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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
 FORM 10-Q/A  (Mark One) þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934 For the quarterly period ended January 31, 2005 OR o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934 For the transition period fromto Commission File Number 001-32239 COMMERCE ENERGY GROUP, INC. (Exact name of registrant as specified in its charter)
 
 Delaware
    
    20-0501090(State or other jurisdiction of
    
    (I.R.S. Employerincorporation or organization)
    
    Identification No.)
 600 Anton Boulevard, Suite 2000, Costa Mesa, California 92626
(Address of principal executive offices) (Zip Code) (714) 259-2500
(Registrants telephone number, including area code) Not Applicable
(Former name, former address and former fiscal year, if changed since last report) Indicate by check mark whether the registrant (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes þ No o Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule
12b-2 of the Exchange Act). Yes o No þ As of March 11, 2005, 30,502,290 shares of the registrants common stock were
outstanding.




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EXPLANATORY NOTE This quarterly report on Form 10-Q/A (Amendment No. 1) is being filed by the Company to amend
the Companys quarterly report on Form 10-Q for the quarterly period ended January 31, 2005 filed
with the Securities and Exchange Commission on March 17, 2005. In connection with the following series of transactions, management has identified certain
deficiencies in our internal controls. In January 2005, we sold electricity commodity supply
contracts related to a strategic realignment of our customer portfolio in the Pennsylvania
electricity market and the discontinuation of service to certain classes of residential and small
commercial customers. As a result of timing issues related to realigning the portfolio and
inaccurately forecasting the resulting required electricity supply, we had transitional electricity
supply obligations which could have been served more cost effectively with the original electricity
supply contracts rather than with the replacement power which was subsequently purchased at market
prices. In the execution of this portfolio realignment, we observed deficiencies in our internal
controls relating to monitoring the operational progress of the realignment. Our independent
auditors, Ernst & Young LLP, advised us on June 8, 2005 that in their opinion, with which we
concur, these internal control deficiencies constitute reportable conditions, and collectively, a
material weakness as defined in Statement on Auditing Standards
No. 60 and that our unaudited condensed consolidated financial
statements for the three and six months periods ended January 31, 2005
should be restated. As a result of these timing and forecasting issues and internal control deficiencies, we
are restating our unaudited condensed consolidated financial
statements for the three and six months
periods ended January 31, 2005. We are restating these unaudited financial statements
to reflect the impact of this adjustment (principally, reporting a net loss
of $729,000 for the three months period ended January 31, 2005 instead of the previously reported net
income of $1,371,000 and a net loss of $1,848,000 for the six months
period ended January 31, 2005 instead of the previously reported net
income of $252,000), and to include additional disclosures in the appropriate period related to
these internal control deficiencies. This amended Quarterly Report on Form 10-Q/A principally
restates prior reported results and includes additional disclosures in the appropriate period as a
result of the foregoing weaknesses in our internal controls. This Form 10-Q/A has not been updated except as required to reflect the effects of the
restatement. This amendment and restatement includes changes to Part I, Items 1, 2 and 4 and Part
II, Item 6. Except as identified in the prior sentence, no other item included in the original
Form 10-Q has been amended, and such items shall remain in effect as of the filing date of the
original Form 10-Q. Additionally, this Form 10-Q/A does not purport to provide an update or
discussion of any other developments at the Company subsequent to its original filing.




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COMMERCE ENERGY GROUP, INC. Form 10-Q/A
For the Period Ended January 31, 2005
Index PagePart I  Financial InformationItem 1. Financial Statements:Condensed Consolidated Statements of Operations for the three and six months ended
January 31, 2004 and 2005
    
    
    1Condensed Consolidated Balance Sheets as of July 31, 2004 and January 31, 2005
    
    
    2Condensed Consolidated Statements of Cash Flows for the three and six months ended
January 31, 2004 and 2005
    
    
    3Notes to Condensed Consolidated Financial Statements
    
    
    4Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
    
    
    12Item 3. Quantitative and Qualitative Disclosures About Market Risk
    
    
    25Item 4. Controls and Procedures
    
    
    26Part II  Other InformationItem 1. Legal Proceedings
    
    
    28Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities
    
    
    28Item 4. Submission of Matters to a Vote of Security Holders
    
    
    29Item 6. Exhibits
    
    
    30Signatures
    
    
    31EXHIBIT 31.1EXHIBIT 31.2EXHIBIT 32.1EXHIBIT 32.2




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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. The discussion of
such matters and subject areas is qualified by the inherent risks and uncertainties surrounding
future expectations generally, and also may differ materially from our actual future experience
involving any one or more of such matters and subject areas. We wish to caution readers that all
statements other than statements of historical fact included in this Quarterly Report on Form 10-Q
regarding our financial position and strategy may constitute forward-looking statements. When used
in this document, the words anticipate, believe, estimate, expect, intend, may,
project, plan, should, and similar expressions are intended to be among the statements that
identify forward-looking statements. All of these forward-looking statements are based upon
estimates and assumptions made by our management, which although believed to be reasonable, are
inherently uncertain. Therefore, undue reliance should not be placed on such estimates and
statements. No assurance can be given that any of such estimates or statements will be realized and
it is likely that actual results will differ materially from those contemplated by such
forward-looking statements. Factors that may cause such differences include those set forth in this
Quarterly Report on Form 10-Q, as well as the following:  
    regulatory changes in the states in which we operate that could adversely affect our operations;
    our continued ability to obtain and maintain licenses from the states in which we operate;
    the competitive restructuring of retail marketing may prevent us from selling electricity in certain states;
    our dependence upon a limited number of third parties to generate and supply to us electricity;
    fluctuations in market prices for electricity;
    our dependence on the Independent System Operators in each of the states where we
operate, to properly coordinate and manage their electric grids, and to accurately and
timely calculate and allocate the charges to the participants for the numerous related
services provided;
    our ability to obtain credit necessary to support future growth and profitability; and
    our dependence upon a limited number of utilities to transmit and distribute the
electricity we sell to our customers. We have attempted to identify, in context, certain of the factors that we currently believe
may cause actual future experience and results to differ from our current expectations regarding
the relevant matter or subject area. In addition to the items specifically discussed above, our
business and results of operations are subject to the risks and uncertainties described in this
Report in Part I, Item 2. Managements Discussion and Analysis of Financial Condition and Results
of Operations and in our Annual Report on Form 10-K for the year ended July 31, 2004 which we filed
with the Securities and Exchange Commission on November 15, 2004. In evaluating forward-looking
statements, you should consider these risks and uncertainties, together with the other risks
described from time to time in our reports and documents filed with the Securities and Exchange
Commission, and you should not place undue reliance on these statements. These forward-looking
statements speak only as of the date on which the statements were made. We assume no obligation to
update the forward-looking information to reflect actual results or changes in the factors
affecting such forward-looking information.




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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 January 31,
    
    
    Six Months Ended January 31,2004
    
    
    2005
    
    
    2004
    
    
    2005(Restated)
    
    
    
    
    
    
    (Restated)Net revenue
    
    $
    47,038
    
    
    $
    61,048
    
    
    $
    105,434
    
    
    $
    119,545Direct energy costs
    
    
    43,783
    
    
    
    51,026
    
    
    
    97,858
    
    
    
    103,433Gross profit
    
    
    3,255
    
    
    
    10,022
    
    
    
    7,576
    
    
    
    16,112Selling and marketing expenses
    
    
    1,008
    
    
    
    761
    
    
    
    1,978
    
    
    
    1,715General and administrative expenses
    
    
    5,829
    
    
    
    10,043
    
    
    
    11,347
    
    
    
    15,050Reorganization and initial public
listing expenses
    
    
    1,028
    
    
    
    
    
    
    
    1,146
    
    
    
    Loss from operations
    
    
    (4,610
    )
    
    
    (782
    )
    
    
    (6,895
    )
    
    
    (653
    )Other income and expenses:Initial formation litigation expenses
    
    
    
    
    
    
    (162
    )
    
    
    (585
    )
    
    
    (1,601
    )Provision for impairment on
investments
    
    
    (4,313
    )
    
    
    
    
    
    
    (4,313
    )
    
    
    Minority interest share of loss
    
    
    351
    
    
    
    
    
    
    
    895
    
    
    
    Interest income, net
    
    
    151
    
    
    
    215
    
    
    
    281
    
    
    
    406Total other income and expenses
    
    
    (3,811
    )
    
    
    53
    
    
    
    (3,722
    )
    
    
    (1,195
    )Loss before benefit from income taxes
    
    
    (8,421
    )
    
    
    (729
    )
    
    
    (10,617
    )
    
    
    (1,848
    )Benefit from income taxes
    
    
    768
    
    
    
    
    
    
    
    1,842
    
    
    
    Net loss
    
    $
    (7,653
    )
    
    $
    (729
    )
    
    $
    (8,775
    )
    
    $
    (1,848
    )Loss per common share:Basic
    
    $
    (0.28
    )
    
    $
    (0.02
    )
    
    $
    (0.32
    )
    
    $
    (0.06
    )Diluted
    
    $
    (0.28
    )
    
    $
    (0.02
    )
    
    $
    (0.32
    )
    
    $
    (0.06
    )
 The accompanying notes are an integral part of these condensed consolidated financial statements. 1




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COMMERCE ENERGY GROUP,
INC. 
 CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands)
 July 31, 2004
    
    
    January 31, 2005(Unaudited)(Restated)ASSETSCurrent assets:Cash and cash equivalents
    
    $
    54,065
    
    
    $
    49,983Accounts receivable, net
    
    
    31,119
    
    
    
    32,272Income taxes refund receivable
    
    
    4,423
    
    
    
    4,430Deferred income tax asset
    
    
    74
    
    
    
    74Prepaid expenses and other current assets
    
    
    5,141
    
    
    
    1,278Total current assets
    
    
    94,822
    
    
    
    88,037Restricted cash and cash equivalents
    
    
    4,008
    
    
    
    4,333Deposits
    
    
    5,445
    
    
    
    6,699Investments
    
    
    96
    
    
    
    91Property and equipment, net
    
    
    2,613
    
    
    
    2,253Goodwill and other intangible assets
    
    
    3,839
    
    
    
    3,504Total assets
    
    $
    110,823
    
    
    $
    104,917LIABILITIES AND STOCKHOLDERS EQUITYCurrent liabilities:Accounts payable
    
    $
    30,576
    
    
    $
    23,251Accrued liabilities
    
    
    6,141
    
    
    
    10,104Total current liabilities
    
    
    36,717
    
    
    
    33,355Stockholders equity:Common stock  150,000 shares authorized
with $0.001 par value; 30,519 and 30,499
shares issued and outstanding at July 31,
2004 and January 31, 2005, respectively
    
    
    60,796
    
    
    
    60,594Unearned restricted stock compensation
    
    
    (256
    )
    
    
    (208
    )Retained earnings
    
    
    13,566
    
    
    
    11,718Other comprehensive loss
    
    
    
    
    
    
    (542
    )Total stockholders equity
    
    
    74,106
    
    
    
    71,562Total liabilities and stockholders equity
    
    $
    110,823
    
    
    $
    104,917
 The accompanying notes are an integral part of these condensed consolidated financial statements. 2




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COMMERCE ENERGY GROUP,
INC. 
 CONDENSED CONSOLIDATED
STATEMENTS OF CASH FLOWS
 (In thousands)
(Unaudited)
 Six months ended January 31,2004
    
    
    2005(Restated)Cash Flows From Operating ActivitiesNet loss
    
    $
    (8,775
    )
    
    $
    (1,848
    )Adjustments to reconcile net income (loss) to net cash
provided by (used in) operating activities:Depreciation
    
    
    761
    
    
    
    683Amortization
    
    
    127
    
    
    
    336Provision for doubtful accounts
    
    
    1,125
    
    
    
    1,318Impairment of Summit investments
    
    
    4,843
    
    
    
    5Stock-based compensation expense
    
    
    
    
    
    
    48Minority interest share of loss of consolidated entity
    
    
    (282
    )
    
    
    Changes in operating assets and liabilities:Accounts receivable, net
    
    
    13,249
    
    
    
    (2,402
    )Prepaid expenses and other assets
    
    
    1,318
    
    
    
    1,992Accounts payable
    
    
    (6,685
    )
    
    
    (7,325
    )Accrued liabilities and other
    
    
    (258
    )
    
    
    3,963Net cash provided by (used in) operating activities
    
    
    5,423
    
    
    
    (3,230
    )Cash Flows From Investing ActivitiesPurchase of property and equipment
    
