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,
|
|
|
|
2007
|
|
|
2006
|
|
Net
revenue
|
|
$
|
105,597
|
|
|
$
|
70,507
|
|
Direct
energy costs
|
|
|
89,209
|
|
|
|
60,451
|
|
Gross
profit
|
|
|
16,388
|
|
|
|
10,056
|
|
Selling
and marketing expenses
|
|
|
3,932
|
|
|
|
2,235
|
|
General
and administrative expenses
|
|
|
13,460
|
|
|
|
7,849
|
|
Loss
from operations
|
|
|
(1,004
|
)
|
|
|
(28
|
)
|
Other
income (expense):
|
|
|
|
|
|
|
|
|
Interest
income
|
|
|
230
|
|
|
|
412
|
|
Interest
expense
|
|
|
(313
|
)
|
|
|
—
|
|
Total
other income and expenses
|
|
|
(83
|
)
|
|
|
412
|
|
Net
income (loss)
|
|
$
|
(1,087
|
)
|
|
$
|
384
|
|
Income
(loss) per common share:
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(0.04
|
)
|
|
$
|
0.01
|
|
Diluted
|
|
$
|
(0.04
|
)
|
|
$
|
0.01
|
|
The
accompanying notes are an integral part of these Condensed Consolidated
Financial Statements.
COMMERCE
ENERGY GROUP, INC.
CONDENSED
CONSOLIDATED BALANCE SHEETS
(In
Thousands, Except Per Share Amounts)
|
|
|
|
|
July
31,
2007
|
|
|
|
(Unaudited)
|
|
|
|
|
ASSETS
|
|
Current
assets:
|
|
|
|
|
|
|
Cash
and equivalents
|
|
$
|
5,442
|
|
|
$
|
6,559
|
|
Accounts
receivable, net
|
|
|
65,950
|
|
|
|
65,231
|
|
Natural
gas inventory
|
|
|
9,382
|
|
|
|
5,905
|
|
Prepaid
expenses and other current
|
|
|
9,245
|
|
|
|
7,224
|
|
Total
current assets
|
|
|
90,019
|
|
|
|
84,919
|
|
|
|
|
|
|
|
|
|
|
Restricted
cash and equivalents
|
|
|
10,104
|
|
|
|
10,457
|
|
Deposits
and other assets
|
|
|
1,802
|
|
|
|
1,906
|
|
Property
and equipment, net
|
|
|
8,970
|
|
|
|
8,662
|
|
Goodwill
|
|
|
4,247
|
|
|
|
4,247
|
|
Other
intangible assets, net
|
|
|
5,946
|
|
|
|
6,385
|
|
Total
assets
|
|
$
|
121,088
|
|
|
$
|
116,576
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES
AND STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
Current
liabilities:
|
|
|
|
|
|
|
|
|
Energy
and accounts payable
|
|
$
|
31,068
|
|
|
$
|
37,926
|
|
Short-term
borrowings
|
|
|
12,400
|
|
|
|
—
|
|
Accrued
liabilities
|
|
|
7,209
|
|
|
|
8,130
|
|
Total
current liabilities
|
|
|
50,677
|
|
|
|
46,056
|
|
|
|
|
|
|
|
|
|
|
Commitments
and contingencies
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders’
equity:
|
|
|
|
|
|
|
|
|
Common
stock — 150,000 shares authorized with $0.001 par value;
30,373
(unaudited) issued and outstanding at October 31, 2007
and
30,383 at July 31, 2007
|
|
|
60,789
|
|
|
|
60,599
|
|
Other
comprehensive income (loss)
|
|
|
(35
|
)
|
|
|
(823
|
)
|
Retained
earnings
|
|
|
9,657
|
|
|
|
10,744
|
|
Total
stockholders’ equity
|
|
|
70,411
|
|
|
|
70,520
|
|
Total
liabilities and stockholders’ equity
|
|
$
|
121,088
|
|
|
$
|
116,576
|
|
The
accompanying notes are an integral part of these Condensed Consolidated
Financial Statements.
COMMERCE
ENERGY GROUP, INC.
CONDENSED
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In
Thousands)
(Unaudited)
|
|
Three
Months Ended
October
31,
|
|
|
|
2007
|
|
|
2006
|
|
Cash
Flows From Operating Activities
|
|
|
|
|
|
|
Net
income (loss)
|
|
$
|
(1,087
|
)
|
|
$
|
384
|
|
Adjustments
to reconcile net income (loss) to net cash used in operating
activities:
|
|
|
|
|
|
|
|
|
Depreciation
|
|
|
544
|
|
|
|
348
|
|
Amortization
|
|
|
440
|
|
|
|
365
|
|
Amortization
of deferred loan costs
|
|
|
41
|
|
|
|
124
|
|
Provision
for doubtful accounts
|
|
|
3,665
|
|
|
|
875
|
|
Stock-based
compensation expense
|
|
|
190
|
|
|
|
134
|
|
Changes
in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
Accounts
receivable, net
|
|
|
(4,384
|
)
|
|
|
(7,749
|
)
|
Inventory
|
|
|
(3,476
|
)
|
|
|
(2,689
|
)
|
Prepaid
expenses and other assets
|
|
|
(1,959
|
)
|
|
|
(373
|
)
|
Accounts
payable
|
|
|
(6,859
|
)
|
|
|
(3,297
|
)
|
Accrued
liabilities and other
|
|
|
(133
|
)
|
|
|
2,390
|
|
Net
cash used in operating activities
|
|
|
(13,018
|
)
|
|
|
(9,488
|
)
|
|
|
|
|
|
|
|
|
|
Cash
Flows From Investing Activities
|
|
|
|
|
|
|
|
|
Purchase
of property and equipment
|
|
|
(852
|
)
|
|
|
(1,529
|
)
|
Purchase
of intangible assets
|
|
|
—
|
|
|
|
(4,218
|
)
|
Net
cash used in investing activities
|
|
|
(852
|
)
|
|
|
(5,747
|
)
|
|
|
|
|
|
|
|
|
|
Cash
Flows From Financing Activities
|
|
|
|
|
|
|
|
|
Short-term
borrowings
|
|
|
12,400
|
|
|
|
—
|
|
Credit
line commitment fee
|
|
|
—
|
|
|
|
18
|
|
Decrease
in restricted cash
|
|
|
353
|
|
|
|
362
|
|
Net
cash provided by financing activities
|
|
|
12,753
|
|
|
|
380
|
|
|
|
|
|
|
|
|
|
|
Decrease
in cash and cash equivalents
|
|
|
(1,117
|
)
|
|
|
(14,855
|
)
|
Cash
and cash equivalents at beginning of period
|
|
|
6,559
|
|
|
|
22,941
|
|
Cash
and cash equivalents at end of period
|
|
$
|
5,442
|
|
|
$
|
8,086
|
|
The
accompanying notes are an integral part of these Condensed Consolidated
Financial Statements.
