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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
 FORM 10-Q (Mark One) x
    
    QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For the quarterly period ended October 31, 2004 Or o
    
    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For the transition period from  to Commission File Number 001-32239 COMMERCE ENERGY GROUP, INC.    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 x 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 x As of December 12, 2004, 30,619,290 shares of the registrants common
stock were outstanding.




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COMMERCE ENERGY GROUP, INC. Form 10-Q
For the Period Ended October 31, 2004
Index  
 PagePart I  Financial InformationItem 1. Financial Statements:Condensed Consolidated Statements of Operations for the three months ended October 31, 2003 and 2004
    
    
    3Condensed Consolidated Balance Sheets as of July 31, 2004 and October 31, 2004
    
    
    4Condensed Consolidated Statements of Cash Flows for the three months ended October 31, 2003 and 2004
    
    
    5Notes to Condensed Consolidated Financial Statements
    
    
    6Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
    
    
    13Item 3. Quantitative and Qualitative Disclosures About Market Risk
    
    
    23Item 4. Controls and Procedures
    
    
    24Part II  Other Information
    
    
    25Item 1. Legal Proceedings
    
    
    25Item 6. Exhibits
    
    
    26Signatures
    
    
    27EXHIBIT 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 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 October 31,2003
    
    2004Net revenue
    
    $
    58,396
    
    
    $
    58,496Direct energy costs
    
    
    54,075
    
    
    
    52,406Gross profit
    
    
    4,321
    
    
    
    6,090Selling and marketing expenses
    
    
    970
    
    
    
    953General and administrative expenses
    
    
    5,518
    
    
    
    5,007Reorganization and initial public listing
expenses
    
    
    118
    
    
    
    Income (loss) from operations
    
    
    (2,285
    )
    
    
    130Other income and expenses:Initial formation litigation expenses
    
    
    (585
    )
    
    
    (1,439
    )Minority interest share of loss
    
    
    544
    
    
    
    Interest income, net
    
    
    130
    
    
    
    189Total other income and expenses
    
    
    89
    
    
    
    (1,250
    )Loss before
benefit from income taxes
    
    
    (2,196
    )
    
    
    (1,120
    )Benefit from income taxes
    
    
    1,074
    
    
    
    Net loss
    
    $
    (1,122
    )
    
    $
    (1,120
    )Loss per common share:Basic
    
    $
    (0.04
    )
    
    $
    (0.04
    )Diluted
    
    $
    (0.04
    )
    
    $
    (0.04
    )
 The accompanying notes are an integral part of these condensed consolidated financial statements. 3




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COMMERCE ENERGY GROUP, INC. 
 CONDENSED CONSOLIDATED BALANCE SHEETS
 (In thousands)
 July 31, 2004
    
    October 31, 2004(Unaudited)ASSETSCurrent assets:Cash and cash equivalents
    
    $
    54,065
    
    
    $
    53,757Accounts receivable, net
    
    
    31,119
    
    
    
    27,452Income taxes refund receivables
    
    
    4,423
    
    
    
    4,423Deferred income tax assets
    
    
    74
    
    
    
    74Prepaid expenses and other current assets
    
    
    5,141
    
    
    
    5,819Total current assets
    
    
    94,822
    
    
    
    91,525Restricted cash and cash equivalents
    
    
    4,008
    
    
    
    4,268Deposits
    
    
    5,445
    
    
    
    5,663Investments
    
    
    96
    
    
    
    96Property and equipment, net
    
    
    2,613
    
    
    
    2,409Goodwill and other intangible assets
    
    
    3,839
    
    
    
    3,671Total assets
    
    $
    110,823
    
    
    $
    107,632LIABILITIES AND STOCKHOLDERS EQUITYCurrent liabilities:Accounts payable
    
    $
    30,576
    
    
    $
    26,808Accrued liabilities
    
    
    6,141
    
    
    
    6,364Total current liabilities
    
    
    36,717
    
    
    
    33,172Stockholders equity:Common stock  150,000 shares authorized
with $0.001 par value; 30,519 shares issued
and outstanding at July 31, 2004 and October
31, 2004
    
    
    60,796
    
    
    
    60,796Unearned restricted stock compensation
    
    
    (256
    )
    
    
    (232
    )Retained earnings
    
    
    13,566
    
    
    
    12,446Other comprehensive income
    
    
    
    
    
    
    1,450Total stockholders equity
    
    
    74,106
    
    
    
    74,460Total
liabilities and stockholders equity
    
    $
    110,823
    
    
    $
    107,632
 The accompanying notes are an integral part of these condensed consolidated financial statements. 4




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COMMERCE ENERGY GROUP, INC. 
 CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 (In thousands)
 (Unaudited)
 Three months ended October 31,2003
    
    2004Cash Flows From Operating ActivitiesNet loss
    
    $
    (1,122
    )
    