    
    (571
    )
    
    
    (325
    )Net cash used in investing activities
    
    
    (571
    )
    
    
    (325
    )Cash Flows From Financing ActivitiesProceeds from exercise of stock
    
    
    1
    
    
    
    50Cancellation of common stock
    
    
    
    
    
    
    (252
    )Decrease (increase) in restricted cash and cash equivalents
    
    
    8,602
    
    
    
    (325
    )Net cash provided by (used in) financing activities
    
    
    8,603
    
    
    
    (527
    )Increase (decrease) in cash and cash equivalents
    
    
    13,455
    
    
    
    (4,082
    )Cash and cash equivalents at beginning of period
    
    
    40,921
    
    
    
    54,065Cash and cash equivalents at end of period
    
    $
    54,376
    
    
    $
    49,983
 The accompanying notes are an integral part of these condensed consolidated financial statements. 3




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COMMERCE ENERGY GROUP,
INC. 
 NOTES TO CONDENSED
CONSOLIDATED FINANCIAL STATEMENTS
 (in thousands, except per share and per kWh amounts)
 2005. Summary of Significant Accounting Policies Basis of Presentation The condensed consolidated financial statements for the three and six months ended January 31,
2005 include the accounts of Commerce Energy Group, Inc. (the Company), its three wholly-owned
subsidiaries: Commonwealth Energy Corporation doing business under the brand name electricAmerica,
Skipping Stone Inc. (Skipping Stone), which was acquired on April 1, 2004, and UtiliHost, Inc.
All material intercompany balances and transactions have been eliminated in consolidation. At January 31, 2004, the Companys consolidated financial statements included the accounts of
its controlled investment in Summit Energy Ventures, LLC (Summit), and its majority ownership in
Power Efficiency Corporation (PEC). In the fourth quarter of fiscal 2004, the Company terminated
its relationship with Summit and its investment in PEC decreased to 39.9% and subsequently, to
36.4% at January 31, 2005. As of July 31, 2004 and as of January 31, 2005, both entities were no
longer consolidated. (See Note 4). Preparation of Interim Condensed Consolidated Financial Statements These interim condensed consolidated financial statements have been prepared by the Companys
management, without audit, in accordance with accounting principles generally accepted in the
United States. In the opinion of management, these financial statements contain all adjustments
(consisting of only normal recurring adjustments) necessary to present fairly the Companys
consolidated financial position, results of operations and cash flows for the periods presented.
Certain information and note disclosures normally included in consolidated annual financial
statements prepared in accordance with accounting principles generally accepted in the United
States have been condensed or omitted in these consolidated interim financial statements, although
the Company believes that the disclosures are adequate to make the information presented not
misleading. The condensed consolidated results of operations, financial position, and cash flows
for the interim periods presented herein are not necessarily indicative of future financial
results. These interim condensed consolidated financial statements should be read in conjunction
with the annual consolidated financial statements and the notes thereto included in the Companys
most recent Annual Report on Form 10-K for the year ended July 31, 2004. Uses of Estimates The preparation of condensed consolidated financial statements in conformity with accounting
principles generally accepted in the United States requires management to make certain estimates
and assumptions that affect the reported amounts and timing of revenue and expenses, the reported
amounts and classification of assets and liabilities, and disclosure of contingent assets and
liabilities. These estimates and assumptions are based on the Companys historical experience as
well as managements future expectations. As a result, actual results could differ from
managements estimates and assumptions. The Companys management believes that its most critical
estimates herein relate to independent system operator costs, allowance for doubtful accounts,
unbilled receivables and loss contingencies. Reclassifications Certain amounts in the condensed consolidated financial statements for the comparative prior
fiscal period have been reclassified to be consistent with the current fiscal periods
presentation. 4




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COMMERCE ENERGY GROUP, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(continued)
(in thousands, except per share and per kWh amounts) Revenue Recognition Energy sales are recognized as the electric power is delivered to customers. The Companys net
revenue is comprised of the following: Three months ended
    
    
    Six months ended JanuaryJanuary 31,
    
    
    31,2004
    
    
    2005
    
    
    2004
    
    
    2005Retail energy sales
    
    $
    46,034
    
    
    $
    44,807
    
    
    $
    102,181
    
    
    $
    97,499Excess energy sales
    
    
    1,004
    
    
    
    16,241
    
    
    
    3,253
    
    
    
    22,046Net revenue
    
    $
    47,038
    
    
    $
    61,048
    
    
    $
    105,434
    
    
    $
    119,545
 Skipping Stone revenue (which is included in retail energy sales above), after elimination of
intercompany transactions, for the three and six months ended January 31, 2005 was $595 and $1,195,
respectively, representing approximately 1% of total net revenue for both periods. Stock-Based Compensation The Company accounts for its employee stock options under the recognition and measurement
principles of Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees
(APB No. 25), and related interpretations. Under APB No. 25, no stock-based employee compensation
costs are reflected in net income (loss) for the three and six month periods ended January 31, 2005
and 2004, because all options granted under the plans had an exercise price equal to or greater
than the market value of the underlying common stock on the date of grant. The following table illustrates the effect on net income (loss) as applicable to common stock
(see Note 2) and income (loss) per common share if the Company had applied the fair value
recognition provisions of Statement of Financial Accounting Standards (SFAS) No. 123: Three months ended
    
    
    Six months ended JanuaryJanuary 31,
    
    
    31,2004
    
    
    2005
    
    
    2004
    
    
    2005(Restated)
    
    
    
    
    
    
    (Restated)Net income (loss)
as applicable to common
stock  basic and
diluted
    
    $
    (7,679
    )
    
    $
    (729
    )
    
    $
    (8,827
    )
    
    $
    ( 1,848
    )Deduct: Total
stock-based
compensation expense
determined under fair
value based method for
all awards, net of
related tax effects
    
    
    (9
    )
    
    
    (7
    )
    
    
    (92
    )
    
    
    (10
    )Pro forma net income
(loss)  basic and
diluted
    
    $
    (7,688
    )
    
    $
    (736
    )
    
    $
    (8,919
    )
    
    $
    (1,858
    )Income (loss) per share:Basic  as reported
    
    $
    (0.28
    )
    
    $
    (0.02
    )
    
    $
    (0.32
    )
    
    $
    (0.06
    )Basic  pro forma
    
    $
    (0.28
    )
    
    $
    (0.02
    )
    
    $
    (0.32
    )
    
    $
    (0.06
    )Diluted  as reported
    
    $
    (0.28
    )
    
    $
    (0.02
    )
    
    $
    (0.32
    )
    
    $
    (0.06
    )Diluted  pro forma
    
    $
    (0.28
    )
    
    $
    (0.02
    )
    
    $
    (0.32
    )
    
    $
    (0.06
    )
 Employee Stock Purchase Plan On January 12, 2005, the stockholders of the Company approved the 2005 Employee Stock Purchase
Plan (the ESPP). The ESPP will allow eligible employees, officers, directors and consultants of
the Company and its designated affiliates to purchase, through payroll deductions, shares of the
Companys common stock. As of January 31, 2005, the ESPP had not been implemented. 5




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COMMERCE ENERGY GROUP, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(continued)
(in thousands, except per share and per kWh amounts) Segment Reporting The Companys chief operating decision makers consist of members of senior management that
work together to allocate resources to, and assess the performance of, the Companys business.
These members of senior management currently manage the Companys business, assess its performance,
and allocate its resources as a single operating segment. Because the revenue of the Companys
subsidiary, Skipping Stone, which we acquired in fiscal 2004, accounts for approximately 1% of
total net revenue (after elimination of intercompany transactions), and geographic information is
not relevant, no segment information is provided. Recent Accounting Standards In December 2004, the Financial Accounting Standards Board issued SFAS No. 123 (Revised 2004),
Share-Based Payment, (SFAS No. 123R), which is a revision to SFAS No. 123 and supersedes APB No.
25 and SFAS No. 148, Accounting for Stock-Based Compensation  Transition and Disclosure. This
statement requires that the cost resulting from all share-based payment transactions be recognized
in the financial statements. This statement establishes fair value as the measurement objective in
accounting for share-based payment arrangements and requires all entities to apply a fair-value
based measurement method in accounting for share-based payment transactions with employees except
for equity instruments held by employee share ownership plans. SFAS No. 123R applies to all awards
granted after the required effective date (the beginning of the first interim or annual reporting
period that begins after June 15, 2005) and to awards modified, repurchased, or cancelled after
that date. As of the required effective date, all public entities that used the fair-value based
method for either recognition or disclosure under SFAS No. 123 will apply this statement using a
modified version of prospective application. Under that transition method, compensation costs is
recognized on or after the required effective date for the portion of outstanding awards for which
the requisite service has not yet been rendered, based on the grant-date fair value of those awards
calculated under SFAS No. 123 for either recognition or pro forma disclosures. For periods before
the required effective date, those entities may elect to apply a modified version of the
retrospective application under which financial statements for prior periods are adjusted on a
basis consistent with the pro forma disclosures required for those periods by SFAS No. 123. As a
result, beginning in the first quarter of fiscal 2006, the Company will adopt SFAS No. 123R and
begin reflecting the stock option expense determined under fair-value based methods in its
statement of operations rather than as pro forma disclosure in the notes to the financial
statements. The Company has not yet determined whether the adoption of SFAS No. 123R will result in
amounts that are similar to the current pro forma disclosures under SFAS No. 123 and it is
evaluating the requirements under SFAS No. 123R. 2. Basic and Diluted Income (Loss) per Common Share Basic income (loss) per common share was computed by dividing net income (loss) available to
common stockholders, after any preferred stock dividends, by the weighted average number of common
shares outstanding during the period. Diluted income (loss) per common share reflects the potential
dilution that would occur if all outstanding options or other contracts to issue common stock were
exercised or converted and was computed by dividing net income (loss) by the weighted average
number of common shares plus dilutive common equivalent shares outstanding, unless they were
anti-dilutive. The following is a reconciliation of the numerator (income or loss) and the denominator
(common shares in thousands) used in the computation of basic and diluted income (loss) per common
share: Three months ended January 31,
    
    
    Six months ended January 31,2004
    
    
    2005
    
    
    2004
    
    
    2005(Restated)
    
    
    
    
    
    (Restated)Numerator:Netloss
    
    $
    (7,653
    )
    
    $
    (729
    )
    
    $
    (8,775
    )
    
    $
    (1,848
    )Deduct: Preferred stock dividends
    
    
    (26
    )
    
    
    
    
    
    
    (52
    )
    
    
    Net loss applicable to common
stock  basic and diluted
    
    $
    (7,679
    )
    
    $
    (729
    )
    
    $
    (8,827
    )
    
    $
    (1,848
    )
 6




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COMMERCE ENERGY GROUP, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(continued)
(in thousands, except per share and per kWh amounts) Three months ended January 31,
    
    
    Six months ended January 31,2004
    
    
    2005
    
    
    2004
    
    
    2005(Restated)
    
    
    
    
    
    (Restated)Denominator:Weighted-average
outstanding common
shares  basic
    
    
    27,645
    
    
    
    30,534
    
    
    
    27,645
    
    
    
    30,528Effect of stock options
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Weighted-average
outstanding common
shares  diluted
    
    
    27,645
    
    
    
    30,534
    
    
    
    27,645
    
    
    