COMMERCE
ENERGY GROUP, INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS)
(Dollars
In Thousands, Except Per Share Amounts)
(Unaudited)
Note
1. Summary of Significant Accounting Policies
Basis
of Presentation
The
unaudited condensed consolidated financial statements as of October 31, 2007
and
for the three months ended October 31, 2007 and 2006 of Commerce Energy Group,
Inc., or the Company, include its two wholly-owned subsidiaries: Commerce
Energy, Inc. or Commerce, and Skipping Stone Inc., or Skipping Stone. All
material inter-company balances and transactions have been eliminated in
consolidation. As used herein and unless the context requires otherwise,
the
reference to the Company, “we,” “us” and “our” refers to Commerce Energy Group,
Inc. and its subsidiaries.
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 condensed
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 Annual Report on Form
10-K for the year ended July 31, 2007.
Uses
of Estimates
The
preparation of condensed consolidated financial statements in conformity
with
accounting principles generally accepted in the United States requires
management to make certain estimates and assumptions that affect the reported
amounts and timing of revenue and expenses, the reported amounts and
classification of assets and liabilities, and disclosure of contingent assets
and liabilities. These estimates and assumptions are based on the Company’s
historical experience as well as management’s future expectations. As a result,
actual results could materially differ from management’s estimates and
assumptions. In preparing our financial statements and accounting for the
underlying transactions and balances, we apply our accounting policies as
disclosed in our notes to the condensed consolidated financial statements.
The
accounting policies relating to accounting for derivatives and hedging
activities, inventory, independent system operator costs, allowance for doubtful
accounts, revenue and unbilled receivables are those that we consider to
be the
most critical to an understanding of our financial statements because their
application places the most significant demands on our ability to assess
the
effect of inherently uncertain matters on our financial results.
Revenue
Recognition
Energy
revenues are recognized when the electricity and natural gas are delivered
to
the Company’s customers and are comprised of the following:
|
|
Three
Months
Ended
October
31,
|
|
|
|
2007
|
|
|
2006
|
|
Retail
electricity sales
|
|
$
|
84,225
|
|
|
$
|
53,407
|
|
Excess
electricity sales
|
|
|
—
|
|
|
|
1,436
|
|
Total
electricity sales
|
|
|
84,225
|
|
|
|
54,843
|
|
Retail
natural gas sales
|
|
|
21,372
|
|
|
|
15,664
|
|
Net
revenue
|
|
$
|
105,597
|
|
|
$
|
70,507
|
|
COMMERCE
ENERGY GROUP, INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS)
—
(Continued)
(Dollars
In Thousands, Except Per Share Amounts)
(Unaudited)
The
Company purchases electricity and natural gas utilizing forward physical
delivery contracts based on the projected usage of its customers.
Stock-Based
Compensation
The
total
compensation cost associated with stock options and restricted stock for
the
three months ended October 31, 2007 was $(9) and $199, respectively, and
for the
three months ended October 31, 2006 were $65 and $69 respectively. These
costs
are included in general and administrative expenses. In October 2007, our
Senior
Vice President and General Counsel resigned from his position and pursuant
to
his separation agreement 10,000 shares of his 60,000 unvested, restricted
stock
was forfeited and cancelled. The remaining 50,000 unvested shares were
accelerated, to vest on January 2, 2008, which incurred additional compensation
cost of $93 through October 31, 2007.
The
fair
value of options granted is estimated on the date of grant using the
Black-Scholes model based on the weighted-average assumptions in the table
below. The assumptions for the expected lives are based on evaluations of
historical and expected future exercise behavior. The risk-free interest
rate is
based on the U.S. Treasury rates at the date of the grant with maturity dates
approximating the expected life at the grant date. The historical volatility
of
the Company’s common stock is used as the basis for the expected
volatility.
|
|
Three
Months Ended
October
31,
|
|
|
|
2007
|
|
|
2006
|
|
Weighted-average
risk-free interest rate
|
|
|
4.5
|
%
|
|
|
4.6
|
%
|
Average
expected life in years
|
|
|
4.15
|
|
|
|
4.63
|
|
Expected
dividends
|
|
None
|
|
|
None
|
|
Expected
volatility
|
|
|
0.71
|
|
|
|
0.75
|
|
A
summary
of option activity under the Company’s 1999 Equity Incentive Plan, or the 1999
Plan, and the Company’s 2006 Stock Incentive Plan, or the SIP, and under certain
individual plans, during the quarter ended October 31, 2007 is presented
below.
|
|
Options
Outstanding
|
|
|
|
Number
of
Shares
(in
Thousands)
|
|
|
Exercise
Price
Per
Share
|
|
|
Weighted
Average
Exercise
Price
|
|
Options
outstanding as of July 31, 2007
|
|
|
6,983
|
|
|
$
|
1.00-$3.75
|
|
|
$
|
2.33
|
|
Options
expired
|
|
|
(757
|
)
|
|
$
|
2.75
|
|
|
$
|
2.75
|
|
Options
forfeited
|
|
|
(45
|
)
|
|
$
|
2.56
|
|
|
$
|
2.56
|
|
Options
outstanding as of October 31, 2007
(1)
|
|
|
6,181
|
|
|
$
|
1.00-$3.75
|
|
|
$
|
2.28
|
|
____________
(1)
|
Options
exercisable and outstanding as of October 31, 2007 were 6,181 with
weighted average exercise price of $2.28 and an aggregate intrinsic
value
of $620.
|
As
of
October 31, 2007, there was no unrecognized compensation cost relating to
non-vested outstanding stock options; all options were vested. The total
unrecognized compensation cost relating to non-vested restricted stock was
$277
and will be recognized over the period of November 2007 through November
2009.
For the three months ended October 31, 2007, no restricted stock was issued.
A
total of 362,000 unvested restricted shares were outstanding as of October
31,
2007, with a total market value of $838. These restricted shares vest in
accordance with the terms of various written agreements. At October 31, 2007,
988,334 shares of the Company’s common stock may be issued pursuant to awards
under the Company’s 2006 Stock Incentive Plan.
Income
Tax
The
Company has
established valuation allowances to reserve its net deferred tax assets due
to
the uncertainty that the Company will realize the related tax benefits in
the
foreseeable future. At October 31, 2007, the Company
COMMERCE
ENERGY GROUP, INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS)—
(Continued)
(Dollars
In Thousands, Except Per Share Amounts)
(Unaudited)
had
net
operating loss carryforwards of approximately $8.5 million and $11.3 million
for
federal and state income tax purposes, respectively.
The
Company adopted the provisions of FIN 48 in August 2007. As of the date of
adoption, the Company had no unrecognized income tax benefits. Accordingly,
the
annual effective tax rate will not be affected by the adoption of FIN 48.
Unrecognized tax benefits are not expected to increase or decrease within
the
next 12 months as a result of the anticipated lapse of an applicable statue
of
limitations. Interest and penalties related to unrecognized income tax benefits
will be accrued in interest expense and operating expense, respectively.
The
Company has not accrued interest or penalties as of the date of adoption
because
they are not applicable.