    $
    (1,120
    )Adjustments to reconcile net loss to net cash provided by
(used in) operating activities:Depreciation
    
    
    375
    
    
    
    354Amortization
    
    
    63
    
    
    
    168Provision for doubtful accounts
    
    
    661
    
    
    
    548Stock-based compensation expense
    
    
    
    
    
    
    24Minority interest share of loss of consolidated entity
    
    
    172
    
    
    
    Changes in operating assets and liabilities:Accounts receivable, net
    
    
    13,690
    
    
    
    3,119Prepaid expenses and other assets
    
    
    692
    
    
    
    554Accounts payable
    
    
    (5,908
    )
    
    
    (3,769
    )Accrued liabilities and other
    
    
    307
    
    
    
    225Net cash provided by operating activities
    
    
    8,930
    
    
    
    103Cash Flows From Investing ActivitiesPurchase of property and equipment
    
    
    (466
    )
    
    
    (151
    )Net cash used in investing activities
    
    
    (466
    )
    
    
    (151
    )Cash Flows From Financing ActivitiesDecrease (increase) in restricted cash and cash equivalents
    
    
    2,337
    
    
    
    (260
    )Net cash provided by (used in) financing activities
    
    
    2,337
    
    
    
    (260
    )Increase (decrease) in cash and cash equivalents
    
    
    10,801
    
    
    
    (308
    )Cash and cash equivalents at beginning of period
    
    
    40,921
    
    
    
    54,065Cash and cash equivalents at end of period
    
    $
    51,722
    
    
    $
    53,757
 The accompanying notes are an integral part of these condensed consolidated financial statements. 5




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COMMERCE ENERGY GROUP, INC. 
 NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 (in thousands, except per share and per kWh amounts)
 1. Summary of Significant Accounting Policies Basis of Presentation The condensed consolidated financial statements for the three months ended
October 31, 2004 include the accounts of Commerce Energy Group, Inc. (the
Company), its three wholly-owned subsidiaries: Commonwealth Energy Corporation
(Commonwealth) doing business under the brand name electricAmerica, Skipping
Stone, Inc. (Skipping Stone), which was acquired on April 1, 2004, and
UtiliHost, Inc. (UtiliHost). All material intercompany balances and
transactions have been eliminated in consolidation. At October 31, 2003, 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 fiscal 2004, the Company terminated its relationship with Summit
and its investment in PEC decreased to 39.9%, therefore, neither entity was
consolidated as of July 31, 2004 or as of October 31, 2004. (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 and in the
opinion of management, contain all adjustments (consisting of only normal
recurring adjustments) necessary to present fairly the Companys consolidated
financial position, results of operations and cash flows for the periods
presented. Certain information and note disclosures normally included in
consolidated annual financial statements prepared in accordance with accounting
principles generally accepted in the United States have been condensed or
omitted in these consolidated interim financial statements, although the
Company believes that the disclosures are adequate to make the information
presented not misleading. The condensed consolidated results of operations,
financial position, and cash flows for the interim periods presented herein are
not necessarily indicative of future financial results. These interim condensed
consolidated financial statements should be read in conjunction with the annual
consolidated financial statements and the notes thereto included in the
Companys most recent Annual Report on Form 10-K for the year ended July 31,
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, particularly
those associated with litigation. 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. 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) 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 loss for the three month periods ended October 31, 2004
and 2003, 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 loss as applicable to
common stock (see Note 2) and loss per common share if the Company had applied
the fair value recognition provisions of Statement of Financial Accounting
Standards (SFAS) SFAS No. 123: Three months ended October 31,2003
    
    2004Net loss as applicable to common
stock  basic and diluted
    
    $
    (1,122
    )
    
    $
    (1,120
    )Deduct: Total stock-based
compensation expense determined under
fair value based method for all
awards, net of related tax effects
    
    
    (42
    )
    
    
    (3
    )Pro forma net loss  basic and diluted
    
    $
    (1,164
    )
    
    $
    (1,123
    )Loss per share:Basic and diluted  as reported
    
    $
    (0.04
    )
    
    $
    (0.04
    )Basic and diluted  pro forma
    
    $
    (0.04
    )
    
    $
    (0.04
    )
 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. As we acquired Skipping
Stone in fiscal 2004 and its revenue accounts for approximately 1% of
total net revenue, and geographic information is not material, no
segment information is provided. 2. Basic and Diluted Loss per Common Share Basic loss per common share was computed by dividing net loss available to
common stockholders, after any preferred stock dividends, by the weighted
average number of common shares outstanding during the period. Diluted loss per
common share reflects the potential dilution that would occur if all
outstanding options or other contracts to issue common stock were exercised or
converted and was computed by dividing net loss by the weighted average number
of common shares plus dilutive common equivalent shares outstanding, unless
they were anti-dilutive. 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) The following is a reconciliation of the numerator (loss) and the
denominator (common shares in thousands) used in the computation of basic and
diluted loss per common share: Three months ended October 31,2003
    