    30,528
 For the three and six months ended January 31, 2004, the effects of the assumed exercise of
all stock options and the assumed conversion of preferred stock into common stock are
anti-dilutive; accordingly, such assumed exercises and conversions have been excluded from the
calculation of net loss  diluted. If the assumed exercises or conversions had been used, the
fully diluted shares outstanding for the three and six months ended January 31, 2005 would have
been 30,881 and 30,888, respectively. If the assumed exercises or conversions had been used, the
fully diluted shares outstanding for the three and six months ended January 31, 2004 would have
been 29,087 and 29,118, respectively. 3. Market and Regulatory California The 1996 California Assembly Bill (AB) 1890 codified the restructuring of the California
electric industry and provided for the right of direct access (DA). DA allowed electricity
customers to buy their power from a supplier other than the electric distribution utilities
beginning January 1, 1998. On April 1, 1998, the Company began supplying customers in California
with electricity as an Electric Service Provider (ESP). The California Public Utility Commission (CPUC) issued a ruling on September 20, 2001
suspending direct access. The suspension permitted the Company to keep current customers and to
solicit DA customers served by other providers, but prohibited the Company from soliciting new
non-DA customers for an indefinite period of time. In July 2002, the CPUC authorized Southern California Edison (SCE) to implement a Historical
Procurement Charge (HPC), to repay debt incurred during the energy crisis. This amount is
currently being collected by SCE as a $0.01 per kilowatt-hour (kWh) surcharge on the retail
electricity bill paid by the Companys customers. SCE estimates that full payment could be achieved
as soon as early 2006. While the HPC does not directly impact the Companys rate design or revenue,
it may affect the Companys ability to retain existing customers or compete for new customers. Effective January 1, 2003, the CPUC authorized the electric distribution utilities to charge
certain DA customers a surcharge to cover state power contract costs. The Direct Access Cost
Responsibility Surcharge (the DA CRS) is currently fixed at $0.027 per kWh. The DA CRS is only
assessed to those DA customers who enrolled in DA on or after February 1, 2001. In the SCE service
territory, the $0.027 DA CRS includes the $0.01 HPC. Those customers who were enrolled in DA prior
to February 1, 2001, and are in the SCE service territory continue to pay only the $0.01 HPC. While
this charge does not directly impact the Companys rate design or revenue, it may affect the
Companys ability to retain existing customers or compete for new customers. In December 2003, Pacific Gas and Electric (PG&E) and the CPUC reached a settlement in the
PG&E bankruptcy. In February 2004, the CPUC approved a rate settlement agreement, which reduced
overall customer rates in the PG&E service territory. DA bills have generally declined in the PG&E
service territory and the lower rates have affected the Companys revenue and profitability. Currently, four important issues are under review at the CPUC, a Resource Adequacy
Requirement, a Renewable Portfolio Standard, Utilities Long Term Procurement Plans and the General
Rate Cases of the electric distribution utilities. Additional costs to serve customers in
California are anticipated from these proceedings; however, the 7




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COMMERCE ENERGY GROUP, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(continued)
(in thousands, except per share and per kWh amounts) CPUC decisions will determine the distribution of those costs across all load serving entities
and ultimately the financial impact on the Company. Pennsylvania In 1996, the Electricity Generation Customer Choice and Competition Act was passed. This law
allowed electric customers to choose among competitive power suppliers beginning with one third of
the States consumers by January 1999, two thirds by January 2000, and all consumers by January
2001. The Company began serving customers in the Pennsylvania territory in 1999. There are no
current rate cases or filings regarding this territory that are anticipated to impact the Companys
financial results. Michigan The Michigan state legislature passed two acts, the Customer Choice Act and Electricity
Reliability Act, signed into law on June 3, 2000. Open access, or Choice, became available to all
customers of Michigan electric distribution utilities, beginning January 1, 2002. The Company began
marketing in Michigans Detroit Edison (DTE) service territory in September 2002. In February 2004, the Michigan Public Service Commission (MPSC) issued an interim order
granting partial but immediate rate relief to DTE, the Companys primary electric distribution
utility market in Michigan. The order significantly reduced the savings of commercial customers who
choose an alternative electric supplier, such as the Company. These changes have adversely affected
the Companys ability to retain some of the Companys existing customers and obtain new customers,
primarily among larger commercial customers. In November 2004, the MPSC issued the final order in the DTE General Rate case making slight
changes in the rates originally approved in the interim order issued in February 2004. The final
order reinstated a small percentage of savings of large commercial customers who choose an
alternative electric supplier, while generally maintaining the charges for smaller commercial
customers. More notable changes were made to rules regarding moving between the local utility and
alternative suppliers. New customers electing service from alternative providers must remain
outside utility service for a minimum of two years. Additionally, the local utility now requires
substantial notice prior to returning to their service. Overall rate and rule changes are not
expected to have a significant impact to the Companys ability to retain its existing customers and
obtain new customers. The Michigan Senate has energy restructuring language before it in various bills, supported by
the electric distribution utilities, which could negatively impact competition in the Michigan
electric market. New Jersey Deregulation activities began in New Jersey in November 1999 when the Board of Public
Utilities, or BPU, approved the implementation plan. The Company began marketing in New Jersey in
the Public Service Electric and Gas service territory in December 2003. The Basic Generation Service is the comparable utility price for small and large commercial
accounts and includes a reconciliation charge which can change on a monthly basis. Reconciliation
charge fluctuations can affect the Companys ability to remain competitive against the comparable
utility pricing. 4. Investments The Company has three investments in early-stage, energy related entities incurring operating
losses, which are expected to continue, at least in the near term: Encorp, Inc. (Encorp),
Turbocor B.V. (Turbocor) and Power Efficiency Corporation (PEC). Each company has very limited
working capital and as a result, continuing operations will be dependent upon their securing
additional financing to meet their respective immediate capital needs. The Company has no
obligation, and currently no intention to invest additional funds into these companies. 8




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COMMERCE ENERGY GROUP, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(continued)
(in thousands, except per share and per kWh amounts) At January 31, 2005, the Companys ownership interest in Encorp, Turbocor and PEC was 1.9%,
6.5% and 36.4%, respectively. The Company accounts for its investment in Encorp and Turbocor under
the cost method of accounting. The Company currently accounts for its investment in PEC (ticker
symbol: PEFF) under the equity method of accounting. At January 31, 2004, PEC was consolidated in
the Companys financial statements. In fiscal 2004, these investments were written down to $96. In
fiscal 2005, these investments are carried at $91 and have no material impact on our financial
statements. 5. Commitments and Contingencies Commitments Purchase Commitments On January 28, 2005, the Company made a strategic decision to discontinue service to certain
customers in the Pennsylvania service territory, specifically certain residential and small
commercial customers. In connection with that decision, the Company sold back future electricity
supply commitments related to serving those customers to its energy supplier. The supply
commitments would have provided the Company with electricity to serve the discontinued customers
electricity requirements through May 2006. The transaction occurred in January 2005 and resulted in
a gain on the sale of the supply commitments of $9,301, which has been reflected in the Companys
financial statements for its second fiscal quarter ending January 31, 2005. This gain was
partially offset by $1,500 of additional costs, to cover the timing and forecasting issues related
to realigning the customer portfolio, incurred in the third fiscal quarter of 2005 and $600 of a
reserve for additional estimated energy costs in the fourth fiscal quarter of 2005. (See Note 8).
The Company will continue to serve remaining customers in the Pennsylvania territory from remaining
supply contracts with other wholesale suppliers. After giving effect to the supply commitment that
was sold in the Pennsylvania territory and any new supply commitments entered into in the second
fiscal quarter, the following is a summary of the Companys commitments to purchase electric power
as of January 31, 2005: Fiscal Years Ending2005
    
    
    2006
    
    
    TotalCalifornia
    
    $
    24,494
    
    
    $
    18,586
    
    
    $
    43,080Pennsylvania and New Jersey
    
    
    6,898
    
    
    
    5,079
    
    
    
    11,977Total
    
    $
    31,392
    
    
    $
    23,665
    
    
    $
    55,057
 Contingencies Employment Settlements As of January 31, 2005, the Company has recorded a $3,600 reserve for potential employment
related settlements. Litigation On November 25, 2003, several stockholders filed a lawsuit against the Company entitled
Coltrain, et al. v. Commonwealth Energy Corporation, et al. The complaint purported to be a class
action against the Company for violations of section 709 of the California Corporations Code. This
action was dismissed for lack of prosecution on January 21, 2005. On December 23, 2004, the Company entered into a full and comprehensive Settlement Agreement
and Mutual General Release (Settlement Agreement) with stockholder and former director of
Commonwealth Energy Corporation, Joseph P. Saline, and stockholder Joseph Ogundiji. The Settlement
Agreement effectively ended all legal actions between the parties that began in 2001. The
Settlement Agreement acknowledges and validates Mr. Salines shares of common stock in the Company
and provides for a $1,200 settlement payment to Mr. Saline. The Settlement Agreement also provides
Mr. Ogundiji with a payment of $222 in settlement of all of his claims and for 9




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COMMERCE ENERGY GROUP, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(continued)
(in thousands, except per share and per kWh amounts) canceling all of his shares of common stock. In addition, Mr. Saline and Mr. Ogundiji agreed
that for the next two years they would submit any future disputes to mediation before commencing
litigation or before they take any steps to contact the Companys stockholders for any reason. The
Company accrued $1,200 in October of 2004 for the settlement with Mr. Saline and the $222
settlement for Mr. Ogundiji was recorded as cancellation of stock with no income statement effect. On February 18, 2005, the court struck the defendants answers and dismissed their
counter-claim in Commonwealth Energy Corporation v. Wayne Mosley, et al. for failure to prosecute
and failure to comply with orders of the court. The Company currently is, and from time to time may become, involved in other litigation
concerning claims arising out of the Companys operations in the normal course of business. While
the Company cannot predict the ultimate outcome of its pending matters or how they will affect the
Companys results of operations or financial position, the Companys management currently does not
expect any of the legal proceedings to which the Company is currently a party, including the legal
proceedings described above, individually or in the aggregate, to have a material adverse effect on
its results of operations or financial position beyond the accruals provided as of January 31,
2005. 6. Derivative Financial Instruments The Companys activities expose it to a variety of market risks, including commodity prices
and interest rates. Management has established risk management policies and procedures designed to
reduce the potentially adverse effects that the price volatility of these markets may have on its
operating results. The Companys risk management activities, including the use of derivative
instruments, are subject to the management, direction and control of an internal risk oversight
committee. The Company maintains commodity price risk management strategies that use derivative
instruments within strict risk tolerances to minimize significant, unanticipated earnings
fluctuations caused by commodity price volatility. Derivative instruments measured at fair market
value are recorded on the balance sheet as an asset or liability. Changes in fair market value are
recognized currently in earnings unless specific hedge accounting criteria are met. Supplying electricity to retail customers requires the Company to match customers projected
demand with fixed price purchases. The Company primarily uses forward physical energy purchases and
to a lesser extent derivative instruments to minimize significant, unanticipated earnings
fluctuations caused by commodity price volatility. In certain markets where the Company operates,
entering into forward fixed price contracts may be expensive relative to derivative alternatives.
Derivative instruments, primarily swaps and futures, are used to hedge the future purchase price of
electricity for the applicable forecast usage protecting the Company from significant price
volatility. In the first and second fiscal quarters of 2005, certain forward fixed price purchases
and swap agreements were designated as cash flow hedges resulting in changes in the hedge value
being deferred in other comprehensive income (OCI). To the extent that the hedges are not
effective, the ineffective portion of the changes in fair market value was recorded in direct
energy costs. The Company also entered into transactions that did not qualify as accounting hedges
but were designed to take advantage of trends in wholesale power prices to reduce its direct energy
costs. In such cases, the changes in the fair value of these transactions are recorded in earnings
as a component of direct energy costs. The Company did not engage in trading activities in the
wholesale energy market other than to manage its direct energy cost. The amounts recorded in OCI at January 31, 2005 related to cash flow hedges are summarized in
the following table: July 31,
    
    
    October 31,
    
    
    January 31,2004
    
    
    2004
    
    
    2005Current assets
    
    $
    
    
    
    $
    1,450
    
    
    $
    Current liabilities
    
    
    
    
    
    
    
    
    
    
    (112
    )Deferred losses
    
    
    
    
    
    
    
    
    
    
    (430
    )Other comprehensive income (loss)
    
    $
    
    
    
    $
    1,450
    
    
    $
    (542
    )
 10




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COMMERCE ENERGY GROUP, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(continued)
(in thousands, except per share and per kWh amounts) 7. Subsequent Event On February 9, 2005, the Company and its wholly-owned subsidiary, Commonwealth Energy
Corporation, entered into an agreement with American Communications Network, Inc. (ACN), and
several of its subsidiaries, ACN Utility Services, Inc., ACN Energy, Inc. and ACN Power, Inc.
(collectively the Sellers) to purchase certain assets of the Sellers, retail electric power and
natural gas sales business, and assume specified liabilities. The Sellers sell retail electric
power in Texas and Pennsylvania and sell retail natural gas in California, Ohio, Georgia, New York,
Pennsylvania and Maryland. The assets acquired include equipment, gas inventory associated with
utility and pipeline storage and transportation agreements and electricity supply, scheduling and
capacity contracts, software and other infrastructure plus approximately 80 residential and small
commercial customers. The initial consideration paid by the Company was (a) $6,500 in cash, plus
(b) 930 shares of the Companys common stock, valued at $2,000, based upon the market price for the
Companys common stock as of February 8, 2005, the date immediately prior to the closing date. The
shares of the Companys common stock will initially be placed in escrow and released upon
satisfaction of certain performance targets related to customer growth. ACN was also paid at
closing an estimated prepayment amount of approximately $5,500 as payment for certain working
capital and prepayment items relating to the assets being acquired, and are subject to final
adjustment and settlement. The Company has sufficient cash to cover the needs of this acquisition. 8. Quarterly Financial Information (Unaudited) In January 2005, the Company announced a strategic realignment of its customer portfolio in
the Pennsylvania electricity market and the discontinuation of service to certain classes of
residential and small commercial customers. In connection with this decision, the Company sold
electricity commodity supply contracts, which were deemed excess based on the realignment plan,
back to the original supplier and recorded a gain on the sale of the contracts of $9,301 in the
second quarter of fiscal 2005. As a result of timing and forecasting issues related to realigning
the portfolio, the Company had unforeseen transitional supply obligations which could have been
served more cost effectively with the original supply contracts rather than with the market cost of
the replacement power which was subsequently purchased. As a result, the Company is restating the
second quarter gain from $9,301 to $7,201, to account for the higher replacement cost of power
incurred in the third quarter of fiscal 2005 and estimated in the fourth quarter of fiscal 2005
compared to the cost that would have been incurred under the original supply contracts, as
reflected below. Three Months Ended
    