The
Company may be audited by applicable federal and state taxing authorities
in the
following income tax jurisdictions in which the Company previously filed
or
expects to file income tax returns for the years indicated:
|
Jurisdictions
|
Tax
Years
|
|
Federal
|
2003-2006
|
|
California
|
2002-2006
|
|
Florida
|
2005-2006
|
|
Maryland
|
2003-2006
|
|
Massachusetts
|
2003-2006
|
|
Michigan
|
2002-2006
|
|
Missouri
|
2003-2006
|
|
New
Jersey
|
2002-2006
|
|
New
York
|
2003-2006
|
|
Ohio
|
2003-2006
|
|
Pennsylvania
|
2004-2006
|
|
Texas
|
2002-2006
|
|
Virginia
|
2003-2006
|
|
Wisconsin
|
2006
|
|
Georgia
|
2006
|
|
Kentucky
|
2006
|
|
City
of Philadelphia
|
2003-2006
|
However,
because the Company had net operating losses and credits carried forward
in
several of the jurisdictions including federal and California, certain
items
attributable to closed tax years are still subject to adjustment by applicable
taxing authorities through an adjustment to tax attributes carried forward
to
open years.
Comprehensive
Income (Loss)
Statement
of Financial Accounting Standards No. 130, “Reporting Comprehensive Income,” or
SFAS 130, establishes standards for reporting and displaying comprehensive
income and its components in the Company’s consolidated financial statements.
Comprehensive income is defined in SFAS 130 as the change in equity (net
assets)
of a business enterprise during a period from certain transactions and
other
events and circumstances and is comprised of net income (loss) and other
comprehensive income (loss).
The
components of comprehensive income (loss) are as follows:
|
|
Three
Months Ended
October
31,
|
|
|
|
2007
|
|
|
2006
|
|
Net
income (loss)
|
|
$
|
(1,087
|
)
|
|
$
|
384
|
|
Changes
in fair value of cash flow hedges
|
|
|
788
|
|
|
|
(2,597
|
)
|
Comprehensive
income (loss)
|
|
$
|
(299
|
)
|
|
$
|
(2,213
|
)
|
Accumulated
other comprehensive loss included in stockholders’ equity totaled $35 and $326
at October 31, 2007 and October 31, 2006, respectively.
COMMERCE
ENERGY GROUP, INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS)—
(Continued)
(Dollars
In Thousands, Except Per Share Amounts)
(Unaudited)
Segment
Reporting
The
Company’s chief operating decision makers consist of members of senior
management that work together to allocate resources to, and assess the
performance of, the Company’s business. These members of senior management
currently manage the Company’s business, assess its performance, and allocate
its resources as the single operating segment of energy retailing. As Skipping
Stone, net of inter-company eliminations, accounts for less than 1% of
total net
revenue, and geographic information is not significant, no segment information
is provided.
Accounts
Receivable, Net
Accounts
receivable, net, is comprised of the following:
|
|
October
31,
2007
|
|
|
July
31,
2007
|
|
Billed
|
|
$
|
51,029
|
|
|
$
|
44,693
|
|
Unbilled
|
|
|
22,967
|
|
|
|
24,963
|
|
|
|
|
73,996
|
|
|
|
69,656
|
|
Less
allowance for doubtful accounts
|
|
|
(8,046
|
)
|
|
|
(4,425
|
)
|
Accounts
receivable, net
|
|
$
|
65,950
|
|
|
$
|
65,231
|
|
Inventory
Inventory
consists of natural gas in storage as required by state regulators and
contracted obligations under customer choice programs. Inventory is stated
at
the lower of weighted average cost or market.
Adoption
of New Accounting Pronouncements
In
June
2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes”, an
interpretation of SFAS No. 109, “Accounting for Income Taxes”. The
interpretation contains a two-step approach to recognizing and measuring
uncertain tax positions accounted for in accordance with SFAS No. 109. The
Company adopted FIN 48 during the first quarter of fiscal year 2008, and
the
adoption had no impact on its financial statements.
New
Accounting Standards
In
February 2007, the FASB issued SFAS No. 159, “The Fair Value Option
forFinancial Assets and Financial Liabilities Including an Amendment of FASB
StatementNo. 115”. SFAS No. 159 permits entities to choose to
measure many financial instruments and certain other items at fair value
that
are not currently required to be measured at fair value. This statement also
establishes presentation and disclosure requirements designed to facilitate
comparisons between entities that choose different measurement attributes
for
similar types of assets and liabilities. SFAS No. 159 is effective for
fiscal years beginning after November 15, 2007. The Company is evaluating
the impact this statement may have on its financial statements.
In
September 2006, the FASB issued SFAS No. 157, “Fair Value
Measurements”, which provides guidance for using fair value to measure assets
and liabilities. The pronouncement clarifies (1) the extent to which
companies measure assets and liabilities at fair value; (2) the information
used to measure fair value; and (3) the effect that fair value measurements
have on earnings. SFAS No. 157 will apply whenever another standard
requires (or permits) assets or liabilities to be measured at fair value.
SFAS No. 157 is effective for fiscal years beginning after
November 15, 2007. The Company is evaluating the impact this statement will
have on its financial statements.
Note
2. Liquidity
Based
on
current cash flow estimates, the Company has alerted its Credit Facility
Lender
that it may, during the current quarter, seek a temporary waiver of certain
conditions contained in the credit facility, similar to concessions previously
obtained on a temporary basis. This waiver would likely take the form of
eliminating or reducing temporarily the required excess availability of
$2.5
million and possibly other concessions. There is no assurance that such a
waiver, if needed, will be granted.
The
Company expects needing to add to its capital resources in fiscal
2008: (1) to meet the credit facility requirement to have $10 million in
excess
availability at all times on and after July 1, 2008, and (2) if the Company
expands its business, either from internal growth or acquisition, if energy
prices increase materially, or if energy industry volatility and/or uncertainty
create additional credit requirements.
Note
3. Basic and Diluted Income (Loss) per Common Share
Basic
income (loss) per common share was computed by dividing net income (loss)
available to common stockholders, by the weighted average number of common
shares outstanding during the period. Diluted income per common share reflects
the potential dilution that would occur if all outstanding options or other
contracts to issue common stock were exercised or converted, and was computed
by
dividing net income (loss) by the weighted average number of common shares
plus
dilutive common equivalent shares outstanding, unless they were
anti-dilutive.
COMMERCE
ENERGY GROUP, INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS)—
(Continued)
(Dollars
In Thousands, Except Per Share Amounts)
(Unaudited)
The
following is a reconciliation of the numerator, income (loss), and the
denominator, (common shares in thousands), used in the computation of basic
and
diluted income (loss) per common share:
|
|
Three
Months
Ended
October
31,
|
|
|
|
2007
|
|
|
2006
|
|
Numerator:
|
|
|
|
|
|
|
Net
income (loss)
|
|
$
|
(1,087
|
)
|
|
$
|
384
|
|
Net
income (loss) applicable to common stock —basic and
diluted
|
|
$
|
(1,087
|
)
|
|
$
|
384
|
|
|
|
|
|
|
|
|
|
|
Denominator:
|
|
|
|
|
|
|
|
|
Weighted-average
outstanding common shares — basic
|
|
|
30,380
|
|
|
|
29,639
|
|
Effect
of stock options
|
|
|
—
|
|
|
|
26
|
|
Weighted-average
outstanding common shares — diluted
|
|
|
30,380
|
|
|
|
29,665
|
|
Note
4. Market and Regulatory
The
Company currently serves electricity customers in six states across 12 utility
markets and gas customers in seven states across 13 utility markets and
collectively operates in nine states with authority to operate in an additional
four states. Regulatory requirements are determined at the individual state
level and administered and monitored by the Public Utility Commission, or
PUC,
of each state. Operating rules and tariff filings by states and by utility
markets can significantly impact the viability of the Company’s sales and
marketing plans and its overall operating and financial results.