    2004Numerator:Net loss
    
    $
    (1,122
    )
    
    $
    (1,120
    )Deduct: Preferred stock dividends
    
    
    (164
    )
    
    
    Net loss applicable to common stock
 basic
    
    
    (1,286
    )
    
    
    (1,120
    )Assumed conversion of preferred stock
    
    
    
    
    
    
    Net loss applicable to common stock
 diluted
    
    $
    (1,286
    )
    
    $
    (1,120
    )Denominator:Weighted-average outstanding common shares
 basic
    
    
    27,645
    
    
    
    30,519Effect of stock options
    
    
    
    
    
    
    Effect of convertible preferred stock
    
    
    
    
    
    
    Weighted-average outstanding common shares
 diluted
    
    
    27,645
    
    
    
    30,519
 For the three months ended October 31, 2003 and 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 months ended October 31, 2003 and 2004 would have
been 29,159 and 30,881, 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. 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) 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 Customer Responsibility Surcharge (DA CRS)
is currently fixed at $0.027 per kWh. 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 enrolled in DA prior to February 1,
2001, in the SCE service territory continue to pay only the $0.01 HPC. While
this charge does not directly impact the Companys rate design or revenue, it
may affect the Companys ability to retain existing customers or compete for
new customers. In December 2003, Pacific Gas and Electric (PG&E) and the CPUC reached a
settlement in the PG&E bankruptcy. In February 2004, the CPUC approved a rate
settlement agreement, which reduced overall customer rates in the PG&E service
territory. DA bills have generally declined in the PG&E service territory and
the lower rates have affected the Companys revenue and profitability. Currently, four important issues are under review at the CPUC, a Resource
Adequacy Requirement, a Renewable Portfolio Standard, Utilities Long Term
Procurement Plans and the General Rate Cases of the electric distribution
utilities. Additional costs to serve customers in California are anticipated
from these proceedings, however, the CPUC decisions will determine the
distribution of those costs across all load serving entities and ultimately the
Companys financial impact. Pennsylvania In 1996, the Electricity Generation Customer Choice and Competition Act
was passed. The 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 slightly decreased charges
applied to 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. 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) 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 early stage investments in 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). They each have very limited working capital
and as a result, continuing operations will be dependent upon their securing
additional financing to meet their immediate capital needs. The Company has no
obligation, and currently no intention of investing additional funds into these
companies. At October 31, 2004, the Companys ownership interest in Encorp, Turbocor
and PEC was 2.3%, 9.3% and 39.9%, respectively. The Company accounts for its
investment in Encorp and Turbocor under the cost method of accounting.
Although the Company currently accounts for its investment in PEC (ticker
symbol: PEFF) under the equity method of accounting, in fiscal 2004, the
Company recorded a loss sufficient to reduce the Companys investment basis in
PEC to zero and, therefore, it will have no negative impact on the Companys
financial results in the current fiscal year. At October 31, 2003, PEC was
consolidated in the Companys financial statements. 5. Contingencies Litigation On January 15, 2003, the Company filed a complaint in the United States
District Court for the Central District of California entitled Commonwealth
Energy Corporation v. Wayne Mosley; et al. against several dissident
stockholders who the Company believes had illegally solicited proxies in
connection with the annual meeting of stockholders on January 21, 2003. On
February 6, 2003, the Company filed an amended complaint in this lawsuit asking
the court to confirm that its Board of Directors had been legally elected by
the stockholders and validating the inspectors determination at the annual
meeting that the proxy materials sent by defendants had violated several
Securities and Exchange Commission (SEC) rules and regulations and that the
resulting proxies were invalid. On June 10, 2003, the court issued a default
judgment against certain defendants, finding 1) the Company properly conducted
the election at the Companys annual meeting and the inspector of elections was
correct in rejecting the proxies solicited by the group; 2) the inspector of
elections counted the votes and proxies properly (and thus the elections
results were validated); and 3) the challenged proxies violated various SEC
rules and were therefore invalid. Three members of the group, and all persons
acting in concert with them, were ordered by the court to comply with all
federal securities laws and SEC rules in any future attempts to solicit
proxies. However, two additional defendants, who were not subject to the
courts earlier ruling, brought a counterclaim against the Company on November
14, 2003 alleging that its Board of Directors was not properly elected at the