    
    Six Months EndedJanuary 31, 2005
    
    
    January 31, 2005Reported
    
    
    Restated
    
    
    Reported
    
    
    RestatedNet revenue
    
    $
    61,048
    
    
    $
    61,048
    
    
    $
    119,545
    
    
    $
    119,545Direct energy costs
    
    
    48,926
    
    
    
    51,026
    
    
    
    101,333
    
    
    
    103,433Gross profit
    
    
    12,122
    
    
    
    10,022
    
    
    
    18,212
    
    
    
    16,112Earnings (loss) from operations
    
    $
    1,318
    
    
    $
    (782
    )
    
    $
    1,447
    
    
    $
    (653
    )Net income (loss)
    
    $
    1,371
    
    
    $
    (729
    )
    
    $
    252
    
    
    $
    (1,848
    )Earnings (loss) per share  basic
    
    $
    0.04
    
    
    $
    (0.02
    )
    
    $
    0.01
    
    
    $
    (0.06
    )Earnings (loss) per share  diluted
    
    $
    0.04
    
    
    $
    (0.02
    )
    
    $
    0.01
    
    
    $
    (0.06
    )
 11




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##### Table of Contents



Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations. Overview We are a diversified energy services company. We provide electric power to our residential,
commercial, industrial and institutional customers in the California, Pennsylvania, Michigan and
New Jersey electricity markets. We are licensed by the Federal Energy Regulatory Commission, or
FERC, as a power marketer. In addition to the state agencies in which we currently operate, we are
also licensed to supply retail electric power by applicable state agencies in New York, Maryland,
Texas, Ohio and Virginia. Unless otherwise noted, as used herein, the Company, we, us, and
our mean Commerce Energy Group, Inc. and its three wholly-owned subsidiaries: Commonwealth Energy
Corporation, doing business under the brand name electricAmerica, Skipping Stone Inc. or Skipping
Stone, and UtiliHost, Inc. As of January 31, 2005, we delivered electricity to approximately 94,000 customers in
California, Pennsylvania, Michigan and New Jersey. The growth of this business depends upon the
degree of deregulation in each state, the availability of energy at competitive prices, credit
terms, and our ability to acquire retail or commercial customers. Our core business is the retail sale of electricity to end-use customers. All of the power we
sell to our customers is purchased from third-party power generators under long-term contracts and
in the spot market. We do not own electricity generation facilities, with the exception of small
experimental renewal energy assets. The electric power we sell is generally metered and delivered
to our customers by local incumbent electric distribution utilities, or local utilities. The local
utilities also provide billing and collection services for most of our customers on our behalf. To
facilitate load shaping and balancing for our retail customer portfolio, we also buy and sell
surplus electric power from and to other market participants when necessary. We buy electricity in the wholesale market in blocks of time-related quantities usually at
fixed prices. We sell electricity in the real time market based on the demand from our customers at
contracted prices. We manage the inherent mismatch between our block purchases and our sales by
buying and selling in the spot market. In addition, the independent system operators (ISO), the
entities which manage each of the electric grids in which we operate, perform real time load
balancing. We are charged or credited for electricity purchased and sold for our account by the
ISO. There are inherent risks and uncertainties in our core business operations. These include:
regulatory uncertainty, timing differences between our purchases and sales of electricity,
forecasting error between our estimated customer usage and the customers actual usage, weather
related changes in quantities demanded by our customers, customer attrition, spread changes between
on-peak and off-peak power pricing and seasonal differences between summer and winter demand, and
spring and fall demand seasons, unexpected factors in the wholesale power markets such as regional
power plant outages, volatile fuel prices (used to generate the electricity that we buy),
transmission congestion or system failure, and credit related counter-party risk for us or within
the grid system generally. Accordingly, these uncertainties may produce results that may differ
from our internal forecasts. For a discussion of other risks related to the operation of our
business, see the discussion herein under the caption Factors That May Affect Future Results. Skipping Stone, which we acquired in April 2004, provides energy-related consulting and
technologies to utilities, electricity generators, natural gas pipelines, wholesale energy
merchants, energy technology providers and investment banks. Skipping Stones revenue (after
elimination of intercompany transactions) was approximately 1% of our consolidated net revenue for
the three and six months ended January 31, 2005. In fiscal 2004, we consolidated Summit Energy Ventures, or Summit, and its majority interest
in Power Efficiency Corporation, or PEC, into our financial results. In the third fiscal quarter of
2004, we terminated our relationship with Summit. We no longer consolidate Summit and PEC in our
current fiscal year financial results as we retained a 39.9% interest in PEC. At January 31, 2005,
our ownership interest was diluted to 36.4% as a result of an equity linked financing by PEC.
Although we currently account for our investment in PEC under the equity method of accounting, in
fiscal 2004, we recorded a loss sufficient to reduce our investment basis in PEC to zero and,
therefore, it will have no negative impact on our financial results in fiscal 2005 or in the
future. 12




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##### Table of Contents



The information in this Item 2, should be read in conjunction with the audited consolidated
financial statements and notes thereto and Managements Discussion and Analysis of Financial
Condition and Results of Operations contained in the Companys Annual Report on Form 10-K for the
year ended July 31, 2004, and the unaudited condensed consolidated financial statements and notes
thereto included in this Quarterly Report. Market and Regulatory California The 1996 California Assembly Bill, or AB, 1890 codified the restructuring of the California
electric industry and provided for the right of direct access, or DA. DA allowed electricity
customers to buy their power from a supplier other than the electric distribution utilities
beginning January 1, 1998. On April 1, 1998, we began supplying customers in California with
electricity as an Electric Service Provider, or ESP. The California Public Utility Commission, or CPUC, issued a ruling on September 20, 2001
suspending direct access. The suspension permitted us to keep current customers and to solicit DA
customers served by other providers, but prohibited us from soliciting new non-DA customers for an
indefinite period of time. In July 2002, the CPUC authorized Southern California Edison, or SCE, to implement a
Historical Procurement Charge, or HPC, to repay debt incurred during the energy crisis. This amount
is currently being collected by SCE as a $0.01 per kilowatt-hour, or kWh, surcharge on the retail
electricity bill paid by our customers. SCE estimates that full payment could be achieved as soon
as early 2006. While the HPC does not directly impact our rate design or revenue, it may affect our
ability to retain existing customers or compete for new customers. Effective January 1, 2003, the CPUC authorized the electric distribution utilities to charge
certain DA customers a surcharge to cover state power contract costs. The Direct Access Cost
Responsibility Surcharge, or the DA CRS, is currently fixed at $0.027 per kWh. The DA CRS is only
assessed to those DA customers who enrolled in DA on or after February 1, 2001. In the SCE service
territory, the $0.027 DA CRS includes the $0.01 HPC. Those customers who were enrolled in DA prior
to February 1, 2001, and are in the SCE service territory continue to pay only the $0.01 HPC. While
this charge does not directly impact our rate design or revenue, it may affect our ability to
retain existing customers or compete for new customers. In December 2003, Pacific Gas and Electric, or PG&E, and the CPUC reached a settlement in the
PG&E bankruptcy. In February 2004, the CPUC approved a rate settlement agreement, which reduced
overall customer rates in the PG&E service territory. DA bills have generally declined in the PG&E
service territory and the lower rates have affected our revenue and profitability. Currently, four important issues are under review at the CPUC, a Resource Adequacy
Requirement, a Renewable Portfolio Standard, Utilities Long Term Procurement Plans and the General
Rate Cases of the electric distribution utilities. Additional costs to serve customers in
California are anticipated from these proceedings; however, the CPUC decisions will determine the
distribution of those costs across all load serving entities and ultimately the financial impact on
us. Pennsylvania In 1996, the Electricity Generation Customer Choice and Competition Act was passed. This law
allowed electric customers to choose among competitive power suppliers beginning with one third of
the States consumers by January 1999, two thirds by January 2000, and all consumers by January
2001. We began serving customers in the Pennsylvania territory in 1999. There are no current rate
cases or filings regarding this territory that are anticipated to impact our financial results. Michigan The Michigan state legislature passed two acts, the Customer Choice Act and Electricity
Reliability Act, signed into law on June 3, 2000. Open access, or Choice, became available to all
customers of Michigan electric 13




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##### Table of Contents



distribution utilities, beginning January 1, 2002. We began marketing in Michigans Detroit
Edison, or DTE, service territory in September 2002. In February 2004, the Michigan Public Service Commission, or MPSC, issued an interim order
granting partial but immediate rate relief to DTE, our primary electric distribution utility market
in Michigan. The order significantly reduced the savings of commercial customers who choose an
alternative electric supplier, such as us. These changes have adversely affected our ability to
retain some of our existing customers and obtain new customers, primarily among larger commercial
customers. In November 2004, the MPSC issued the final order in the DTE General Rate case making slight
changes in the rates originally approved in the interim order issued in February 2004. The final
order reinstated a small percentage of savings of large commercial customers who choose an
alternative electric supplier, while generally maintaining the charges for smaller commercial
customers. More notable changes were made to rules regarding moving between the local utility and
alternative suppliers. New customers electing service from alternative providers must remain
outside utility service for a minimum of two years. Additionally, the local utility now requires
substantial notice prior to returning to their service. Overall rate and rule changes are not
expected to have a significant impact to our ability to retain our existing customers and obtain
new customers. The Michigan Senate has energy restructuring language before it in various bills, supported by
the electric distribution utilities, which could negatively impact competition in the Michigan
electric market. New Jersey Deregulation activities began in New Jersey in November 1999 when the Board of Public
Utilities approved the implementation plan. We began marketing in New Jersey in the Public Service
Electric and Gas service territory in December 2003. The Basic Generation Service is the comparable utility price for small and large commercial
accounts and includes a reconciliation charge which can change on a monthly basis. Reconciliation
charge fluctuations can affect our ability to remain competitive against the comparable utility
pricing. Critical Accounting Policies and Estimates The following discussion and analysis of our financial condition and operating results are
based on our consolidated financial statements. The preparation of this Form 10-Q requires us to
make estimates and assumptions that affect the reported amount of assets and liabilities,
disclosure of contingent assets and liabilities at the date of our financial statements, and the
reported amount of revenue and expenses during the reporting period. Actual results may differ from
those estimates and assumptions. In preparing our financial statements and accounting for the
underlying transactions and balances, we apply our accounting policies as disclosed in our notes to
the condensed consolidated financial statements. The accounting policies discussed below are those
that we consider to be critical to an understanding of our financial statements because their
application places the most significant demands on our ability to judge the effect of inherently
uncertain matters on our financial results. For all of these policies, we caution that future
events rarely develop exactly as forecast, and the best estimates routinely require adjustment.  
    Purchase and sale accounting In fiscal 2004 and 2005, we purchased substantially all
of our power under long-term forward physical delivery contracts for supply to our retail
electricity customers. We apply the normal purchase, normal sale accounting treatment to
our forward purchase supply contracts and our customer sales contracts. Accordingly, we
record revenue generated from our sales contracts as energy is delivered to our retail
customers, and direct energy costs are recorded when the energy under our long-term forward
physical delivery contracts is delivered. In the first and second quarters of fiscal 2005,
we also employed financial hedges using derivative instruments, to hedge our commodity
price risks. In the first fiscal quarter of 2005, certain forward fixed price purchases and
swap agreements were designated as cash flow hedges resulting in changes in the hedge value
being recorded as other comprehensive income, or OCI. 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 use derivative instruments as an efficient
way of 14