Note
5. HESCO Customer Acquisition
Effective
September 1, 2006, the Company acquired from Houston Energy Services
Company, L.L.C., or HESCO certain assets consisting principally of contracts
with end-use customers in California, Florida, Nevada, Kentucky and Texas
consuming approximately 12 billion cubic feet of natural gas annually. The
acquisition price of approximately $4.1 million in cash and
$0.2 million in assumption of liabilities was allocated to customer
contracts and is being amortized over an estimated life of four
years.
Note
6. Contingencies
APX
Settlement
During
2000 and 2001, we bought, sold and scheduled power in the California wholesale
energy markets through the markets and services of APX, Inc., or APX. As
a
result of a complaint filed at the Federal Energy Regulatory Commission,
or
FERC, by San Diego Gas & Electric Co. in August 2000 and a line of
subsequent FERC orders, we became involved in proceedings at FERC related
to
sales and schedules in the California Power Exchange, or CPX, and the California
Independent System Operator, or CAISO, markets. We refer to these proceedings
as
the California Refund Cases. The APX Settlement, described below, is a part
of
that proceeding relating to APX’s involvement in those markets.
On
January 5, 2007, APX, we and certain other parties signed an APX Settlement
and Release of Claims Agreement, or the APX Settlement Agreement, which among
other things, established a mechanism for allocating refunds owed to APX
and
resolved certain other matters and claims related to APX’s participation in the
PX and CAISO centralized spot markets for wholesale electricity from May 1,
2000 through June 20, 2001. Under the APX Settlement Agreement, Commerce
and certain other parties were entitled to receive payments from APX, with
Commerce expected to receive up to approximately $6.5 million. In April
2007, we received a payment of $5.1 million and in August 2007 we received
the remaining settlement payment of $1.4 million.
COMMERCE
ENERGY GROUP, INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS)—
(Continued)
(Dollars
In Thousands, Except Per Share Amounts)
(Unaudited)
Certain
other aspects of the California Refund Case which may affect the Company
remain
pending. The Company cannot at this time predict whether, or to what extent,
these proceedings will have an impact on the Company’s financial
results.
Note
7. Derivative Financial Instruments
The
Company purchases substantially all of its power and natural gas utilizing
forward physical delivery contracts. These physical delivery contracts are
defined as commodity derivative contracts under Statement of Financial
Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging
Activities” (“SFAS 133”). Using the exemption available for qualifying contracts
under SFAS No. 133, the Company applies the normal purchase and normal sale
accounting treatment to its forward physical delivery contracts. Accordingly,
the Company records revenue generated from customer sales as energy is delivered
to retail customers and the related energy under the forward physical delivery
contracts is recorded as direct energy costs when received from
suppliers.
For
forward or future contracts that do not meet the qualifying criteria for
normal
purchase, normal sale accounting treatment, the Company elects cash flow
hedge
accounting, where appropriate. Under cash flow hedge accounting, the fair
value
of the contract is recorded as a current or long-term derivative asset or
liability. Subsequent changes in the fair value of the derivative assets
and
liabilities are recorded on a net basis in Accumulated other comprehensive
income (loss) (“OCI”), and reflected as direct energy cost in the statement of
operations as the related energy is delivered.
The
amounts recorded in Accumulated OCI at October 31, 2007 and July 31, 2007
related to cash flow hedges are summarized in the following table:
|
|
October
31,
2007
|
|
|
July
31,
2007
|
|
Current
assets
|
|
$
|
251
|
|
|
$
|
—
|
|
Current
liabilities
|
|
|
(286
|
)
|
|
|
(671
|
)
|
Deferred
gains/(losses)
|
|
|
—
|
|
|
|
(152
|
)
|
Hedge
ineffectiveness
|
|
|
—
|
|
|
|
—
|
|
Accumulated
other comprehensive income
|
|
$
|
(35
|
)
|
|
$
|
(823
|
)
|
Certain
financial derivative instruments (such as swaps, options and futures),
designated as fair-value hedges, economic hedges or as speculative, do not
qualify or meet the requirements for normal purchase, normal sale accounting
treatment or cash flow hedge accounting and are recorded currently in operating
income (loss) and as a current or long-term derivative asset or liability
depending on their term. The subsequent changes in the fair value of these
contracts may result in operating income (loss) volatility as the fair value
of
the changes are recorded on a net basis in direct energy cost in the
consolidated statement of operations for each fiscal period. For the three
months ending October 31, 2007, the impact of financial derivatives accounted
for as mark-to-market resulted in an expense of $17, and resulted mostly
from
economic hedging related to the Company’s natural gas portfolio. The notional
value of all derivatives accounted for as mark-to-market which was outstanding
at October 31, 2007 was $4,284.
As
of
October 31, 2007, the Company had $251 of derivative assets included in Prepaid
expenses and other, and $286 of total derivative liabilities included in
Accrued
liabilities.
Note
8. Credit Facility
and Supply Agreements
Wachovia
Capital Finance Corporation (Western)
In
June 2006, Commerce
and Commerce Energy entered into a Loan and Security Agreement, or the Credit
Facility, with Wachovia Capital Finance Corporation (Western), or the Agent,
for
up to $50 million. The three-year Credit Facility is secured by
substantially all of the Company’s assets and provides for issuance of letters
of credit and for revolving credit loans, which we may use for working capital
and general corporate purposes. The availability of letters of credit and
loans
under the Credit Facility is limited by a calculated borrowing base consisting
of the majority of the Company’s cash on deposit with the Agent and the
Company’s receivables and natural gas inventories. As of October 31, 2007,
letters of credit issued under the facility totaled $11.6 million,
and
COMMERCE
ENERGY GROUP, INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS)—
(Continued)
(Dollars
In Thousands, Except Per Share Amounts)
(Unaudited)
outstanding
borrowings were $12.4 million. Fees for letters of credit issued range
from 1.50
to 1.75 percent per annum, depending on the level of Excess Availability,
as defined in the Credit Facility. We also pay an unused line fee equal
to
0.375 percent of the unutilized credit line. Generally, outstanding
borrowings under the Credit Facility are priced at a domestic bank rate
plus
0.25 percent or LIBOR plus
2.75 percent.
The
Credit Facility contains typical covenants, subject to specific exceptions,
restricting Commerce, the Company and its subsidiaries from: (i) incurring
additional indebtedness; (ii) granting certain liens; (iii) disposing
of certain assets; (iv) making certain restricted payments;
(v) entering into certain other agreements; and (vi) making certain
investments. The Company was also required to maintain a minimum of
$10 million of Eligible Cash Collateral, at all times.
