offset in part by $3.4 million of added direct costs related to the acquired operations of the ACN energy assets.

Initial Formation Litigation Expenses

In the six months ended January 31, 2005, we incurred $1.6 million of initial formation litigation costs related to Commonwealth Energy Corporation’s formation compared to no such costs in the six months ended January 31, 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 six months ended January 31, 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

As of January 31, 2006, cash and cash equivalents were $13.4 million compared to $33.3 million at July 31, 2005. This decrease of $20.0 million reflects using cash to fund a $10.0 million increase in accounts receivable, $2.3 million increase in letters of credit, $4.7 million increase in prepaid energy, and a $1.2 million decrease in accounts payable. These changes in part reflect the seasonal nature of natural gas sales that require inventory buildup and the funding of additional purchases during the winter months. Restricted cash and cash equivalents were $10.5 million, compared to $8.2 million at July 31, 2005. Our principal sources of liquidity to fund ongoing operations were existing cash and cash equivalents.

Cash flow used in operations for the six months ended January 31, 2006 was $13.6 million, compared to the cash flow used in operations of $3.2 million in the six months ended January 31, 2005 primarily because of the items discussed in the preceding paragraph.

Cash flow used in investing activities for the six months ended January 31, 2006 consisted of capital expenditures.

The Company does not have open lines of credit for direct unsecured borrowings or letters of credit. Credit terms from our suppliers of electricity often require us to post collateral against our energy purchases and against our mark-to-market exposure with certain of our suppliers. We currently finance these collateral obligations with our available cash. If we are required to post such additional security, a portion of our cash would become restricted, which could adversely affect our liquidity. As of January 31, 2006, we had $10.5 million in restricted cash to secure letters of credit required by suppliers and other entities, and $9.9 million in deposits used as collateral in connection with energy purchase agreements.

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

Contractual Obligations

For the six months ended January 31, 2006, we have entered into additional electricity purchase contracts in the normal course of doing business for $33.8 million. 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 necessary credit necessary 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 a commodity as critical to their well-being as electricity and natural gas. A major focus of our marketing efforts will be to convince customers that we are a reliable provider with sufficient resources to meet our commitments. If our marketing strategy is not successful, our business, results of operations and financial condition could be materially adversely affected.

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

We are dependent on local utilities for distribution of electricity and natural gas to our customers over their distribution networks. If these local utilities are unable to properly operate their distribution networks, or if the operation of their distribution networks is interrupted for periods of time, we could be unable to deliver electricity or

natural gas to our customers during those interruptions. This would result in lost revenue to us, which could adversely impact the results of our operations.

If our net worth declines, our energy suppliers who extend credit to us may demand that we pledge additional cash or other 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.

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

As of January 31, 2006, we believe that we have adequate cash and liquidity and supplier lines of credit to sustain our business operations in the near term. To expand our business in the future, we will likely pursue external financing from banks, other financial institutions and commodity suppliers. In connection with financing arrangements, we may choose to pledge our accounts receivable and commodity inventory or commodity contracts as collateral to support the extension of credit. Additionally, we have issued and will continue to issue parent company guarantees of subsidiary obligations for commercial credit in connection with the arrangements for unsecured credit from commodity suppliers. 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 for margin to secure our obligations under our long term energy contracts.

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

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 January 31, 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 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 the direct interface with the now defunct California Power Exchange for the sale and purchase of some volumes of power by the Company during 2000 and 2001.

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

In some markets, we are 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;

	•		demand for electricity;

	•		natural gas, crude oil and refined products, and coal supply availability to generators from whom we purchase electricity; natural disasters, wars, embargoes and other catastrophic events; and

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

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

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 very important to our overall ability to report timely and accurate financial results.

We have devoted significant resources to remediate and improve our internal controls. Although we believe that these efforts have strengthened our internal controls and addressed the concerns that gave rise to the reportable conditions and material weaknesses in fiscal 2005 and 2006, we are continuing to work to improve our internal controls, particularly in the area of energy accounting. We cannot be certain that these measures will ensure that we implement and maintain adequate controls over our financial processes and reporting in the future. Any failure to implement required new or improved controls, or difficulties encountered in their implementation, could harm our operating results or cause us to fail to meet our reporting obligations. Inferior internal controls could also cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our stock.