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##### Table of Contents



assisting in managing our price and volume risk in energy supply procurement for our retail
customers. Certain derivative instrument treatment may not qualify for hedge treatment and
require mark-to-market accounting in accordance with the Financial Accounting Standards
Board, or FASB, Statement of Financial Accounting Standard, or SFAS, No. 133, Accounting for
Derivative Instruments and Hedging Activities.  
    Independent system operator costs Included in direct energy costs, along with
electric power that we purchase, are scheduling coordination costs and other ISO fees and
charges. The actual ISO costs are not finalized until a settlement process by the ISO is
performed for each days activities for all grid participants. Prior to the completion of
settlement (which may take from one to several months), we estimate these costs based on
historical trends and preliminary settlement information. The historical trends and
preliminary information may differ from actual fees resulting in the need to adjust the
previously estimated costs.
    Allowance for doubtful accounts We maintain allowances for doubtful accounts for
estimated losses resulting from non-payment of customer billings. If the financial
condition of our customers were to deteriorate, resulting in an impairment of their ability
to make payments, additional allowances may be required.
    Unbilled receivables Our customers are billed monthly at various dates throughout the
month. Unbilled receivables represent the amount of electric power delivered to customers
at the end of a reporting period, but not yet billed. Unbilled receivables from sales are
estimated by us to be the number of kilowatt-hours delivered, but not yet billed,
multiplied by the current customer average sales price per kilowatt-hour.
    Legal matters From time to time, we may be involved in litigation matters. We
regularly evaluate our exposure to threatened or pending litigation and other business
contingencies and accrue for estimated losses on such matters in accordance with SFAS No.
5, Accounting for Contingencies. As additional information about current or future
litigation or other contingencies becomes available, management will assess whether such
information warrants the recording of additional expense relating to our contingencies.
Such additional expense could potentially have a material adverse impact on our results of
operations and financial position. Results of Operations In the following comparative analysis, all percentages are calculated based on dollars in
thousands. The states of Pennsylvania and New Jersey are within the same ISO territory and
procurement of power is not managed separately, therefore, they are referred to as the Pennsylvania
market below. Three months ended January 31, 2005 compared to three months ended January 31, 2004. Net revenue of $61.0 million increased by $14.0 million, or 30%, for the three months ended
January 31, 2005 compared to the three months ended
January 31, 2004. Gross profit increased $6.7
million to $10.0 million for the three months ended January 31, 2005 compared to $3.3 million for
the same prior year period. The revenue and gross profit improvement in the three months ended
January 31, 2005 was primarily due to the sale of a portion of our Pennsylvania energy supply for
$9.3 million and an increase in excess energy sales of $5.9 million. On January 28, 2005, we made a
strategic decision to discontinue service to certain residential and small commercial customers in
the Pennsylvania territory, and sold back electricity supply commitments to our energy supplier for
$9.3 million. This gain was partially offset by $1.5 million and $0.6 million of additional cost,
to cover the timing and forecasting issues related to realigning the customer portfolio, incurred
in the third fiscal quarter of 2005 and estimated to be incurred in the fourth fiscal quarter of
2005, respectively. The Companys operating results for the three months ended January 31, 2005 included a loss
from operations of $0.8 million compared to a loss of $4.6 million for the same prior year period. Net revenue Retail energy sales Retail energy sales decreased $1.2 million, or 3%, to $44.8 million in the three months ended
January 31, 2005 compared to $46.0 million in the same period in the prior fiscal year. The
decrease resulted primarily from 15




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decreased energy sales of $3.9 million in California and $1.1 million in Pennsylvania offset
by an increase in Michigan of $3.3 million compared to the prior year period. In California, we
sold 201 million kWh at an average retail price per kWh of $0.071 in the three months ended January
31, 2005, as compared to 267 million kWh sold at an average retail price per kWh of $0.068 in the
same period last year. The decrease in volume was primarily attributable to customer attrition due
in part to our efforts to improve profitability per customer. In Pennsylvania, we sold 328 million
kWh at an average retail price per kWh of $0.057 in the three months ended January 31, 2005, as
compared to 305 million kWh sold at an average retail price per kWh of $0.065 in the same period
last year. The volume increase was primarily due to our increased customer base in the current year
in New Jersey which was offset by an average price decrease in this territory due to unstable
prices as we entered this new market at the end of fiscal 2004. In Michigan, we sold 190 million
kWh at an average retail price per kWh of $0.060 in the three months ended January 31, 2005, as
compared to 151 million kWh at an average retail price per kWh of $0.054 in the same period last
year. The increase in volume was primarily due to continued increases in our Michigan customer
base. Excess energy sales Excess energy sales increased $15.2 million to $16.2 million in the three months ended January
31, 2005 compared to $1.0 million in the same period in the prior year. The increase is
attributable to the $9.3 million sale of future electricity supply in Pennsylvania and the sale of
excess energy for California operations of $2.3 million and for Pennsylvania operations of $3.6
million compared to the prior fiscal second quarter. Excess energy sales represents the proceeds from surplus electric power we sell back into the
wholesale market when the electricity we have acquired exceeds our retail customers requirements.
The sale of excess energy supply is a natural by-product of balancing the power load used by our
customers against the power that we have previously purchased under contract in anticipation of our
forecast customer demand. Due to the inherent mismatch between our block purchases and our retail
demand and the volatility of customer load from day-to-day and within a given day, and the
volatility of prices on the spot market, significant fluctuations in excess energy sales can occur
from the optimization of the Companys supply portfolio and customer demand. At January 31, 2005, we had approximately 94,000 customers compared to 107,000 customers at
January 31, 2004. We experienced higher attrition as rates increased in California by 17% and in
Pennsylvania by 14%. We increased our customer base in Michigan by 29% and began to market in New
Jersey in December 2003. Direct energy costs Direct energy costs, which are recognized concurrently with related energy sales, include the
aggregated cost of purchased electric power, fees incurred from various energy-related service
providers and energy-related taxes that cannot be passed directly through to the customer. Our
direct energy costs increased to $51.0 million for the three months ended January 31, 2005, an
increase of $7.2 million, or 16 %, from $43.8 million for the three months ended January 31, 2004. The increase in direct energy costs occurred primarily in Michigan and California, with a
partial offset in Pennsylvania. In Michigan, our average cost per kWh was $0.052 for the three
months ended January 31, 2005, as compared to an average cost per kWh of $0.047 for the same period
last year. In California, our average cost per kWh was $0.061 for the three months ended January
31, 2005, as compared to an average cost per kWh of $0.056 for the same period in fiscal 2004. In
Pennsylvania, our average cost per kWh was $0.056 for the three months ended January 31, 2005, as
compared to an average cost per kWh of $0.063 for the same period in fiscal 2004. In addition,
increased cost in the current period reflect $2.1 million of additional costs incurred in the third
fiscal quarter 2005 and estimated to be incurred in the fourth fiscal quarter 2005, which was
restated in the second fiscal quarter 2005 to offset the $9.3 million gain recognized in this same
period. Selling and marketing expenses Our selling and marketing expenses decreased $0.2 million, or 25%, to $0.8 million for the
three months ended January 31, 2005, as compared to $1.0 million for the three months ended January
31, 2004. The decrease was primarily due to lower advertising costs in the current fiscal quarter. 16




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General and administrative expenses Our general and administrative expenses increased $4.2 million, or 72%, to $10.0 million for
the three months ended January 31, 2005 compared to $5.8 million in the three months ended January
31, 2004. The increase in the current fiscal year was primarily attributed to a $3.6 million
reserve for potential employment related settlements and severance of $0.5 million. Reorganization and initial public listing expenses We incurred $1.0 million in the second quarter of fiscal 2004 of costs related to our
reorganization into a Delaware holding company structure and the initial public listing of our
common stock on the American Stock Exchange. Management believed it was appropriate to classify
these costs as a separately identified selling, general and administrative expense category, and
included expenses such as legal, accounting, auditing, consulting, and printing and reproduction
fees that were specific to these activities. We incurred no such expenses in fiscal 2005. Initial formation litigation expenses In the three months ended January 31, 2005, we incurred $0.2 million of initial formation
litigation costs related to Commonwealth Energy Corporations formation compared to no such costs
during the three months ended January 31, 2004. Initial formation litigation expenses include legal
and litigation costs associated with the initial capital raising efforts by former Commonwealth
Energy Corporation employees, various board member matters, and the legal complications arising
from those activities. Provision for impairment on investments In the three months ended January 31, 2004, we recorded an impairment of $4.3 million on our
investments, to reflect our percentage ownership in the net equity of each of Summits two
investments: Turbocor and Encorp, Inc. (formerly Envenergy, Inc.). Minority interest share of loss Minority interests in fiscal 2004 represent that portion of PECs post-consolidation losses
that are allocated to the non-Summit investors based on their aggregate minority ownership interest
in PEC. PEC is no longer consolidated in our financial statements in fiscal 2005. Benefit from income taxes No provision for, or benefit from, income taxes was recorded for the three months ended
January 31, 2005; as compared to the benefit from income taxes of $0.8 million for the three months
ended January 31, 2004. In fiscal 2005, we established a valuation allowance equal to our
calculated tax benefit because we believed it was not certain that we would realize these tax
benefits in the foreseeable future. The current period results are not sufficient to modify this
conclusion. Six months ended January 31, 2005 compared to six months ended January 31, 2004. Net revenue increased $14.1 million, or 13%, to $119.5 million for the six months ended
January 31, 2005 as compared to $105.4 million in the six months ended January 31, 2004. Gross
profit increased $8.5 million to $16.1 million for the six months ended January 31, 2005 as
compared to $7.6 million for the same prior year period. The revenue and gross profit improvement
in the six months ended January 31, 2005 was primarily due to the sale of a portion of the future
Pennsylvania energy supply for $9.3 million, partially offset by $2.1 million additional cost
incurred to cover the timing and forecasting issues related to realigning the customer portfolio,
an increase in excess energy sales of $9.5 million and increased gross profit in Michigan and New
Jersey due to increased customer base offset by the continuing pressure on gross profit in the
California business. The Companys operating results for the six months ended January 31, 2005
included a loss from operations of $0.7 million compared to a loss of $6.9 million for the same
prior year period. 17




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Net revenue Retail energy sales Retail energy sales decreased $4.7 million, or 5%, to $97.5 million in the current fiscal year
compared to $102.2 million for the six months ended January 31, 2004. The decrease resulted
primarily from decreased energy sales of $8.3 million in California and $3.1 million in
Pennsylvania offset by an increase in Michigan of $5.6 million compared to the prior year period.
In California, we sold 462 million kWh at an average retail price per kWh of $0.072 in the six
months ended January 31, 2005, as compared to 595 million kWh sold at an average retail price per
kWh of $0.070 in the same period last year. The decrease in volume was primarily attributable to
customer attrition due in part to our efforts to improve profitability per customer. In
Pennsylvania, we sold 675 million kWh at an average retail price per kWh of $0.059 in the six
months ended January 31, 2005, as compared to 699 million kWh sold at an average retail price per
kWh of $0.061 in the same period last year. The decrease in volume was primarily due to decreases
attributable to customer attrition due in part to our efforts to improve profitability per customer
offset by increases in our New Jersey customer base in the current fiscal year, while the price
continues to fluctuate in this new market. In Michigan, we sold 399 million kWh at an average
retail price per kWh of $0.059 in the six months ended January 31, 2005, as compared to 330 million
kWh at an average retail price per kWh of $0.054 in the same period last year. The increase in
volume was primarily due to continued increases in our Michigan customer base. Excess energy sales Excess energy sales increased $18.7 million to $22.0 million in the six months ended January
31, 2005, as compared to $3.3 in the same period in the prior year. The increase is attributable to
the $9.3 million sale of future electricity supply in Pennsylvania and the sale of excess energy
for California operations of $4.3 million and for Pennsylvania operations of $5.2 million as
compared to the six months ended January 31, 2004. Direct energy costs Our direct energy costs increased to $103.4 million for the six months ended January 31, 2005,
an increase of $5.5 million, or 6 %, from $97.9 million for the six months ended January 31, 2004.
The increase in direct energy costs occurred primarily in Michigan and California partially offset
by decreases in Pennsylvania related to the new New Jersey market. In Michigan, our average cost
per kWh was $0.051 for the six months ended January 31, 2005, as compared to an average cost per
kWh of $0.047 for the same period last year. In California, our average cost per kWh was $0.060 for
the six months ended January 31, 2005, as compared to an average cost per kWh of $0.055 for the
same period in fiscal 2004. In Pennsylvania, our average cost per kWh was $0.056 for the six months
ended January 31, 2005, as compared to an average cost per kWh of $0.063 for the same period in
fiscal 2004. Selling and marketing expenses Our selling and marketing expenses decreased $0.3 million, or 13%, to $1.7 million for the six
months ended January 31, 2005, as compared to $2.0 million for the six months ended January 31,
2004. The decrease is primarily due to decreased advertising costs in the current fiscal period. General and administrative expenses Our general and administrative expenses increased $3.8 million, or 33%, to $15.1 million for
the six months ended January 31, 2005 compared to $11.3 million in the six months ended January 31,
2004. The increase was primarily attributed to a $3.6 million reserve for potential employment
related settlements. Reorganization and initial public listing expenses We incurred $1.1 million in the six months ended January 31, 2004 of costs related to our
reorganization into a Delaware holding company structure and the initial public listing of our
common stock on the American Stock Exchange. Management believed it was appropriate to classify
these costs as a separately identified selling, general 18