From
September 2006 through September 2007, the Company and Commerce Energy have
entered into five amendments and a modification to the Loan and Security
Agreement with the Agent and Lenders, several of which involved waivers of
prior
or existing instances of covenant non-compliance relating to the maintenance
of
Eligible Cash Collateral, capital expenditures and notification requirements
(First Amendment), maintenance and deferral of prospective compliance, of
minimum Fixed Charge Coverage Rates and maintenance of the minimum Excess
Availability Ratio (Second and Third Amendments). In addition, in the First
Amendment, the Agent and Lender agreed to certain prospective waivers of
covenants in the Credit Facility to enable Commerce Energy to consummate
the
HESCO acquisition of customers. In the Fourth Amendment, the amount allowable
under the Credit Facility’s capital expenditures covenant was increased to
$6.0 million. In the Second, Third and Fifth Amendment and in the
Modification Agreement, each addressed reducing and/or restructuring the
Excess
Availability covenant in the Credit Facility to accommodate Commerce Energy’s
business. In the Modification Agreement, the Agent and the Lenders also
permitted Commerce Energy for a period from September 20, 2007 to
October 5, 2007 to exceed its Gross Borrowing Base, as defined in the
Agreement.
The
Sixth
Amendment, executed on November 16, 2007, adjusted the required excess
availability required at all times to $2.5 million until July 1, 2008 at
which
time it becomes and remains $10 million. It also eliminated the Eligible
Cash
Collateral covenant which required keeping $10 million cash on
deposit. In connection with elimination of the Eligible Cash
Collateral covenant, the Sixth Amendment revised the Fixed Charge Coverage
Ratio
and added minimum EBITDA requirements. The Sixth Amendment also
extended the maturity of the Credit Facility from June 8, 2009 to June 8,
2010.
At
October 31, 2007, the Company had approximately $2.5 million of remaining
availability under our Credit Facility, As it is industry practice to pay
energy
bills towards the end of the month, the remaining availability at the end
of a month is lower than most other times during a month.
Tenaska
Power Services Co.
In
August
2005, the Company entered into several agreements with Tenaska Power Services
Co., or Tenaska, for the supply of the majority of Commerce’s wholesale
electricity supply needs in Texas, utilizing commercially standard master
purchase and sale, a lockbox control, security and guaranty agreements. The
Company’s Texas customers pay into a designated account that is used to pay
Tenaska for the electricity. Tenaska also extends credit to the Company to
buy
wholesale electricity supply secured by funds pledged by the Company in the
lockbox, its related accounts receivables and customers contracts. The Company
entered into a guaranty agreement, pursuant to which it, as the parent company
of Commerce, unconditionally guaranteed to Tenaska full and prompt payment
of
all indebtedness and obligations owed to Tenaska. At October 31, 2007, Tenaska
had extended approximately $14.8 million of trade credit to the Company.
Tenaska
also serves as the Company’s exclusive provider of qualified scheduling services
and marketing services in the region of Texas administered by the Electric
Reliability Council of Texas.
Pacific
Summit Energy LLC
In
September 2006, the
Company entered into several agreements with Pacific Summit LLC, or Pacific
Summit, for the supply of natural gas to serve end-use customers that we
acquired in connection with the HESCO acquisition, utilizing operating, a
lockbox control and security agreements. Under the agreements, these customers
remit their
COMMERCE
ENERGY GROUP, INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS)—
(Continued)
(Dollars
In Thousands, Except Per Share Amounts)
(Unaudited)
payments
into the lockbox used to pay Pacific Summit for natural gas supplies. Pacific
Summit also extends credit to the Company to buy wholesale natural gas
supplies,
secured by funds pledged by the Company in the lockbox, its related accounts
receivable and a $3.5 million letter of credit. At October 31, 2007,
Pacific Summit had extended approximately $9.5 million of trade credit to
the Company under this arrangement.
Note
9. Subsequent Events
Lawrence
Clayton, Jr.
On
November 28, 2007, the Company entered into a Settlement Agreement with Lawrence
Clayton, Jr., the former Senior Vice President, Chief Financial Officer and
Secretary of the Company on November 29, 2007 (the “Settlement Agreement”),
which became effective on December 7, 2007, the eighth day after it was
executed. The Settlement Agreement provides for the Company to make a lump-sum
settlement payment to Mr. Clayton of $400,000 on January 2, 2008. Of the
aggregate amount of the settlement payment, all but $120,000 was covered
by
insurance. Each party to the Settlement Agreement agreed to mutual general
releases of all claims that the parties may have against each
other.
Item
2.
Management’s Discussion and Analysis of Financial
Condition and Results
of
Operations.
As
used herein and unless the context requires otherwise, references to
the “Company,” “we,” “us,” and “our” refer specifically to Commerce
Energy
Group, Inc. and its subsidiaries. “Commerce” refers to Commerce
Energy, Inc.,
our principal operating subsidiary. This discussion and
analysis should be read
in conjunction with Management’s Discussion and
Analysis of Financial Condition
and Results of Operations set forth in
our Annual Report on Form 10-K for the year ended July 31, 2007, or the Form
10-K.
Some
of the statements in this quarterly report on Form 10-Q are forward-looking
statements
regarding our assumptions, projections, expectations,
targets, intentions or
beliefs about future events which involve risks
and uncertainties. All
statements other than statements of historical
facts included in this Item 2
relating to expectation of future
financial performance, continued growth,
changes in economic conditions
or capital markets and changes in customer usage
patterns and
preferences, are forward-looking statements. In some cases, you
can
identify forward-looking statements by terms such as “may,”
“will,”
“should,” “expect,” “plan,” “intend,” “forecast,” “anticipate,”
“believe,”
“estimate,” “predict,” “potential,” “continue” or the
negative of these terms
or other comparable terms. The forward-looking
statements contained in this
quarterly report on Form 10-Q involve
known and unknown risks and uncertainties and situations that
may cause
our or our industry’s actual results, level of activity, performance
or
achievements to be materially different from any future results, levels of
activity, performance or achievements expressed or implied by these
statements.
Factors that might cause actual events or results to differ
materially from
those indicated by these forward-looking statements may
include the matters
listed under “Risk Factors” in Item 1A in the Form
10-K and elsewhere in this
Form 10-Q, including, without limitation,
changes in general economic
conditions in the markets in which we may
compete; fluctuations in the market
price of energy which may negatively
impact the competitiveness of our product
offerings to current and
future customers; decisions by our energy suppliers requiring us to post
additional collateral for our energy purchases;
uncertainties
in the capital markets should we seek to raise additional capital; uncertainties
relating to federal and state proceedings regarding issues emanating from
the
2000-2001 California energy crisis, including any resulting federal, state,
or
administrative legal proceedings which could effect us;
increased
competition; our ability
to retain key members of management; our
ability to address changes in laws and
regulations; our ability to
successfully integrate businesses or customer
portfolios that we may
acquire; our ability to obtain and retain credit
necessary to
profitably support our operations; adverse state or federal
legislation
or regulation or adverse determinations by regulators; and other
factors identified from time to time in our filings with the Securities
and
Exchange Commission, or the SEC. We caution that, while we make
such statements
in good faith and we believe such statements are based
on reasonable
assumptions, including, without limitation, management’s
examination of
historical operating trends, data contained in records
and other data available
from third parties, we cannot assure you that
our expectations will be
realized.
Any
forward-looking statement speaks only as of the date on which such
statement is made, and, except as required by law, we undertake
no
obligation
to update any forward-looking statement to reflect events or
circumstances
after the date on which such statement is made or to
reflect the occurrence of
unanticipated events. New factors emerge from
time to time, and it is not
possible for management to predict all such
factors.