annual meeting. This action is currently pending and seeks an order voiding the
results of the Board of Directors election at the 2003 annual meeting and
compelling the Company to seat certain other persons whom they allege should
have been elected to the Board. No damages are currently being sought by
plaintiffs in this case. The Company intends to defend these counter-claims
vigorously. On February 14, 2003, the Company filed a complaint in the Orange County
Superior Court against Joseph Ogundiji seeking a judicial declaration
invalidating 80 shares of its capital stock Mr. Ogundiji claims to hold. On
April 11, 2003, Mr. Ogundiji filed and served an answer and cross-complaint
alleging claims against the Company for breach of contract, conversion,
declaratory relief, promissory estoppel, unlawful denial of voting rights
pursuant to California Corporations Code Section 709, illegal stock dividends
in violation of California Corporations Code Section 25120, and unjust
enrichment. The cross-complaint seeks an unspecified amount of general and
punitive damages. This matter is scheduled for trial on June 20, 2005. 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) On November 20, 2003, the Company filed a Notice of Appeal in the
California Court of Appeals in Saline v. Commonwealth Energy Corporation. The
appealed order was entered after the first of two trial phases and requires
Commonwealth to recognize the shares of other convertible preferred stock held
by plaintiff, Joseph Saline, a former director, as valid. A second phase of the
trial is scheduled for January 18, 2005, Commonwealth recently prevailed on its
motion for summary adjudication of Mr. Salines conversion claim, so only a
breach of contract claim remains
for trial. Another case brought by Mr. Saline, Saline v. Commonwealth
Energy Corporation has been consolidated with this case for trial on January
18, 2005. The remaining claims in the second case are allegations by
Commonwealth and/or certain intervenor plaintiffs that Mr. Saline breached his
fiduciary duties as a director, libeled the Company, and illegally tape
recorded certain board meetings. In this second case, Mr. Saline has appealed
the trial courts denial of his motion to strike the libel claims and refusal
to award him attorneys fees related to his original claim concerning his
access to corporate documents. On November 25, 2003, several stockholders filed a lawsuit against the
Company entitled Coltrain, et al. v. Commonwealth Energy Corporation, et al.
The complaint purports to be a class action against the Company for violations
of section 709 of the California Corporations Code. The plaintiffs allege that
the Company failed to correctly count approximately 39,869 votes cast at the
2003 annual meeting and, as a result, the Board of Directors was not properly
elected. Instead, the plaintiffs allege that four different persons would have
been seated on the Board had the votes been tabulated in the manner advocated
by the plaintiffs. This case involves identical issues of law and fact as the
counterclaim discussed above in Commonwealth Energy Corporation v. Wayne
Moseley, et al. and is currently pending. Commonwealth recently settled with
one of the plaintiffs in this case, Coltrain. Commonwealth is vigorously
defending this action. On April 19, 2004, Mr. Saline and Mr. Ogundiji filed an action in
California Superior Court for Orange County, alleging that Commonwealth Energy
Corporations Board of Directors (other than Mr. Saline) breached their
fiduciary duties and breached the covenant of good faith and fair dealing by
approving and putting to a stockholder vote the recent reorganization plan,
which resulted in Commonwealth becoming a wholly-owned subsidiary of Commerce
Energy Group, Inc. In addition, they allege that Commonwealth improperly failed
to hold an annual meeting within the time limits set by California Corporations
Code Section 600, improperly used the reorganization to alter their rights as
preferred shareholders, and improperly refused to hold a vote just among
preferred stockholders regarding the reorganization. Up to this point in the
litigation, Mr. Saline and Mr. Ogundiji have attempted to block the special
meeting at which the reorganization was approved, to enjoin the reorganization,
to unwind the reorganization and to de-list the shares of common stock of
Commerce listed on the AMEX, but were not successful. Because our directors are
defendants in this case, pursuant to the terms of the indemnification
agreements between Commonwealth and its directors, we are required to indemnify
the directors to the fullest extent allowed by law. The indemnification
agreement covers any expenses and/or liabilities reasonably incurred in
connection with the investigation, defense, settlement or appeal of legal
proceedings. The obligation to provide indemnification does not apply if the
officer or director is found to be liable for fraudulent or criminal conduct.
Pursuant to the indemnification agreement, the Company is currently providing a
joint defense with the directors in this action. This matter is scheduled for
trial in September 12, 2005 and Commonwealth will defend vigorously. 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 October 31, 2004. 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 strategies 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, 11