Investor confidence and share value may be adversely impacted if our independent auditors are unable to provide us with the attestation of the adequacy of our internal controls over financial reporting as of July 31, 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 adopted rules requiring public companies to include a report of management on our internal controls over financial reporting in our Annual Reports on Form 10-K that contains an assessment by management of the effectiveness of our internal controls over financial reporting. In addition, our independent auditors must attest to and report on management’s assessment of the effectiveness of our internal controls over financial reporting. This requirement will first apply to our Annual Report on Form 10-K for the fiscal year ending July 31, 2007. How companies should be implementing these new requirements, including internal control reforms, if any, to comply with Section 404’s requirements, and how independent auditors will apply these new requirements and test companies’ internal controls, are subject to uncertainty. Although we are diligently and vigorously reviewing our internal controls over financial reporting in order to ensure compliance with the new Section 404 requirements, if our independent auditors are not satisfied with our internal controls over financial reporting or the level at which these controls are documented, designed, operated or reviewed, or if the independent auditors interpret the requirements, rules or regulations differently than we do, then they may decline to attest to management’s assessment or may issue a report that is qualified. This could result in an adverse reaction in the financial marketplace due to a loss of investor confidence in the reliability of our financial statements, which ultimately could negatively impact the market price of our shares.

We have initiated a company-wide review of our internal controls over financial reporting as part of the process of preparing for compliance with Section 404 of the Sarbanes-Oxley Act of 2002 and as a complement to our existing overall program of internal controls over financial reporting. As a result of this on-going review, we have made numerous improvements to the design and effectiveness of our internal controls over financial reporting through the period ended January 31, 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, we received a Demand for Arbitration relating to the Sales Agency Agreement between American Communications Network, or ACN, and Commerce Energy, Inc. alleging that Commerce is liable for actual and consequential damages estimated to be no less than $32,286,564, restitution estimated to be no less than $6,776,009 and punitive damages estimated to be no less than $45,395,438 with respect to alleged future commissions arising after the termination of the Sales Agency Agreement by ACN. Although we intend to pursue the claims vigorously in arbitration, we cannot predict the outcome of this arbitration or any litigation. In addition, we may become subject to additional lawsuits in the future. If we are held liable for significant damages in any arbitration or lawsuit, our operations and financial condition may be harmed. In addition, we could incur substantial expenses in connection with any such litigation, including substantial fees for attorneys and other professional advisors. These expenses could adversely affect our operations and cash position if they are material in amount. In addition, any future litigation could result in the diversion of management’s attention from the implementation of our business strategy.

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 II 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 January 31, 2006, we had 96% 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

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.

On February 24, 2006 the Company received a Demand for Arbitration from ACN under the Sales Agency Agreement previously entered into by Commerce and the Company with respect to alleged future commissions arising after the termination of the Sales Agency Agreement by ACN, effective February 9, 2006. The Demand for Arbitration alleges 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 $32,286,564, restitution estimated to be no less than $6,776,009 and punitive damages estimated to be no less than $45,395,438. The Company intends to vigorously defend this matter.

Item 1A. Risk Factors.

None.

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

Stock Repurchases

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

Share

Announced Plans

Plans or

Period

Purchased(1)(2)(3)

(or Unit)

or Programs

Programs

November 1 — 30, 2005

1,589,405

1.50

—

December 1 — 31, 2005

—

January 1 — 31, 2006

—


(1)		Pursuant to Settlement Agreement and General Release Agreements dated November 17, 2005 entered into separately with each of Peter Weigand and Richard Boughrum, the Company repurchased 994,479 and 300,000 shares of the Company’s common stock from Messrs. Weigand and Boughrum, respectively, for a price of $1.50 per share. Each Settlement and General Release Agreement became effective on November 25, 2005. In each case, one-half of the purchase price was paid on November 28, 2005 and the remaining half is being paid pursuant to a promissory note paid in five equal monthly installments commencing in December 2005. In addition, pursuant to the respective Settlement Agreements, Mr. Weigand’s and Mr. Boughrum’s options to purchase common stock of the Company, 1,100,000 in the aggregate, were cancelled.