Our
Company
We
are an
independent marketer of retail electricity and natural gas to residential,
commercial, industrial and institutional end-use customers. Commerce is licensed
by the Federal Energy Regulatory Commission, or FERC, and by state regulatory
agencies as an unregulated retail marketer of electricity and natural
gas.
We
were
founded in 1997 as a retail electricity marketer in California. As of October
31, 2007, we delivered electricity to approximately 135,000 customers in
California, Maryland, Michigan, New Jersey, Pennsylvania and Texas; and natural
gas to approximately 59,000 customers in California, Florida, Georgia, Maryland,
Nevada, Ohio and Pennsylvania.
The
electricity and natural gas we sell to our customers is purchased from
third-party suppliers under both short-term and long-term contracts. We do
not
own electricity generation or delivery facilities, natural gas producing
properties or pipelines. The electricity and natural gas we sell is generally
metered and always delivered to our customers by the local utilities. The
local
utilities also provide billing and collection services for many of our customers
on our behalf. Additionally, to facilitate load shaping and demand balancing
for
our customers, we buy and sell surplus electricity and natural gas from and
to
other market participants when necessary. We utilize third-party facilities
for
the storage of our natural gas.
The
growth of our business depends upon a number of factors, including the degree
of
deregulation in each state, our ability to acquire new and retain existing
customers and our ability to acquire energy for our customers at competitive
prices and on reasonable credit terms.
Significant
Customer Acquisitions
HESCO
Acquisition
In
September 2006, the Company acquired from Houston Energy Services Company,
L.L.C., or HESCO certain assets consisting principally of contracts with
end-use
customers in California, Florida, Nevada, Kentucky and Texas consuming
approximately 12 billion cubic feet of natural gas annually. The
acquisition price of approximately $4.1 million in cash and
$0.2 million in assumption of liabilities was allocated to customer
contracts and is being amortized over an estimated life of four
years.
Market
and Regulatory
The
Company currently serves electricity customers in six states across 12 utility
markets and gas customers in seven states across 13 utility markets and
collectively operates in nine states with authority to operate in an additional
four states. Regulatory requirements are determined at the individual state
level and administered and monitored by the Public Utility Commission, or
PUC,
of each state. Operating rules and tariff filings by states and by utility
markets can significantly impact the viability of the Company’s sales and
marketing plans and its overall operating and financial results.
Results
of Operations
Three
Months Ended October 31, 2007 Compared to Three Months Ended October 31,
2006
The
following table summarizes the results of our operations for the three months
ended October 31, 2007 and 2006 (dollars in thousands):
|
|
Three
Months Ended October
31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
Dollars
|
|
|
%
Revenue
|
|
|
Dollars
|
|
|
%
Revenue
|
|
Retail
electricity sales
|
|
$
|
84,225
|
|
|
|
80
|
%
|
|
$
|
53,407
|
|
|
|
76
|
%
|
Natural
gas sales
|
|
|
21,372
|
|
|
|
20
|
%
|
|
|
15,664
|
|
|
|
22
|
%
|
Excess
electricity sales
(1)
|
|
|
—
|
|
|
|
—
|
|
|
|
1,436
|
|
|
|
2
|
%
|
Net
revenue
|
|
|
105,597
|
|
|
|
100
|
%
|
|
|
70,507
|
|
|
|
100
|
%
|
Direct
energy costs
|
|
|
89,209
|
|
|
|
84
|
%
|
|
|
60,451
|
|
|
|
86
|
%
|
Gross
profit
|
|
|
16,388
|
|
|
|
16
|
%
|
|
|
10,056
|
|
|
|
14
|
%
|
Selling
and marketing expenses
|
|
|
3,932
|
|
|
|
4
|
%
|
|
|
2,235
|
|
|
|
3
|
%
|
General
and administrative expenses
|
|
|
13,460
|
|
|
|
13
|
%
|
|
|
7,849
|
|
|
|
11
|
%
|
Loss
from operations
|
|
$
|
(1,004
|
)
|
|
|
(1
|
)%
|
|
$
|
(28
|
)
|
|
|
—
|
|
(1)
Electricity
supply greater than retail electricity demand which is sold back into the
wholesale market.
Net
revenue
The
following table summarizes net revenues for the three months ended October
31,
2007 and 2006 (dollars in thousands):
|
|
Three
Months Ended October
31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
Dollars
|
|
|
%
Revenue
|
|
|
Dollars
|
|
|
%
Revenue
|
|
Retail
Electricity Sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
Texas
|
|
$
|
48,191
|
|
|
|
46
|
%
|
|
$
|
16,730
|
|
|
|
24
|
%
|
California
|
|
|
13,387
|
|
|
|
13
|
%
|
|
|
17,283
|
|
|
|
25
|
%
|
Pennsylvania/New
Jersey
|
|
|
12,984
|
|
|
|
12
|
%
|
|
|
14,214
|
|
|
|
20
|
%
|
Maryland
|
|
|
7,965
|
|
|
|
7
|
%
|
|
|
1,489
|
|
|
|
2
|
%
|
Michigan
and Others
|
|
|
1,698
|
|
|
|
2
|
%
|
|
|
3,691
|
|
|
|
5
|
%
|
Total
Retail Electricity Sales
|
|
|
84,225
|
|
|
|
80
|
%
|
|
|
53,407
|
|
|
|
76
|
%
|
Natural
Gas Sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
HESCO
Customers
|
|
|
14,569
|
|
|
|
14
|
%
|
|
|
7,257
|
|
|
|
10
|
%
|
California
|
|
|
3,334
|
|
|
|
3
|
%
|
|
|
4,022
|
|
|
|
6
|
%
|
Ohio
|
|
|
3,278
|
|
|
|
3
|
%
|
|
|
3,004
|
|
|
|
4
|
%
|
Georgia
|
|
|
36
|
|
|
|
—
|
|
|
|
987
|
|
|
|
1
|
%
|
All
Others
|
|
|
155
|
|
|
|
—
|
|
|
|
394
|
|
|
|
1
|
%
|
Total
Natural Gas Sales
|
|
|
21,372
|
|
|
|
20
|
%
|
|
|
15,664
|
|
|
|
22
|
%
|
Excess
Electricity Sales
|
|
|
—
|
|
|
|
—
|
|
|
|
1,436
|
|
|
|
2
|
%
|
Net
Revenue
|
|
$
|
105,597
|
|
|
|
100
|
%
|
|
$
|
70,507
|
|
|
|
100
|
%
|
Net
revenues increased $35.1 million, or 49.8%, to $105.6 million for the three
months ended October 31, 2007 from $70.5 million for the three months ended
October 31, 2006. The increase in net revenues was driven primarily by a
57.7%
increase in electricity sales and a 36.4% increase in natural gas sales.
Higher
retail electricity sales reflects the impact of a 224% and a 385% increase
in
sales volumes in Texas and Maryland, respectively, due to customer growth
that
was partly offset by lower retail sales in the California and Michigan markets
resulting from customer attrition. Higher natural gas sales reflect the impact
of a full quarter of HESCO customers, which were acquired in September
2006.