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COMMERCE ENERGY GROUP, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(continued)
(in thousands, except per share and per kWh amounts) 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 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 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 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. Some of these transactions do
not qualify for hedge accounting 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. The Company did not engage in trading
activities in the wholesale energy market other than to manage its direct
energy cost in an attempt to improve the profit margin associated with its
customer requirements. The amounts recorded in OCI at October 31, 2004 related to cash flow
hedges are summarized in the following table: IncreaseJuly 31,
    
    (Decrease)
    
    October 31,2004
    
    in OCI
    
    2004Current assets
    
    $
    
    
    
    $
    1,450
    
    
    $
    1,450Other comprehensive income
    
    $
    
    
    
    $
    1,450
    
    
    $
    1,450
 The Company does not use derivative instruments related to its interest
rate exposure at this time. 12




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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. As of October 31, 2004, we delivered electricity to approximately 100,000
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 and 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 can differ significantly 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, Inc., or 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 is our wholly-owned
subsidiary and its revenue (after elimination of
intercompany transactions) was less than 1% of our consolidated totals for the
three months ended October 31, 2004. 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, and we retained only a 39.9% interest in PEC, therefore, we are no
longer consolidating either Summit or PEC in our current fiscal year financial
results. 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 the current fiscal year. 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 13




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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 Customer Responsibility Surcharge, or DA CRS,
is currently fixed at $0.027 per kWh. 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 enrolled
in DA prior to February 1, 2001, 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. The 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. 14




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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. 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 slightly decreased charges
applied to 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 quarter of fiscal 2005, we also employed financial hedges
using derivative instruments, to hedge our 15




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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 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 October 31, 2004 compared to three months ended October 31,
2003. Net revenue of $58.5 million remained constant for the three months ended
October 31, 2004 compared to the three months ended October 31, 2003. Gross
profit increased $1.8 million, or 41%, to $6.1 million for the three months
ended October 31, 2004 compared to $4.3 million for the same prior year period.
The gross profit improvement in the three months ended October 31, 2004 was
primarily due to substantial improvement in the operating income contribution
in Pennsylvania which offset the continuing pressure on gross profit in the
California business. The Companys operating results for the three months
ended October 31, 2004 included income from operations of $0.1 million compared
to a loss of $2.3 million for the same prior year period. Net revenue Revenue of $58.5 million in the current year resulted primarily from
increased energy sales of $2.4 million in Michigan offset by a decrease in
California of $2.3 million compared to the prior year period. In Michigan, we
sold 209 million kWh at an average retail price per kWh of $0.057 in the three
months ended October 31, 2004, as compared to 179 million kWh at an average
retail price per kWh of $0.054 in the same period last year. The 16




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increase in volume was primarily due to continued increases in our
Michigan customer base. In California, we sold 324 million kWh at an average
retail price per kWh of $0.068 in the three months ended October 31, 2004, as
compared to 355 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 due to
customer attrition attributable to our efforts to improve profitability per
customer. In Pennsylvania, we sold 405
million kWh at an average retail price per kWh of $0.059 in the three months
ended October 31, 2004, as compared to 413 million kWh sold at an average
retail price per kWh of $0.059 in the same period last year. At October 31, 2004, we had approximately 100,000 customers compared to
115,000 customers at October 31, 2003. The number of customers has decreased
due to our profitability per customer focus, reducing the number of
residential customers, which have much lower average usage, and are less
profitable. The decrease was 12% in California and 19% in Pennsylvania, while
we increased our customer base in Michigan by 54% and entered the New
Jersey market 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
decreased to $52.4 million for the three months ended October 31, 2004, a
decrease of $1.7 million, or 3%, from $54.1 million for the three months ended
October 31, 2003. The decrease in direct energy costs occurred primarily in Pennsylvania
partially offset by increases in Michigan and California. In Pennsylvania, our
average cost per kWh was $0.055 for the three months ended October 31, 2004, as
compared to an average cost per kWh of $0.063 for the same period in fiscal
2003. In Michigan, our average cost per kWh was $0.051 for the three months
ended October 31, 2004, as compared to an average cost per kWh of $0.048 for
the same period last year. In California, our average cost per kWh was $0.059
for the three months ended October 31, 2004, as compared to an average cost per
kWh of $0.054 for the same period in fiscal 2003. Selling and marketing expenses Our selling and marketing expenses remained constant at $1.0 million for
the three months ended October 31, 2004 and 2003. General and administrative expenses Our general and administrative expenses decreased $0.5 million, or 9%, to
$5.0 million for the three months ended October 31, 2004 compared to $5.5
million in the three months ended October 31, 2003. The decrease was primarily
attributed to fiscal 2003 management fee expenses of $0.2 million incurred in
connection with Summit, which we no longer incur due to the termination of the
Summit agreement at the end of fiscal 2003. The remaining decrease
was attributable to various
expense categories within general and administrative expenses. Reorganization and initial public listing expenses We incurred $0.1 million in the first 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 believes it is appropriate to classify these costs as a separately
identified selling, general and administrative expense category, and include
expenses such as legal, accounting, auditing, consulting, and printing and
reproduction fees that are specific to these activities. We incurred no
reorganization and initial public listing expenses in fiscal 2005. Initial formation litigation expenses In the three months ended October 31, 2004, we incurred $1.4 million of
initial formation litigation costs related to Commonwealth Energy Corporations
formation compared to $0.6 million of such costs incurred during the three 17