(2)		In connection with his Settlement Agreement and General Release entered into on November 17, 2005, Mr. Weigand sold an aggregate of 120,000 shares of the Company’s common stock to two independent directors of the Company, 100,000 shares to Mr. Charles E. Bayless for $1.50 per share and 20,000 shares to Mr. Mark Juergensen for $1.50 per share. Messrs. Bayless and Juergensen each paid the full purchase price in their transaction with Mr. Weigand on November 28, 2005.

(3)		Pursuant to a Settlement Agreement and General Release Agreement dated November 17, 2005 entered into by and among the Company, its wholly-owned subsidiary, Commerce Energy, Inc. and Eric Alam, the Company repurchased 174,926 shares of the Company’s common stock from Mr. Alam for a price of $1.50 per share. Mr. Alam was paid one-half of the purchase price on November 28, 2005 and the remainder on February 27, 2006. In addition, pursuant to the Settlement Agreement, all of Mr. Alam’s options to purchase common stock of the Company, 133,333 in the aggregate, were cancelled.

Item 6. Exhibits.

The exhibits listed below are hereby filed with the Commission 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 Commission 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 Commission 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 Commission 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.

Material Contracts Relating to Management Compensation Plans or Arrangements


Exhibit
Number		Description
10.1		Settlement Agreement and General Release dated November 17, 2005 by and among Peter T. Weigand, Commerce Energy Group, Inc. and Commerce Energy, Inc., previously filed with the Commission on November 23, 2005 as Exhibit 99.1 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.2		Promissory Note dated November 17, 2005 by and between Commerce Energy Group, Inc. and Peter T. Weigand, previously filed with the Commission on November 23, 2005 as Exhibit 99.2 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.3		Voting and Standstill Agreement dated November 17, 2005, by and between Commerce Energy Group, Inc. and Peter T. Weigand, previously filed with the Commission on November 23, 2005 as Exhibit 99.3 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.4		Amendment No. 1 to Executive Employment Agreement dated November 17, 2005, by and among Commerce Energy Group, Inc., Commerce Energy, Inc. and Peter T. Weigand, previously filed with the Commission on November 23, 2005 as Exhibit 99.4 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.5		Amendment No. 1 to Agreement Not to Engage in Prohibited Activities dated November 17, 2005 by and among Commerce Energy Group, Inc., Commerce Energy, Inc. and Peter T. Weigand, previously filed with the Commission on November 23, 2005 as Exhibit 99.5 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.6		Amendment No. 1 to Agreement Not to Compete dated November 17, 2005 by and among Commerce Energy Group, Inc., Commerce Energy, Inc. and Peter T. Weigand, previously filed with the Commission on November 23, 2005 as Exhibit 99.6 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.7		Agreement and Release dated November 17, 2005, by and among, Commerce Energy Group, Inc., Commerce Energy, Inc., Paul, Hastings, Janofsky & Walker LLP, Eric G. Alam, Bruno R. Kvetinskas, Greg M. Lander and Peter T. Weigand, previously filed with the Commission on November 23, 2005 as Exhibit 99.7 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.8		Settlement Agreement and General Release dated November 17, 2005 by and among Richard L. Boughrum, Commerce Energy Group, Inc. and Commerce Energy, Inc., previously filed with the Commission on November 23, 2005 as Exhibit 99.8 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.