Retail
electricity sales increased $30.8 million to $84.2 million for the three
months
ended October 31, 2007, from $53.4 million for the three months ended October
31, 2006, reflecting the impact of a 56% increase in sales volume. For the
three
months ended October 31, 2007, we sold 716 million kilowatt hours, or kWh,
at an
average retail price per kWh of $0.118, as compared to 458 million kWh sold
at
an average retail price per kWh of $0.117 for the three months ended October
31,
2006.
Natural
gas sales increased $5.7 million to $21.4 million for the three months ended
October 31, 2007 from $15.7 million for the three months ended October 31,
2006
reflecting the impact of a 36% increase in sales volumes, partly offset by
a
4.7% decline in average retail sales prices. For the three months ended October
31, 2007, we sold 3.0 million dekatherms, or DTH, at an average retail price
per
DTH of $7.11, as compared to 2.1 million DTH, sold at an average retail price
per DTH of $7.46 during three months ended October 31, 2006. For the three
months ended October 31, 2007, sales to the commercial and industrial natural
gas customers acquired in September 2006 totaled $14.6 million on sales volume
of 2.2 million DTH at an average sales price of $6.64 per DTH.
We
had
approximately 194,000 electricity and natural gas customers at October 31,
2007,
an increase of 21% from 161,000 at October 31, 2006. We had approximately
135,000 electricity and 59,000 natural gas customers at October 31, 2007,
as
compared to 95,000 and 66,000 at October 31, 2006. A gross increase of
approximately 90,000 electricity customers in Texas and Maryland more than
offset high customer attrition in our Pennsylvania/New Jersey and Michigan
markets; an increase of approximately 30,000 natural gas customers in our
Ohio
markets offset customer attrition in other natural gas markets. Attrition
in our
retail customer base largely results from the impact of increased sales prices
to our customers resulting from our passing on higher wholesale energy and
transmission costs to our customers without the incumbent utility passing
on
corresponding price increases to their customers. This competitive imbalance
is
created as a result of a lack of market responsive ratemaking and a lagging
regulatory approval process.
Direct
Energy Costs
Direct
energy costs, which are recognized concurrently with related energy sales,
include the commodity cost of natural gas and electricity, electricity
transmission costs from the Independent Systems Operators, or ISOs,
transportation costs from local distribution companies, or LDCs and pipelines,
other fees and costs incurred from various energy-related service providers
and
energy-related taxes that cannot be passed directly through to the
customer.
Direct
energy costs for the three months ended October 31, 2007 totaled $69.2 million
and $20.0 million for electricity and natural gas, respectively, compared
to
$46.5 million and $13.9 million, respectively, for the three months ended
October 31, 2006. Electricity costs averaged $0.097 per kWh for the three
months
ended October 31, 2007 compared to $0.102 per kWh for the three months ended
October 31, 2006. Direct energy costs for natural gas averaged $6.66 per
DTH for
the three months ended October 31, 2007 as compared to $6.62 per DTH for
the
three months ended October 31, 2006.
Gross
Profit
Gross
profit increased $6.3 million, or 63.0% to $16.4 million for the three months
ended October 31, 2007 from $10.1 million for the three months ended October
31,
2006. Gross profit from electricity increased $6.6 million to $15.0 million
for
the three months ended October 31, 2007 from $8.4 million for the three months
ended October 31, 2006, reflecting the impact of customer growth in Texas
and
Maryland. Gross profit from natural gas decreased $0.3 million to $1.4 million
for the three months ended October 31, 2007, from $1.7 million for the three
months ended October 31, 2006 primarily due to the impact of much lower margins
relating to the HESCO customers due to unusually high transportation charges,
primarily in Florida.
Selling
and Marketing Expenses
Selling
and marketing expenses increased to $3.9 million for the three months ended
October 31, 2007 from $2.2 million for the three months ended October 31,
2006,
reflecting the impact of higher telemarketing, third-party commissions and
direct mail costs related to the Company’s increased customer acquisition
initiatives, and an increase in personnel and consultants to support these
initiatives.
General
and Administrative Expenses
General
and administrative expenses increased to $13.5 million for the three months
ended October 31, 2007 from $7.8 million for the three months ended October
31,
2006. Of the $5.7 million increase, $2.8 million was attributable to an increase
in the bad debt provision, primarily a result of the rapid growth in revenue
in
Texas from $10.3 million to $47.6 million, respectively. In addition, regulatory
changes in Texas surrounding customer credit checking procedures, customer
disconnection processes and billing delays led to an increase in receivable
balances and delinquency at quarter end. The remaining $2.9 million was
attributable to an increase in personnel costs relating to higher customer
service and information technology staff to support increased customer
acquisition initiatives, an increase in professional service fees resulting
from
the Company’s review of its strategic alternatives, and depreciation and
amortization expenses.
Income
Taxes
No
provision for, or benefit from, income taxes was recorded for the three months
ended October 31, 2007 or the three months ended 2006. We provided valuation
allowances equal to our calculated tax due to the amount of the Company’s net
operating loss carryforwards and the related uncertainty that we would realize
these tax benefits in the foreseeable future. At October 31, 2007, the Company
had net operating loss carryforwards of approximately $8.5 million and $11.3
million for federal and state income tax purposes, respectively.
The
Company adopted the provisions of FIN 48 in August 2007; however, this
implementation had no impact on the Company’s financial statements.
Liquidity
and Capital Resources
The
following table summarizes our liquidity measures:
|
|
(Dollars
in
Thousands
)
|
|
|
|
October
31, 2007
|
|
|
July
31, 2007
|
|
Cash
and cash equivalents
|
|
$
|
5,442
|
|
|
$
|
6,559
|
|
Short-term
borrowings
|
|
$
|
12,400
|
|
|
|
—
|
|
Working
capital
|
|
$
|
39,342
|
|
|
$
|
38,863
|
|
Current
ratio (current assets to current liabilities)
|
|
1.8:1.0
|
|
|
1.8:1.0
|
|
Restricted
cash
|
|
$
|
10,104
|
|
|
$
|
10,457
|
|
Letters
of credit outstanding
|
|
$
|
11,609
|
|
|
$
|
19,334
|
|
Consolidated
Cash Flows
The
following table summarizes our statements of cash flows for the three months
ended October 31, 2007 and 2006 (in thousands):
|
|
Three
Months Ended
|
|
|
|
October
31, 2007
|
|
|
October
31, 2006
|
|
Net
cash provided by (used in):
|
|
|
|
|
|
|
Operating
activities
|
|
$
|
(13,018
|
)
|
|
$
|
(9,488
|
)
|
Investing
activities
|
|
|
(852
|
)
|
|
|
(5,747
|
)
|
Financing
activities
|
|
|
12,753
|
|
|
|
380
|
|
Net
decrease in cash and cash equivalents
|
|
$
|
(1,117
|
)
|
|
$
|
(14,855
|
)
|
Our
principal sources of liquidity to fund ongoing operations have been existing
cash and cash equivalents on hand, cash generated from operations, our credit
facility and credit extended by our suppliers (both secured and unsecured).
Based on our current cash flow estimates, we have alerted
our
Credit Facility Lender that we may, during the current quarter, seek a temporary
waiver of certain conditions contained in our credit facility, similar to
concessions previously obtained on a temporary basis. This waiver would likely
take the form of eliminating or reducing temporarily the required excess
availability of $2.5 million and possibly other concessions.