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months ended October 31, 2003. 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 the Companys financial statements in fiscal 2005. Benefit from income taxes No provision for or benefit from income taxes was recorded for the three
months ended October 31, 2004; as compared to the benefit from income taxes of
$1.1 million for the three months ended October 31, 2003. 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. Liquidity and Capital Resources As of October 31, 2004, our unrestricted cash and cash equivalents were
$53.8 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. Our principal sources of liquidity to fund ongoing operations were
cash provided by operations and existing cash and cash equivalents. Cash flow provided by operations for the three months ended October 31,
2004 was $0.1 million, compared to $8.9 million in the three months ended
October 31, 2003. In the three months ended October 31, 2004, cash was
provided primarily by a decrease in accounts receivable of $3.1 million offset
by cash used primarily to decrease accounts payable by $3.8 million. Cash flow used in investing activities for the three months ended October
31, 2004 was $0.2 million compared to $0.5 million for the three months ended
October 31, 2003. Cash used in investments consisted of capital expenditures. Cash flow used in financing activities for the three months ended October
31, 2004 was $0.3 million, compared to cash flow provided by financing
activities of $2.3 million in the three months ended October 31, 2003. In the
prior fiscal year, restricted cash increased primarily due to the partial
reduction of the required security for an appeals bond related to litigation. 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 October 31, 2004, we had $4.3
million in restricted cash to secure letters of credit required by our
suppliers and $5.4 million in deposits pledged as collateral in connection with
energy purchase agreements. Based upon our current plans, level of operations and business conditions,
we believe that our cash and cash equivalents, and cash generated from
operations will be sufficient to meet our capital requirements and working
capital needs for the foreseeable future. However, there can be no assurance
that we will not be required to seek other financing in the future or that such
financing, if required, will be available on terms satisfactory to us. Contractual Obligations For the three months ended October 31, 2004, we have entered into
additional electricity purchase contracts in the normal course of doing
business for $14.1 million. These contracts are for less than one year and are
with various suppliers. 18




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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. Only recently have a
small number of markets opened to competition under rules that we believe may
offer attractive competitive opportunities. Our business model depends on other
favorable markets opening under viable competitive rules in a timely manner. In
any particular market, there are a number of rules that will ultimately
determine the attractiveness of any market. Markets that we enter may have both
favorable and unfavorable rules. If the trend towards competitive restructuring
of retail energy markets does not continue or is delayed or reversed, our
business prospects and financial condition could be materially adversely
impaired. Retail energy market restructuring has been and will continue to be a
complicated regulatory process, with competing interests advanced not only by
relevant state and federal utility regulators, but also by state legislators,
federal legislators, local utilities, consumer advocacy groups and potential
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. 19




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We may experience difficulty attracting customers because many customers
may be reluctant to switch to a new supplier for a commodity as critical to
their well-being as electric power. A major focus of our marketing efforts will
be to convince customers that we are a reliable provider with sufficient
resources to meet our commitments. If our marketing strategy is not successful,
our business, results of operations and financial condition could be materially
adversely affected. We depend upon internally developed systems and processes to provide several
critical functions for our business, and the loss of these functions could
materially adversely impact our business. We have developed our own systems and processes to operate our back-office
functions, including customer enrollment, metering, forecasting, settlement and
billing. Problems that arise with the performance of our back-office functions
could result in increased expenditures, delays in the launch of our commercial
operations into new markets, or unfavorable customer experiences that could
materially adversely affect our business strategy. Also, any interruption of
these services could be disruptive to our business. Substantial fluctuations in electricity prices or the cost of transmitting and
distributing electricity could have a material adverse affect on us. To provide electricity to our customers, we must, from time to time,
purchase electricity in the short-term or spot wholesale energy markets, which
can be highly volatile. In particular, the wholesale electric power market can
experience large price fluctuations during peak load periods. Furthermore, to
the extent that we enter into contracts with customers that require us to
provide electricity at a fixed price over an extended period of time, and to
the extent that we have not purchased electricity to cover those commitments,
we may incur losses caused by rising wholesale electricity prices. Periods of
rising electricity prices may reduce our ability to compete with local
utilities because their regulated rates may not immediately increase to reflect
these increased costs. Energy Service Providers like us take on the risk of
purchasing power for an uncertain load and if the load does not materialize as
forecast, it leaves us in a long position that would be resold into the
wholesale electricity market. Sales of this surplus electricity could be at
prices below our cost. Conversely, if unanticipated load appears that may
result in an insufficient supply of electricity, we would need to purchase the
additional supply. These purchases could be at prices that are higher than our
sales price to our customers. Either situation could create losses for us if we
are exposed to the price volatility of the wholesale spot markets. Any of these
contingencies could substantially increase our costs of operation. Such factors
could have a material adverse effect on our financial condition. We are dependent on local utilities for distribution of electricity to our
customers over their distribution networks. If these local utilities are unable
to properly operate their distribution networks, or if the operation of their
distribution networks is interrupted for periods of time, we could be unable to
deliver electricity to our customers during those interruptions. This would
results in lost revenue to us, which could adversely impact the results of our
operations. Historical procurement charges and customer rate changes in the Southern
California Edison utility district could adversely affect our revenue and cash
flows. Under a Settlement agreement with the California PUC, SCE was authorized
to recoup $3.6 billion in debt incurred during the energy crisis of 2000-2001
from all customers. This debt was to be collected under the Procurement Related
Obligations Account, or PROACT, from bundled (non direct access) customers and
under the HPC from DA customers. In July 2002, the California PUC issued an interim order implementing the
HPC sought by SCE. This interim order authorized SCE to collect $391 million in
HPC charges from all DA customers by reducing their Procured Energy Credit, or
PE Credit, by $0.027 per kWh beginning July 27, 2002. The lowered PE Credit
continued until an exit fee for DA customers was approved by the CPUC.
Effective January 1, 2003, it was reduced to $0.01 per kWh. For the fiscal year
ended July 31, 2003, we estimate that HPC charges have impacted our sales and
pretax earnings by a range of $4.8 million to $6.0 million. We are unable to
precisely determine the actual HPC charges applied to our customers by SCE
because there are different charges, by customer type, and this charge is only
on the electricity usage above the monthly baseline usage allocation. 20