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and administrative expense category, and included expenses such as legal, accounting,
auditing, consulting, and printing and reproduction fees that were specific to these activities. We
incurred no such expenses in fiscal 2005. Initial formation litigation expenses In the six months ended January 31, 2005, we incurred $1.6 million of initial formation
litigation costs related to Commonwealth Energy Corporations formation compared to $0.6 million
incurred during the six months ended January 31, 2004. Initial formation litigation expenses
include legal and litigation costs associated with the initial capital raising efforts by former
Commonwealth Energy Corporation employees, various board member matters, and the legal
complications arising from those activities. Minority interest share of loss Minority interests in fiscal 2004 represent that portion of PECs post-consolidation losses
that are allocated to the non-Summit investors based on their aggregate minority ownership interest
in PEC. PEC is no longer consolidated in our financial statements in fiscal 2005. Benefit from income taxes No provision for, or benefit from, income taxes was recorded for the six months ended January
31, 2005; as compared to the benefit from income taxes of $1.8 million for the six months ended
January 31, 2004. In fiscal 2005, we established a valuation allowance equal to our calculated tax
benefit because we believed it was not certain that we would realize these tax benefits in the
foreseeable future. The current period results are not sufficient to modify this conclusion. Liquidity and Capital Resources As of January 31, 2005, our unrestricted cash and cash equivalents were $50.0 million,
compared to $54.1 million at July 31, 2004 and our restricted cash and cash equivalents were $4.3
million, compared to $4.0 million at July 31, 2004. In addition to restricted cash, we also had
cash deposits of $6.7 million at January 31, 2005, compared to $5.4 million at July 31, 2004. Our
principal sources of liquidity to fund ongoing operations were cash provided by operations and
existing cash and cash equivalents. Cash flow used in operations for the six months ended January 31, 2005 was $3.2 million,
compared to cash flow provided by operations of $5.4 million in the six months ended January 31,
2004. In the six months ended January 31, 2005, cash was used primarily by an increase in accounts
receivable of $2.4 million and a decrease in accounts payable of $7.3 million offset by a decrease
in prepaid expenses of $2.0 million primarily due to a prepayment contract ending in December 2004. Cash flow used in investing activities for the six months ended January 31, 2005 was $0.3
million compared to $0.6 million for the six months ended January 31, 2004. Cash used in
investments consisted of capital expenditures. Cash flow used in financing activities for the six months ended January 31, 2005 was $0.5
million, compared to cash flow provided by financing activities of $8.6 million in the six months
ended January 31, 2004. In the current fiscal year, cash flow used was primarily for the
cancellation of common stock and increased restricted cash primarily for increased required letters
of credit in New Jersey. In the prior fiscal year, restricted cash decreased primarily due to the
cancellation of the required security for an appeals bond of $4.1 million related to a settled
litigation and the $3.5 million reduction of the required letters of credit secured by cash related
to energy suppliers. The Company does not have open lines of credit for direct unsecured borrowings or letters of
credit. Credit terms from our suppliers of electricity often require us to post collateral against
our energy purchases and against our mark-to-market exposure with certain of our suppliers. We
currently finance these collateral obligations with our available cash. If we are required to post
such additional security, a portion of our cash would become restricted, which could adversely
affect our liquidity. As of January 31, 2005, we had $4.3 million in restricted cash to secure
letters of credit required by our suppliers and $6.5 million in deposits pledged as collateral in
connection with energy purchase agreements. 19




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Based upon our current plans, level of operations and business conditions, we believe that our
cash and cash equivalents, and cash generated from operations will be sufficient to meet our
capital requirements and working capital needs for the foreseeable future. However, there can be no
assurance that we will not be required to seek other financing in the future or that such
financing, if required, will be available on terms satisfactory to us. Contractual Obligations There have been no material changes to contractual obligations from the disclosures set forth
in Part II, Item 7 in our Annual Report on Form 10-K for the year ended July 31, 2004, except as
set forth below. In January 2005, we sold back our electricity supply commitments related to serving certain
residential and small commercial customers, in the Pennsylvania territory, to our energy supplier.
The supply commitments would have provided us with electricity to serve the discontinued customers
electricity requirements through May 2006. The transaction occurred in January 2005 and resulted in
a gain on the sale of the supply commitments of $9.3 million, which has been reflected in our
financial statements for our second fiscal quarter ending January 31, 2005. This gain was
partially offset by $2.1 million of additional cost, to cover the timing and forecasting issues
related to realigning the customer portfolio, incurred in the third fiscal quarter of 2005 and
estimated to be incurred in the fourth fiscal quarter of 2005. We will continue to serve remaining
customers in the Pennsylvania territory from remaining supply contracts with other wholesale
suppliers. After giving effect to the supply commitment that was sold in the Pennsylvania territory
and any new supply commitments entered into in the second fiscal quarter, our contractual
commitments for electricity purchase contracts as of January 31, 2005 are $55.1 million, of which
$54.8 million is for less than one year and $0.3 million is for more than one year through March
2006. Subsequent Event On February 9, 2005, we entered into an agreement with American Communications Network, Inc.
(ACN), and several of its subsidiaries, ACN Utility Services, Inc. (ACN Utility), ACN Energy,
Inc. (ACN Energy) and ACN Power, Inc. (ACN Power, and collectively with ACN Utility and ACN
Energy, the Sellers) to purchase certain assets of the Sellers retail electric power and natural
gas sales business, and assume specified liabilities. The Sellers sell retail electric power in
Texas and Pennsylvania and sell retail natural gas in California, Ohio, Georgia, New York,
Pennsylvania and Maryland. The assets acquired include equipment, gas inventory associated with
utility and pipeline storage and transportation agreements and electricity supply, scheduling and
capacity contracts, software and other infrastructure plus approximately 80,000 residential and
small commercial customers. The initial consideration paid by us was (a) $6.5 million in cash, plus
(b) 930,233 shares of our common stock, valued at $2.0 million, based upon the market price for our
common stock as of February 8, 2005, the date immediately prior to the closing date. The shares of
common stock will initially be placed in escrow and released upon satisfaction of certain
performance targets related to customer growth. ACN was also paid at closing an estimated
prepayment amount of approximately $5.5 million as payment for certain working capital and
prepayment items relating to the assets being acquired, and are subject to final adjustment and
settlement. We have sufficient cash to cover the needs of this acquisition. This transaction was
previously reported by us on a current report on Form 8-K filed with the Securities and Exchange
Commission on February 10, 2005. Factors That May Affect Future Results If competitive restructuring of the electric markets is delayed or does not result in viable
competitive market rules, our business will be adversely affected. The Federal Energy Regulatory Commission, or FERC, has maintained a strong commitment over the
past seven years to the deregulation of electricity markets. This movement would seem to indicate
the continuation and growth of a competitive electric retail industry. Twenty-four states and the
District of Columbia have either enacted enabling legislation or issued a regulatory order to
implement retail access. In 18 of these states, retail access is either currently available to some
or all customers, or will soon be available. However, in many of these markets the market rules
adopted have not resulted in energy service providers being able to compete successfully with the
local utilities and customer switching rates have been low. Our business model depends on other
favorable markets opening under viable competitive rules in a timely manner. In any particular
market, there are a number of rules that 20




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will ultimately determine the attractiveness of any market. Markets that we enter may have
both favorable and unfavorable rules. If the trend towards competitive restructuring of retail
energy markets does not continue or is delayed or reversed, our business prospects and financial
condition could be materially adversely impaired. Retail energy market restructuring has been and will continue to be a complicated regulatory
process, with competing interests advanced not only by relevant state and federal utility
regulators, but also by state legislators, federal legislators, local utilities, consumer advocacy
groups and other market participants. As a result, the extent to which there are legitimate
competitive opportunities for alternative energy suppliers in a given jurisdiction may vary widely
and we cannot be assured that regulatory structures will offer us competitive opportunities to sell
energy to consumers on a profitable basis. The regulatory process could be negatively impacted by a
number of factors, including interruptions of service and significant or rapid price increases. The
legislative and regulatory processes in some states take prolonged periods of time. In a number of
jurisdictions, it may be many years from the date legislation is enacted until the retail markets
are truly open for competition. In addition, although most retail energy market restructuring has been conducted at the state
and local levels, bills have been proposed in Congress in the past that would preempt state law
concerning the restructuring of the retail energy markets. Although none of these initiatives has
been successful, we cannot assure stockholders that federal legislation will not be passed in the
future that could materially adversely affect our business. We face many uncertainties that may cause substantial operating losses and we cannot assure
stockholders that we can achieve and maintain profitability. We intend to increase our operating expenses to develop and expand our business, including
brand development, marketing and other promotional activities and the continued development of our
billing, customer care and power procurement infrastructure. Our ability to operate profitably will
depend on, among other things:  
    Our ability to attract and to retain a critical mass of customers at a reasonable cost;
    Our ability to continue to develop and maintain internal corporate organization and systems;
    The continued competitive restructuring of retail energy markets with viable
competitive market rules; and
    Our ability to effectively manage our energy procurement and shaping requirements, and
to sell our energy at a sufficient profit margin. We may have difficulty obtaining a sufficient number of customers. We anticipate that we will incur significant costs as we enter new markets and pursue
customers by utilizing a variety of marketing methods. In order for us to recover these expenses,
we must attract and retain a large number of customers to our service. We may experience difficulty attracting customers because many customers may be reluctant to
switch to a new supplier for a commodity as critical to their well-being as electric power. A major
focus of our marketing efforts will be to convince customers that we are a reliable provider with
sufficient resources to meet our commitments. If our marketing strategy is not successful, our
business, results of operations and financial condition could be materially adversely affected. We depend upon internally developed systems and processes to provide several critical functions for
our business, and the loss of these functions could materially adversely impact our business. We have developed our own systems and processes to operate our back-office functions,
including customer enrollment, metering, forecasting, settlement and billing. Problems that arise
with the performance of our back-office functions could result in increased expenditures, delays in
the launch of our commercial operations into new markets, or unfavorable customer experiences that
could materially adversely affect our business strategy. Also, any interruption of these services
could be disruptive to our business. 21