Exhibit
Number		Description
10.9		Promissory Note dated November 17, 2005 by and between Commerce Energy Group, Inc. and Richard L. Boughrum, previously filed with the Commission on November 23, 2005 as Exhibit 99.9 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.10		Voting and Standstill Agreement dated November 17, 2005, by and between Commerce Energy Group, Inc. and Richard L. Boughrum, previously filed with the Commission on November 23, 2005 as Exhibit 99.10 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.11		Amendment No. 1 to Executive Employment Agreement dated November 17, 2005, by and among Commerce Energy Group, Inc., Commerce Energy, Inc. and Richard L. Boughrum, previously filed with the Commission on November 23, 2005 as Exhibit 99.11 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.12		Amendment No. 1 to Agreement Not to Engage in Prohibited Activities dated November 17, 2005 by and among Commerce Energy Group, Inc., Commerce Energy, Inc. and Richard L. Boughrum, previously filed with the Commission on November 23, 2005 as Exhibit 99.12 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.13		Settlement Agreement and General Release dated November 17, 2005, by and among Commerce Energy Group, Inc., Commerce Energy, Inc. and Eric G. Alam, previously filed with the Commission on November 23, 2005 as Exhibit 99.13 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.14		Employment Agreement, dated December 1, 2005 between Lawrence Clayton, Jr. and Commerce Energy Group, Inc., previously filed with the Commission on December 6, 2005 as Exhibit 99.1 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.15		Stock Option Agreement dated December 1, 2005 between Lawrence Clayton, Jr. and Commerce Energy Group, Inc., previously filed with the Commission on December 6, 2005 as Exhibit 99.2 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.16		Restricted Stock Agreement dated December 1, 2005 between Lawrence Clayton, Jr. and Commerce Energy Group, Inc., previously filed with the Commission on December 6, 2005 as Exhibit 99.3 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.17		Indemnification Agreement dated December 1, 2005 between Lawrence Clayton, Jr. and Commerce Energy Group, Inc., previously filed with the Commission on December 6, 2005 as Exhibit 99.4 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.18		Restricted Stock Agreement dated December 12, 2005 between Andrew Coppola and Commerce Energy Group, Inc., previously filed with the Commission on December 15, 2005 as Exhibit 99.1 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.19		Form of Restricted Stock Agreement pursuant to the Commonwealth Energy Corporation 1999 Equity Incentive Plan, as amended (Time Vesting Version), previously filed with the Commission on December 15, 2005 as Exhibit 99.2 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.20		Amended and Restated 2005 Employee Stock Purchase Plan previously filed with the Commission 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.

10.21		2006 Stock Incentive Plan previously filed with the Commission 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.

Other Material Contracts


Exhibit
Number		Description

10.22		First Amendment to Sales Agency Agreement dated November 10, 2005, by and among Commerce Energy, Inc. and American Communications Network, previously filed with the Commission on November 17, 2005 as Exhibit 99.1 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

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 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99.1		Amended and Restated Non-Employee Director Compensation Policy, effective March 10, 2006.

EXHIBIT INDEX

The exhibits listed below are hereby filed with the Commission 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 Commission 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 Commission 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 Commission 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.

Material Contracts Relating to Management Compensation Plans or Arrangements


Exhibit
Number		Description
10.1		Settlement Agreement and General Release dated November 17, 2005 by and among Peter T. Weigand, Commerce Energy Group, Inc. and Commerce Energy, Inc., previously filed with the Commission on November 23, 2005 as Exhibit 99.1 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.2		Promissory Note dated November 17, 2005 by and between Commerce Energy Group, Inc. and Peter T. Weigand, previously filed with the Commission on November 23, 2005 as Exhibit 99.2 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.3		Voting and Standstill Agreement dated November 17, 2005, by and between Commerce Energy Group, Inc. and Peter T. Weigand, previously filed with the Commission on November 23, 2005 as Exhibit 99.3 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.4		Amendment No. 1 to Executive Employment Agreement dated November 17, 2005, by and among Commerce Energy Group, Inc., Commerce Energy, Inc. and Peter T. Weigand, previously filed with the Commission on November 23, 2005 as Exhibit 99.4 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.5		Amendment No. 1 to Agreement Not to Engage in Prohibited Activities dated November 17, 2005 by and among Commerce Energy Group, Inc., Commerce Energy, Inc. and Peter T. Weigand, previously filed with the Commission on November 23, 2005 as Exhibit 99.5 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.6		Amendment No. 1 to Agreement Not to Compete dated November 17, 2005 by and among Commerce Energy Group, Inc., Commerce Energy, Inc. and Peter T. Weigand, previously filed with the Commission on November 23, 2005 as Exhibit 99.6 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.7		Agreement and Release dated November 17, 2005, by and among, Commerce Energy Group, Inc., Commerce Energy, Inc., Paul, Hastings, Janofsky & Walker LLP, Eric G. Alam, Bruno R. Kvetinskas, Greg M. Lander and Peter T. Weigand, previously filed with the Commission on November 23, 2005 as Exhibit 99.7 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.8		Settlement Agreement and General Release dated November 17, 2005 by and among Richard L. Boughrum, Commerce Energy Group, Inc. and Commerce Energy, Inc., previously filed with the Commission on November 23, 2005 as Exhibit 99.8 to Commerce Energy Group, Inc.’s Current Report


Exhibit
Number		Description
		on Form 8-K and incorporated herein by reference.