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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 includes the former impact of
the HPC. This rate reduction will impact sales and pretax profit in the SCE
district. The rate reduction will be in place in 2004 and will approximate the
effect of the HPC dollar impact of 2003. Recently, SCE acknowledged that the PROACT debt was paid in full by
bundled customers at the end of July 2003. As a result, on August 1, 2003, all
SCE rates were lowered. As a direct result, to retain our customers in the SCE
utility district, we lowered our customer rates proportionately. Our estimate
of the annual financial impact of this rate reduction is a decline in sales and
pretax profit during fiscal 2004, in the range of $3.0 to $3.5 million. This
reduction is separate from, and in addition to, the HPC related reduction in
2003. These changes in the SCE service territory will continue to cause a
significant impact on our revenue and cash flow; however, we currently do not
expect they will preclude us from continuing to participate in the SCE market. Some suppliers of electricity have been experiencing deteriorating credit
quality. We continue to monitor our suppliers credit quality to attempt to reduce
the impact of any potential counterparty default. As of October 31, 2004, 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. 21




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In some markets, we are required to bear credit risk and billing responsibility
for our customers. In some markets, we are responsible for the billing and collection
functions for our customers. In these markets, we may be limited in our ability
to terminate service to customers who are delinquent in payment. Even if we
terminate service to customers who fail to pay their utility bill in a timely
manner, we may remain liable to our suppliers of electricity for the cost of
the electricity and to the local utilities for services related to the
transmission and distribution of electricity to those customers. The failure of
our customers to pay their bills in a timely manner or our failure to maintain
adequate billing and collection programs could materially adversely affect our
business. Our revenues and results of operations are subject to market risks that are
beyond our control. We sell electricity that we purchase from third-party power generation
companies to our retail customers on a contractual basis. We are not guaranteed
any rate of return through regulated rates, and our revenues and results of
operations are likely to depend, in large part, upon prevailing market prices
for electricity in our regional markets. These market prices may fluctuate
substantially over relatively short periods of time. These factors could have
an adverse impact on our revenues and results of operations. Volatility in market prices for electricity results from multiple factors,
including:  
    
    weather conditions, including hydrological conditions such as precipitation, snow pack and streamflow,
    
    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. Our results of operation and financial condition could be affected by pending
and future litigation. We are currently a defendant in several pending lawsuits. We believe our
substantive and procedural defenses in each of these cases are meritorious, but
we cannot predict the outcome of any such litigation. In addition, we may
become subject to additional lawsuits in the future. If we are held liable for
significant damages in any lawsuit, our operations and financial condition may
be harmed. In addition, we could incur substantial expenses in connection with
any such litigation, including substantial fees for attorneys and other
professional advisors. These expenses could adversely affect our operations and
cash position if they are material in amount. 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 our preparation for
our 2004 audit, we discovered an unreconciled energy accounting issue that
caused us to restate our second and third quarter reported results. Our
external auditor identified this issue as a reportable 22




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condition and a material weakness, 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 2004, we devoted 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 2004, 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 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, 2005,
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, 2005. 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 October 31, 2004. 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, 23




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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 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 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 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 October 31, 2004 related to cash flow
hedges are summarized in the following table: IncreaseJuly 31,
    
    (Decrease)
    
    October 31,2004
    
    in OCI
    
    2004Current assets
    
    $
    
    
    
    $
    1,450
    
    
    $
    1,450Other comprehensive income
    
    $
    
    
    