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Substantial fluctuations in electricity prices or the cost of transmitting and distributing
electricity could have a material adverse affect on us. To provide electricity to our customers, we must, from time to time, purchase electricity in
the short-term or spot wholesale energy markets, which can be highly volatile. In particular, the
wholesale electric power market can experience large price fluctuations during peak load periods.
Furthermore, to the extent that we enter into contracts with customers that require us to provide
electricity at a fixed price over an extended period of time, and to the extent that we have not
purchased electricity to cover those commitments, we may incur losses caused by rising wholesale
electricity prices. Periods of rising electricity prices may reduce our ability to compete with
local utilities because their regulated rates may not immediately increase to reflect these
increased costs. Energy Service Providers like us take on the risk of purchasing power for an
uncertain load and if the load does not materialize as forecast, it leaves us in a long position
that would be resold into the wholesale electricity market. Sales of this surplus electricity could
be at prices below our cost. Conversely, if unanticipated load appears that may result in an
insufficient supply of electricity, we would need to purchase the additional supply. These
purchases could be at prices that are higher than our sales price to our customers. Either
situation could create losses for us if we are exposed to the price volatility of the wholesale
spot markets. Any of these contingencies could substantially increase our costs of operation. Such
factors could have a material adverse effect on our financial condition. We are dependent on local utilities for distribution of electricity to our customers over
their distribution networks. If these local utilities are unable to properly operate their
distribution networks, or if the operation of their distribution networks is interrupted for
periods of time, we could be unable to deliver electricity to our customers during those
interruptions. This would results in lost revenue to us, which could adversely impact the results
of our operations. Historical procurement charges and customer rate changes in the Southern California Edison utility
district could adversely affect our revenue and cash flows. Under a Settlement agreement with the California PUC, SCE was authorized to recoup $3.6
billion in debt incurred during the energy crisis of 2000-2001 from all customers. This debt was to
be collected under the Procurement Related Obligations Account, or PROACT, from bundled (non direct
access) customers and under the HPC from DA customers. In July 2002, the California PUC issued an interim order implementing the HPC sought by SCE.
This interim order authorized SCE to collect $391 million in HPC charges from all DA customers by
reducing their Procured Energy Credit, or PE Credit, by $0.027 per kWh beginning July 27, 2002. The
lowered PE Credit continued until an exit fee for DA customers was approved by the CPUC. Effective
January 1, 2003, it was reduced to $0.01 per kWh. For the fiscal year ended July 31, 2003, we
estimated that HPC charges had impacted our sales and pretax earnings by a range of $4.8 million to
$6.0 million. We were unable to precisely determine the actual HPC charges applied to our customers
by SCE because there were different charges, by customer type, and this charge was only on the
electricity usage above the monthly baseline usage allocation. On September 5, 2003 the CPUC issued Decision 03-09-016 granting SCEs request to recover
additional shortfall and authorizing the HPC balance to be revised to $473 million; however, the
$0.01 per kWh monthly charge remained in place. As of August 1, 2003, SCE revised its billing
methodology to a bottoms-up design effectively doing away with the PE Credit and the net effect
of the HPC on our rates. While the HPC no longer discretely impacts our rate calculations, a recent
SCE rate reduction indirectly includes the former impact of the HPC. This rate reduction impacted
sales and pretax profit in the SCE district. The rate reduction remained in place in 2004 and
approximated the effect of the HPC dollar impact of 2003. In 2003, SCE acknowledged that the PROACT debt was paid in full by bundled customers at the
end of July 2003. As a result, on August 1, 2003, all SCE rates were lowered. As a direct result,
to retain our customers in the SCE utility district, we lowered our customer rates proportionately.
Our estimate of the annual financial impact of this rate reduction is a decline in sales and pretax
profit during fiscal 2004, in the range of $3.0 to $3.5 million. This reduction is separate from,
and in addition to, the HPC related reduction in 2003. 22




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These changes in the SCE service territory will continue to cause a significant impact on our
revenue and cash flow; however, we currently do not expect they will preclude us from continuing to
participate in the SCE market. Some suppliers of electricity have been experiencing deteriorating credit quality. We continue to monitor our suppliers credit quality to attempt to reduce the impact of any
potential counterparty default. As of January 31, 2005, the majority of our counterparties are
rated investment grade or above by the major rating agencies. These ratings are subject to change
at any time with no advance warning. A deterioration in the credit quality of our suppliers could
have an adverse impact on our sources of electricity purchases. If the wholesale price of electricity decreases, we may be required to post letters of credit for
margin to secure our obligations under our long term energy contracts. As the price of the electricity we purchase under long-term contracts is fixed over the term
of the contracts, if the market price of wholesale electricity decreases below the contract price,
the power generator may require us to post margin in the form of a letter of credit, or other
collateral, to protect themselves against our potential default on the contract. If we are required
to post such security, a portion of our cash would become restricted, which could adversely affect
our liquidity. We are required to rely on utilities with whom we will be competing to perform some functions for
our customers. Under the regulatory structures adopted in most jurisdictions, we will be required to enter
into agreements with local utilities for use of the local distribution systems, and for the
creation and operation of functional interfaces necessary for us to serve our customers. Any delay
in these negotiations or our inability to enter into reasonable agreements with those utilities
could delay or negatively impact our ability to serve customers in those jurisdictions. This could
have a material negative impact on our business, results of operations and financial condition. We are dependent on local utilities for maintenance of the infrastructure through which
electricity is delivered to our customers. We are limited in our ability to control the level of
service the utilities provide to our customers. Any infrastructure failure that interrupts or
impairs delivery of electricity to our customers could have a negative effect on the satisfaction
of our customers with our service, which could have a material adverse effect on our business. Regulations in many markets require that the services of reading our customers energy meters
and the billing and collection process be retained by the local utility. In those states, we will
be required to rely on the local utility to provide us with our customers energy usage data and to
pay us for our customers usage based on what the local utility collects from our customers. We may
be limited in our ability to confirm the accuracy of the information provided by the local utility
and we may not be able to control when we receive payment from the local utility. The local
utilitys systems and procedures may limit or slow down our ability to create a supplier
relationship with our customers that would delay the timing of when we can begin to provide
electricity to our new customers. If we do not receive payments from the local utility on a timely
basis, our working capital may be impaired. In some markets, we are required to bear credit risk and billing responsibility for our customers. In some markets, we are responsible for the billing and collection functions for our
customers. In these markets, we may be limited in our ability to terminate service to customers who
are delinquent in payment. Even if we terminate service to customers who fail to pay their utility
bill in a timely manner, we may remain liable to our suppliers of electricity for the cost of the
electricity and to the local utilities for services related to the transmission and distribution of
electricity to those customers. The failure of our customers to pay their bills in a timely manner
or our failure to maintain adequate billing and collection programs could materially adversely
affect our business. Our revenues and results of operations are subject to market risks that are beyond our control. We sell electricity that we purchase from third-party power generation companies to our retail
customers on a contractual basis. We are not guaranteed any rate of return through regulated rates,
and our revenues and results of operations are likely to depend, in large part, upon prevailing
market prices for electricity in our regional markets. 23




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These market prices may fluctuate substantially over relatively short periods of time. These
factors could have an adverse impact on our revenues and results of operations. Volatility in market prices for electricity results from multiple factors, including:  
    weather conditions, including hydrological conditions such as precipitation, snow pack and stream flow,
    seasonality,
    unexpected changes in customer usage,
    transmission or transportation constraints or inefficiencies,
    planned and unplanned plant or transmission line outages,
    demand for electricity,
    natural gas, crude oil and refined products, and coal supply availability to generators
from whom we purchase electricity,
    natural disasters, wars, embargoes and other catastrophic events, and
    federal, state and foreign energy and environmental regulation and legislation. We may experience difficulty in integrating and managing acquired businesses successfully and in
realizing anticipated economic, operational and other benefits in a timely manner We recently completed the acquisition of certain assets of ACN Energy, Inc. The ultimate
success of this acquisition depends, in part, on our ability to realize the anticipated synergies,
cost savings and growth opportunities from integrating ACN Energys business into our existing
businesses. If we fail to maintain an effective system of internal controls, we may not be able to accurately
report our financial results or prevent fraud. As a result, current and potential stockholders
could lose confidence in our financial reporting, which would harm our business and the trading
price of our stock. Effective internal controls are necessary for us to provide reliable financial reports and
effectively prevent fraud. If we cannot provide reliable financial reports or prevent fraud, our
operating results could be harmed. We have in the past discovered, and may in the future discover,
areas of our internal controls that need improvement. For example, in January 2005, we sold
electricity commodity supply contracts related to a strategic realignment of our customer portfolio
in the Pennsylvania electricity market and the discontinuation of service to certain classes of
residential and small commercial customers. As a result of timing issues related to realigning the
portfolio and inaccurately forecasting the resulting required electricity supply, we had
transitional electricity supply obligations which could have been served more cost effectively with
the original supply contract rater than with replacement power which was subsequently purchased at
market prices. In the execution of this portfolio realignment, we observed deficiencies in our
internal controls relating to monitoring the operational progress of the realignment. Our
independent auditors advised us that in their opinion, with which we concur, these internal control
deficiencies constitute reportable conditions, and collectively, a material weakness that caused us
to restate our second quarter reported results, which means that this was an issue that in the
auditors judgment could adversely affect our ability to record, process, summarize and report
financial data consistent with the assertions of management in the financial statements. In both
fiscal 2004 and 2005, we 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 condition and material weakness in fiscal
2004 and 2005, we are continuing to work to improve our internal controls, including 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 24




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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, 2006, as required by Section 404 of the Sarbanes-Oxley Act of 2002. As directed by Section 404 of the Sarbanes-Oxley Act of 2002, the Securities and Exchange
Commission adopted rules requiring public companies to include a report of management on our
internal controls over financial reporting in our Annual Reports on Form 10-K that contains an
assessment by management of the effectiveness of our internal controls over financial reporting. In
addition, our independent auditors must attest to and report on managements assessment of the
effectiveness of our internal controls over financial reporting. This requirement will first apply
to our Annual Report on Form 10-K for the fiscal year ending July 31, 2006. 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, 2005. We anticipate that improvements will continue to be made. 
 Item 3. Quantitative and Qualitative Disclosures about Market Risk. There have been no material changes to information called for by this Item 3 from the
disclosures set forth in Part II, Item 7A in the Companys Annual Report on Form 10-K for the year
ended July 31, 2004, except as set forth below. Our activities expose us to a variety of market risks including commodity prices and interest
rates. Management has established risk management policies and strategies to reduce the potentially
adverse effects that the price volatility of these markets may have on our operating results. Our
risk management activities, including the use of derivative instruments, are subject to the
management, direction and control of an internal risk oversight committee. We maintain commodity
price risk management strategies that use derivative instruments within strict risk tolerances to
minimize significant, unanticipated earnings fluctuations caused by commodity price volatility.
Derivative instruments measured at fair market value are recorded on the balance sheet as an asset
or liability. Changes in fair market value are recognized currently in earnings unless specific
hedge accounting criteria are met. Supplying electricity to retail customers requires us to match customers projected demand
with fixed price purchases. We primarily use forward physical energy purchases and derivative
instruments to minimize significant, unanticipated earnings fluctuations caused by commodity price
volatility. In certain markets where we operate, entering into forward fixed price contracts may be
expensive relative to derivative alternatives. Derivative instruments, primarily swaps and futures,
are used to hedge the future purchase price of electricity for the applicable forecast usage
protecting us from significant price volatility. In the first and second fiscal quarters of 2005,
certain forward fixed price purchases and swap agreements were designated as cash flow hedges
resulting in changes in the hedge value being deferred in other comprehensive income (OCI). To
the extent that the hedges are not effective, the ineffective portion of the changes in fair market
value was recorded in direct energy costs. We also entered into transactions that did not qualify
as accounting hedges but were designed to take advantage of trends in wholesale power prices to
reduce our direct energy costs. Some of these transactions do not qualify for hedge accounting 25




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##### Table of Contents



treatment under SFAS 133. In such cases, the changes in the fair value of these transactions
are recorded in earnings as a component of direct energy costs. We did not engage in trading
activities in the wholesale energy market other than to manage our direct energy cost in an attempt
to improve the profit margin associated with our customer requirements. The amounts recorded in OCI at January 31, 2005 related to cash flow hedges are summarized in
the following table: July 31,
    
    
    October 31,
    
    
    January 31,2004
    
    
    2004
    
    
    2005Current assets
    
    $
    
    
    
    $
    1,450
    
    
    $
    Current liabilities
    
    
    
    
    
    
    
    
    
    
    (112
    )Deferred losses
    
    
    
    
    
    
    
    
    
    
    (430
    )Other comprehensive income (loss)
    
    $
    
    
    
    $
    1,450
    
    
    $
    (542
    )
 On January 28, 2005, we sold back future electricity supply commitments related to serving
certain customers in Pennsylvania to our energy supplier. As a result of the portfolio rebalancing
required due to this sale, the portfolio coverage ratio is more meaningful at February 28, 2005,
where we had 87% of our forecast energy load through December 31, 2005 covered through either fixed
price power purchases with counterparties, or price protected through financial hedges. 
 Item 4. Controls and Procedures.  a)
    Evaluation of Disclosure Controls and Procedures. The Company conducted an evaluation of the effectiveness of the design and operation of our
disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the
Securities Exchange Act of 1934, as amended (the Exchange Act)) as of the end of the period
covered by this Quarterly Report in connection with the filing of its initial Quarterly Report on
Form 10-Q based upon the information available at that time and concluded that the Companys
disclosure controls and procedures were effective. The controls evaluation was done under the
supervision and with the participation of management, including our Principal Executive Officer and
Chief Financial Officer. Subsequent to that evaluation, we advised the Audit Committee of our Board of Directors that,
in monitoring the strategic realignment of our Pennsylvania customer portfolio, we noted
deficiencies in internal controls relating to monitoring the operational progress of the
realignment and properly forecasting the resulting required electricity supply. Our independent auditors, Ernst & Young LLP, have advised the Audit Committee that these
internal control deficiencies constitute a reportable condition and a material weakness as defined
in Statement on Auditing Standards No. 60. This amended Quarterly Report on Form 10-Q/A
principally restates prior reported results and include additional disclosures in the appropriate
period as a result of finding the foregoing weakness in our internal controls. We continue to evaluate and implement methods to improve our internal controls and procedures
with the assistance of outside advisors. We have taken the following corrective actions, some of
which we began to implement as early as March 2005:  
    Determined that a major integrated system upgrade was required to replace the
current in-house forecasting, meter tracking and sales systems. We have evaluated
several such third party systems and have begun implementation on our selections;
    Established procedures to reconcile demand and load factors among the various
in-house systems until the integrated system can be fully implemented;
    Established procedures to reconcile meter counts on a weekly basis among the
various in-house systems until the integrated system can be fully implemented; and 26