10.9		Promissory Note dated November 17, 2005 by and between Commerce Energy Group, Inc. and Richard L. Boughrum, previously filed with the Commission on November 23, 2005 as Exhibit 99.9 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.10		Voting and Standstill Agreement dated November 17, 2005, by and between Commerce Energy Group, Inc. and Richard L. Boughrum, previously filed with the Commission on November 23, 2005 as Exhibit 99.10 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.11		Amendment No. 1 to Executive Employment Agreement dated November 17, 2005, by and among Commerce Energy Group, Inc., Commerce Energy, Inc. and Richard L. Boughrum, previously filed with the Commission on November 23, 2005 as Exhibit 99.11 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.12		Amendment No. 1 to Agreement Not to Engage in Prohibited Activities dated November 17, 2005 by and among Commerce Energy Group, Inc., Commerce Energy, Inc. and Richard L. Boughrum, previously filed with the Commission on November 23, 2005 as Exhibit 99.12 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.13		Settlement Agreement and General Release dated November 17, 2005, by and among Commerce Energy Group, Inc., Commerce Energy, Inc. and Eric G. Alam, previously filed with the Commission on November 23, 2005 as Exhibit 99.13 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.14		Employment Agreement, dated December 1, 2005 between Lawrence Clayton, Jr. and Commerce Energy Group, Inc., previously filed with the Commission on December 6, 2005 as Exhibit 99.1 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.15		Stock Option Agreement dated December 1, 2005 between Lawrence Clayton, Jr. and Commerce Energy Group, Inc., previously filed with the Commission on December 6, 2005 as Exhibit 99.2 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.16		Restricted Stock Agreement dated December 1, 2005 between Lawrence Clayton, Jr. and Commerce Energy Group, Inc., previously filed with the Commission on December 6, 2005 as Exhibit 99.3 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.17		Indemnification Agreement dated December 1, 2005 between Lawrence Clayton, Jr. and Commerce Energy Group, Inc., previously filed with the Commission on December 6, 2005 as Exhibit 99.4 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.18		Restricted Stock Agreement dated December 12, 2005 between Andrew Coppola and Commerce Energy Group, Inc., previously filed with the Commission on December 15, 2005 as Exhibit 99.1 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.19		Form of Restricted Stock Agreement pursuant to the Commonwealth Energy Corporation 1999 Equity Incentive Plan, as amended (Time Vesting Version), previously filed with the Commission on December 15, 2005 as Exhibit 99.2 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

10.20		Amended and Restated 2005 Employee Stock Purchase Plan previously filed with the Commission 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.

10.21		2006 Stock Incentive Plan previously filed with the Commission 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.

Other Material Contracts


Exhibit
Number		Description

10.22		First Amendment to Sales Agency Agreement dated November 10, 2005, by and among Commerce Energy, Inc. and American Communications Network, previously filed with the Commission on November 17, 2005 as Exhibit 99.1 to Commerce Energy Group, Inc.’s Current Report on Form 8-K and incorporated herein by reference.

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		Amended and Restated Non-Employee Director Compensation Policy, effective March 10, 2006.


	COMMERCE ENERGY GROUP, INC.

Date: March 16, 2006	By:	/s/ STEVEN S. BOSS

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

Date: March 16, 2006	By:	/s/ LAWRENCE CLAYTON, JR.

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

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		Page
Part I —	Financial Information		2
Item 1.	Financial Statements:		2
	Condensed Consolidated Statements of Operations for the three and six months ended January 31, 2006 and January 31, 2005		2
	Condensed Consolidated Balance Sheets as of January 31, 2006 and July 31, 2005		3
	Condensed Consolidated Statements of Cash Flows for the six months ended January 31, 2006 and January 31, 2005		4
	Notes to Condensed Consolidated Financial Statements		5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		14
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		29
Item 4.	Controls and Procedures		30
Part II —	Other Information		30
Item 1.	Legal Proceedings		30
Item 1A.	Risk Factors		30
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		31
Item 4.	Submission of Matters to a Vote of Security Holders		32
Item 5.	Other Information		32
Item 6.	Exhibits		33
Signatures			36
EXHIBIT 31.1
EXHIBIT 31.2
EXHIBIT 32.1
EXHIBIT 32.2
EXHIBIT 99.1