    $
    1,450
    
    
    $
    1,450
 As of October 31, 2004, we had 84% 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. Our Principal Executive Officer and Chief Financial Officer have
concluded, based on their evaluation as of the end of the period covered by
this report, that our disclosure controls and procedures (as defined in Rules
13(a)-15(e) under the Securities Act of 1934, as amended) are effective to
ensure that all information required to be disclosed by the Company in the
reports filed or submitted by it under the Securities and Exchange Act is
recorded, processed, summarized and reported within the time periods specified
in the SECs rules and forms, and include controls and procedures designed to
ensure that information required to be disclosed by the Company in such reports
is accumulated and communicated to the Companys management, including the
Principal Executive Officer and the Chief Financial Officer, as appropriate and
allow timely decisions regarding required disclosure. b) Changes in Internal Controls. In connection with the above-referenced evaluation, no change in the
Companys internal control over financial reporting occurred during the period
covered by this report that has materially affected, or is reasonably likely to
materially affect, the Companys internal control over financial reporting. We are evaluating the effectiveness of our internal controls over
financial reporting in order to comply with Section 404 of the Sarbanes-Oxley
Act of 2002. Section 404 requires us to evaluate annually the effectiveness of
our internal controls over financial reporting as of the end of each fiscal
year beginning in 2005, and to include a management report assessing the
effectiveness of our internal controls over financial reporting in all annual
reports beginning with our Annual Report on Form 10-K for the fiscal year
ending on July 31, 2005. Section 404 also requires our independent accountant
to attest to, and report on, managements assessment of our internal controls
over financial reporting. In evaluating our internal controls over financial
reporting, we have identified a number of 24




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changes that need to be made to our internal controls, primarily related
to better documenting the controls, and related changes to information systems
used in financial reporting. We began making these changes during the second
quarter of 2005. The changes we began during the second quarter of
2005 did not,
individually or in the aggregate, have a material effect on our internal
controls over financial reporting. 
 PART II OTHER INFORMATION 
 Item 1. Legal Proceedings. Reference is made to the Companys Report on Form 10-K for the period
ended July 31, 2004 (the 10-K), for a summary the Companys legal proceedings
previously reported. Since the date of the 10-K, there have been no material
developments in previously reported legal proceedings. 25




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Item 6. Exhibits. The exhibit listed below is hereby filed with the Commission as part of this
Report. ExhibitNumber
    
    Description10.1
    
    Form of Non-Employee Director Stock Option Agreement for directors,
previously filed with the Commission on December 8, 2004 as Exhibit
10.1 to Commerce Energy Group, Inc.s Current Report on Form 8-K,
which is incorporated herein by reference.10.2
    
    Commerce Energy Group, Inc. Non-Employee Director Compensation
Policy, previously filed with the Commission on December 8, 2004 as
Exhibit 10.2 to Commerce Energy Group, Inc.s Current Report on Form
8-K, which is incorporated herein by reference.10.3
    
    Revised Security Agreement dated October 27, 2004 by and between
Commonwealth Energy Corporation and DTE Energy Trading, previously
filed with the Commission on November 15, 2004 as Exhibit 10.32 to
Commerce Energy Group, Inc.s Annual Report on Form 10-K, which is
incorporated herein by reference.10.4
    
    Revised Operating Agreement dated November 15, 2004 between DTE
Energy Trading, Inc. and Commonwealth Energy Corporation, previously
filed with the Commission on April 5, 2004 as Exhibit 10.33 to
Commerce Energy Group, Inc.s Annual Report on Form 10-K, 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 Rule 13a-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.
 26




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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: December 15, 2004
    
    By:
    
    /s/ Peter WeigandPeter WeigandPresident(Principal Executive Officer)Date: December 15, 2004
    
    By:
    
    /s/ Richard L. BoughrumRichard L. BoughrumSenior Vice President, Chief Financial Officer(Principal Financial Officer)
 27




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EXHIBIT INDEX The exhibit listed below is hereby filed with the Commission as part of this
Report. ExhibitNumber
    
    Description10.1
    
    Form of Non-Employee Director Stock Option Agreement for directors,
previously filed with the Commission on December 8, 2004 as Exhibit
10.1 to Commerce Energy Group, Inc.s Current Report on Form 8-K,
which is incorporated herein by reference.10.2
    
    Commerce Energy Group, Inc. Non-Employee Director Compensation
Policy, previously filed with the Commission on December 8, 2004 as
Exhibit 10.2 to Commerce Energy Group, Inc.s Current Report on Form
8-K, which is incorporated herein by reference.10.3
    
    Revised Security Agreement dated October 27, 2004 by and between
Commonwealth Energy Corporation and DTE Energy Trading, previously
filed with the Commission on November 15, 2004 as Exhibit 10.32 to
Commerce Energy Group, Inc.s Annual Report on Form 10-K, which is
incorporated herein by reference.10.4
    
    Revised Operating Agreement dated November 15, 2004 between DTE
Energy Trading, Inc. and Commonwealth Energy Corporation, previously
filed with the Commission on April 5, 2004 as Exhibit 10.33 to
Commerce Energy Group, Inc.s Annual Report on Form 10-K, which is
incorporated herein by reference.31.1
    
    Principal Executive Officer Certification required by rule 13a-14(a)
of the Securities Exchange Act of 1934, as amended.31.2
    
    Chief Financial Officer Certification required by Rule 13a-14(a) 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.
 28