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
    Established senior level management oversight of the load forecasting process,
including weekly update and reporting meetings. We will continue to design and implement additional procedures to ensure that these internal
control deficiencies will not result in material misstatements in our consolidated financial
statements contained in this amended Quarterly Report on Form 10-Q/A, and will not result in
material misstatements in our future financial results. In connection with this amended Quarterly Report on Form 10-Q/A, under the direction of our
Principal Executive Officer and Chief Financial Officer, we have re-evaluated our disclosure
controls and procedures as currently in effect, including the changes in internal controls over
financial reporting described above, and we have concluded that, as of the date of this amended
Quarterly Report on Form 10-Q/A, our disclosure controls and procedures are effective.  b)
    Changes in Internal Controls. As previously reported, there was no change in our internal control over financial reporting
(as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the second quarter of
fiscal 2005, that materially affected, or is reasonably likely to materially affect, our internal
control over financial reporting. However, subsequent to the end of the second quarter of fiscal
2005, we took the remedial actions described above. 27




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##### Table of Contents



PART II OTHER INFORMATION 
 Item 1. Legal Proceedings. Reference is made to the Companys Report on Form 10-K for the period ended July 31, 2004 (the
10-K), for a summary the Companys legal proceedings previously reported. Since the date of the
10-K, there have been no material developments in previously reported legal proceedings,except as
set forth below. On January 21, 2005, the court granted the Companys motion to dismiss in Coltrain, et al. v.
Commonwealth Energy Corporation, et al. (Case number CV03-8560-FMC (RNBx)) for lack of prosecution. On December 23, 2004, the Company entered into a full and comprehensive Settlement Agreement
and Mutual General Release (the Settlement Agreement) with stockholder and former director of
Commonwealth Energy Corporation, Joseph P. Saline, and stockholder Joseph Ogundiji. The Settlement
Agreement effectively ended all legal actions between the parties that began in 2001, including
Orange Court Superior Court case numbers 01CC10657, 01CC13887, 04CC09285, 03CC03409, 04CC05038. The
Settlement Agreement acknowledges and validates Mr. Salines shares of common stock in the Company
and provides for a $1.2 million settlement payment to Mr. Saline. The Settlement Agreement also
provides Mr. Ogundiji with a payment of $222,400 in settlement of all his claims and for canceling
all of his shares of common stock. In addition, Mr. Saline and Mr. Ogundiji agreed that for the
next two years they would submit any future disputes to mediation before commencing litigation or
before they take any steps to contact the Companys stockholders for any reason related to bringing
a proxy contest. On February 18, 2005, the court struck the defendants answers and dismissed their
counter-claim in Commonwealth Energy Corporation v. Wayne Mosley, et al. (Case number CV03-00402-NM
(RNBx)) for failure to prosecute and failure to comply with orders of the court. 
 Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities. Stock Repurchases The following table details our common stock repurchases for the three months ended January
31, 2005: Issuer Purchases of Equity Securities (a)
    
    
    (b)
    
    
    (c)
    
    
    (d)MaximumNumber (orApproximateTotal
    
    
    DollarNumber of
    
    
    Value) ofShares
    
    
    Shares (or(or Units)
    
    
    Units) thatAverage
    
    
    Purchased as
    
    
    May Yet BeTotal
    
    
    Price
    
    
    Part
    
    
    PurchasedNumber of
    
    
    Paid per
    
    
    of Publicly
    
    
    Under theShares (or Units)
    
    
    Share
    
    
    Announced Plans
    
    
    PlansPeriod
    
    Purchased
    
    
    (or Unit)
    
    
    or Programs
    
    
    or ProgramsNovember 1

30, 2004
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    December 1
 31, 2004
    
    
    120,000
    (1)
    
    
    (1
    )
    
    
    
    
    
    
    January 1  31, 2005
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
   (1)
    
    In connection with a Settlement Agreement and Mutual General Release (the Settlement
Agreement) the Company entered into with stockholder and former director of Commonwealth
Energy Corporation, Joseph P. Saline, and stockholder Joseph Ogundiji on December 23, 2004,
the Company paid Mr. Ogundiji $222,400 in settlement of all his claims and for canceling all
of his shares of common stock. For a further description of this settlement, see Part II, Item
1. Legal Proceedings. 28




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##### Table of Contents



Item 4. Submission of Matters to a Vote of Security Holders. The results of the voting at the Companys annual meeting of stockholders held on January 12,
2005 were previously reported on a current report on Form 8-K filed with the Securities and
Exchange Commission on January 19, 2005. 29




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Item 6. Exhibits. The exhibit listed below is hereby filed with the Securities and Exchange Commission as part
of this Report. ExhibitNumber
    
    Description10.1
    
    
    Settlement Agreement and Mutual General Release dated December 23,2004 by
and between Commerce Energy Group, Inc, Commonwealth Energy Corporation,
Ian Carter, Robert Perkins, Brad Gates, Joseph P. Saline, Patricia E.
Saline and Joseph Ogundiji, previously filed with the Commission as Exhibit
10.1 to the Companys Current Report on Form 8-K filed with the Commission
on December 27, 2004, which is incorporated herein by reference.10.2
    
    
    Commerce Energy Group, Inc. 2005 Employee Stock Purchase Plan, previously
filed with the Commission as Exhibit 10.1 to the Companys Current Report
on Form 8-K filed with the Commission on January 19, 2005, which is
incorporated herein by reference.10.3
    
    
    Asset Purchase Agreement dated as of February 9, 2005 by and among
Commonwealth Energy Corporation, ACN Utility Services, Inc., ACN Energy,
Inc., ACN Power, Inc. and, as to certain sections thereof only, Commerce
Energy Group, Inc. and American Communications Network, Inc., previously
filed with the Commission as Exhibit 2.1 to the Companys Current Report on
Form 8-K filed with the Commission on February 10, 2005, which is
incorporated herein by reference.10.4
    
    
    Transition Services Agreement dated as of February 9, 2005 by and between
American Communications Network, Inc. and Commonwealth Energy Corporation,
previously filed with the Commission as Exhibit 2.2 to the Companys
Current Report on Form 8-K filed with the Commission on February 10, 2005,
which is incorporated herein by reference.10.5
    
    
    Sales Agency Agreement dated as of February 9, 2005 by and among
Commonwealth Energy Corporation, Commerce Energy Group, Inc. and American
Communications Network, Inc., previously filed with the Commission as
Exhibit 2.3 to the Companys Current Report on Form 8-K filed with the
Commission on February 10, 2005, which is incorporated herein by reference.10.6
    
    
    Escrow Agreement dated as of February 9, 2005 by and among Commonwealth
Energy Corporation, ACN Utility Services, Inc., ACN Energy, Inc., ACN
Power, Inc., Commerce Energy Group, Inc., American Communications Network,
Inc. and Computershare Trust Company, Inc., previously filed with the
Commission as Exhibit 2.4to the Companys Current Report on Form 8-K filed
with the Commission on February 10, 2005, which is incorporated herein by
reference.10.7
    
    
    Summary of Commerce Energy Group, Inc. Management Bonus Program for 2005,
previously filed with the Commission as Exhibit 10.1 to the Companys
Current Report on Form 8-K filed with the Commission on March 1, 2005,
which is incorporated herein by reference.10.8
    
    
    Offer Letter for Tom Ulry dated February 28, 2005, previously filed with
the Commission as Exhibit 99.1 to the Companys Current Report on Form 8-K
filed with the Commission on March 7, 2005,which is incorporated herein by
reference.31.1
    
    
    Principal Executive Officer Certification required by Rule 13a-14(a) under
the Securities Exchange Act of 1934, as amended.31.2
    
    
    Chief Financial Officer Certification required by Rule13a-14(a)under of the
Securities Exchange Act of 1934, as amended.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
    
    
    Chief Financial Officer Certification pursuant to 18 U.S.C. Section 1350,
as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 30




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##### Table of Contents



SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the undersigned thereunto duly authorized. COMMERCE ENERGY GROUP, INC. Date: June 14, 2005
    
    By:
    
    /s/ Peter Weigand
Peter WeigandPresident(Principal Executive Officer)
 Date: June 14, 2005
    
    By:
    
    /s/ Richard L. BoughrumRichard L. BoughrumSenior Vice President, Chief Financial Officer(Principal Financial Officer)
 31




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EXHIBIT INDEX ExhibitNumber
    
    Description10.1
    
    
    Settlement Agreement and Mutual General Release dated December 23,2004 by
and between Commerce Energy Group, Inc, Commonwealth Energy Corporation,
Ian Carter, Robert Perkins, Brad Gates, Joseph P. Saline, Patricia E.
Saline and Joseph Ogundiji, previously filed with the Commission as Exhibit
10.1 to the Companys Current Report on Form 8-K filed with the Commission
on December 27, 2004, which is incorporated herein by reference.10.2
    
    
    Commerce Energy Group, Inc. 2005 Employee Stock Purchase Plan, previously
filed with the Commission as Exhibit 10.1 to the Companys Current Report
on Form 8-K filed with the Commission on January 19, 2005, which is
incorporated herein by reference.10.3
    
    
    Asset Purchase Agreement dated as of February 9, 2005 by and among
Commonwealth Energy Corporation, ACN Utility Services, Inc., ACN Energy,
Inc., ACN Power, Inc. and, as to certain sections thereof only, Commerce
Energy Group, Inc. and American Communications Network, Inc., previously
filed with the Commission as Exhibit 2.1 to the Companys Current Report on
Form 8-K filed with the Commission on February 10, 2005, which is
incorporated herein by reference.10.4
    
    
    Transition Services Agreement dated as of February 9, 2005 by and between
American Communications Network, Inc. and Commonwealth Energy Corporation,
previously filed with the Commission as Exhibit 2.2 to the Companys
Current Report on Form 8-K filed with the Commission on February 10, 2005,
which is incorporated herein by reference.10.5
    
    
    Sales Agency Agreement dated as of February 9, 2005 by and among
Commonwealth Energy Corporation, Commerce Energy Group, Inc. and American
Communications Network, Inc., previously filed with the Commission as
Exhibit 2.3 to the Companys Current Report on Form 8-K filed with the
Commission on February 10, 2005, which is incorporated herein by reference.10.6
    
    
    Escrow Agreement dated as of February 9, 2005 by and among Commonwealth
Energy Corporation, ACN Utility Services, Inc., ACN Energy, Inc., ACN
Power, Inc., Commerce Energy Group, Inc., American Communications Network,
Inc. and Computershare Trust Company, Inc., previously filed with the
Commission as Exhibit 2.4to the Companys Current Report on Form 8-K filed
with the Commission on February 10, 2005, which is incorporated herein by
reference.10.7
    
    
    Summary of Commerce Energy Group, Inc. Management Bonus Program for 2005,
previously filed with the Commission as Exhibit 10.1 to the Companys
Current Report on Form 8-K filed with the Commission on March 1, 2005,
which is incorporated herein by reference.10.8
    
    
    Offer Letter for Tom Ulry dated February 28, 2005, previously filed with
the Commission as Exhibit 99.1 to the Companys Current Report on Form 8-K
filed with the Commission on March 7, 2005,which is incorporated herein by
reference.31.1
    
    
    Principal Executive Officer Certification required by Rule 13a-14(a) under
the Securities Exchange Act of 1934, as amended.31.2
    
    
    Chief Financial Officer Certification required by Rule13a-14(a)under of the
Securities Exchange Act of 1934, as amended.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
    
    
    Chief Financial Officer Certification pursuant to 18 U.S.C. Section 1350,
as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 32