We
expect
to need to add to our capital resources in fiscal 2008: (1) to meet the credit
facility requirement to have $10 million in excess availability at all times
on
and after July 1, 2008, and (2) if we expand our business, either from internal
growth or acquisition, if energy prices increase materially, or if energy
industry volatility and/or uncertainty create additional credit
requirements.
Cash
used
in operating activities for the three months ended October 31, 2007 was
$13.0 million, compared to cash used in operations of $9.5 million in
the three months ended October 31, 2006. For the three months ended October
31,
2007, cash used in operating activities was comprised primarily of a net
loss of
$1.1 million, increases in accounts receivable, net of $0.7 million
(including a provision of $3.7 million for bad debts); inventory of $3.5
million
and a decrease in accounts payable of $6.9 million. The larger changes in
accounts payable and inventory were primarily due to seasonality as higher
summer power supply costs declined going into the fall months and inventories
were building in anticipation of the winter heating season. For the three
months
ended October 31, 2006, cash used in operating activities was comprised
primarily of increases in accounts receivable of $6.9 million (net of
provision for bad debts of $0.9 million) primarily due to the HESCO customer
list acquisition, a seasonal increase in inventory of $2.7 million, and a
seasonal decrease in accounts payable of $3.3 million. This was offset by
an
increase of $2.4 million in accrued liabilities and other.
Cash
used
in investing activities was $0.9 million for the three months ended October
31, 2007, compared to $5.7 million used in investing activities in the
three months ended October 31, 2006. The cash used in investing activities
for
the three months ended October 31, 2007 was spent for the upgrades in our
key
customer billing, risk management and customer contact platforms. The cash
used
in the three months ended October 31, 2006 was primarily for upgrades in
the
previously discussed platforms and for the purchase of the HESCO customer
list
for $4.2 million.
Cash
provided by
financing activities for the three months ended October 31, 2007 was
$12.8 million, an increase of $12.4 million in short-term borrowings under
our credit facility, compared to $0.4 provided by financing activities for
the
three months ended October 31, 2006. The increase in borrowings was used
to fund
operations in
the
three
months ended October 31, 2007; during the three months ended October 31,
2006,
we funded operations with available cash.
At
October 31, 2007, the Company had approximately $2.5 million of remaining
availability under our credit facility. As it is industry practice to pay
energy bills toward the end of the month, the remaining availability at the
end
of a month is lower than most other times during a month.
Credit
terms from our suppliers may require us to post collateral against our energy
purchases and against our mark-to-market exposure with them. As of
October 31, 2007, we had $10.1 million in restricted cash primarily in
connection with a $10 million requirement of our credit facility. This cash
was released in the Sixth Amendment to the credit facility discussed below.
We
also have $5.7 million in deposits pledged as collateral to our energy
suppliers in connection with energy purchase agreements.
As
of
October 31, 2007, cash and cash equivalents decreased to $5.4 million
compared with $6.5 million at July 31, 2007. This decrease of
$1.1 million was used primarily to fund seasonal inventory growth.
Restricted cash and cash equivalents at October 31, 2007 was
$15.5 million, compared to $17.0 million at July 31, 2007, for a
decrease of $1.5 million for the same reason.
Credit
Facility
In
June
2006, the Company entered into a Loan and Security Agreement, or the
Credit Facility, with Wachovia Capital Finance Corporation (Western), or
the
Agent, for up to $50 million. The three-year Credit Facility is secured by
substantially all of the Company’s assets and provides for issuance of letters
of credit and for revolving credit loans, which we may use for working capital
and general corporate purposes. The availability of letters of credit and
loans
under the Credit Facility is limited by a calculated borrowing base consisting
of the majority of the Company’s cash on deposit with the Agent and the
Company’s receivables and natural gas inventories. As of October 31, 2007,
letters of credit issued under the Credit Facility totaled $11.6 million,
and outstanding borrowings were $12.4 million. At October 31, 2007, the Company
had approximately $5.0 million of remaining availability under our credit
facility, using the amended provisions from the Sixth Amendment, as discussed
below. As it is industry practice to pay energy bills toward the end of the
month, the remaining availability at the end of a month is lower than most
other
times during a month. Fees for letters of credit issued range from 1.50 to
1.75 percent per annum, depending on the level of Excess Availability, as
defined in the Credit Facility. We also pay an unused line fee equal to
0.375 percent of the unutilized credit line. Generally, outstanding
borrowings under the Credit Facility are priced at a domestic bank rate plus
0.25 percent or LIBOR plus 2.75 percent.
The
Credit Facility contains covenants, subject to specific exceptions,
restricting the Company from: (i) incurring additional
indebtedness; (ii) granting certain liens; (iii) disposing of certain
assets; (iv) making certain restricted payments; (v) entering into
certain other agreements; and (vi) making certain investments. The Credit
Facility also restricts our ability to pay cash dividends on our common stock.
We were also required to maintain a minimum of $10 million of Eligible Cash
Collateral, as defined in the Credit Facility, at all times.
From
September 2006 through September 2007, the Company has entered
into five amendments and a modification to the Loan and Security Agreement
with
the Agent, several of which involved waivers of prior or existing instances
of
covenant non-compliance relating to the maintenance of Eligible Cash Collateral,
capital expenditures and notification requirements (First Amendment),
maintenance and deferral of prospective compliance, of minimum Fixed Charge
Coverage Rates and maintenance of the minimum Excess Availability Ratio (Second
and Third Amendments). In addition, in the First Amendment, the Agent and
Lender
agreed to certain prospective waivers of covenants in the Credit Facility
to
enable Commerce to consummate the HESCO acquisition of customers. In the
Fourth
Amendment, the amount allowable under the Credit Facility’s capital expenditures
covenant was increased to $6.0 million. In the Second, Third and Fifth
Amendment and in the Modification Agreement, each addressed reducing and/or
restructuring the Excess Availability covenant in the Credit Facility to
accommodate Commerce’s business. In the Modification Agreement, the Agent and
the Lenders also permitted Commerce for a period from September 20, 2007 to
October 5, 2007 to exceed its Gross Borrowing Base, as defined in the
Agreement.
The
Sixth
Amendment, executed on November 16, 2007, revised several provisions of the
Credit Facility including (i) revising the Fixed Charge Coverage Ratio covenant
and adding a new minimum EBITDA financial covenant; (ii) adjusting the amount
of
excess availability required to $2.5 million at all times prior to July 1,
2008
at which time it becomes $10 million; (iii) eliminating the previously-required
provision to maintain $10 million of Eligible Cash Collateral on deposit;
and
(iv) extending the term of the Credit Facility for one year to June
2010.
Supply
Agreements
Tenaska
Power Services Co.
In
August
2005, the Company and Commerce entered into several agreements with Tenaska
Power Services Co., or Tenaska, for the supply of the majority of Commerce’s
wholesale electricity supply needs in Texas, utilizing a commercially standard
master power purchase and sale, lockbox, security and guaranty agreements.
The
Company’s Texas customers pay into a designated account that is used to pay
Tenaska for the electricity. Tenaska also extends credit to the Company to
buy
wholesale electricity supply secured by funds pledged by the Company in the
lockbox, its related accounts receivables and customers contracts. The Company
entered into a guaranty agreement, pursuant to which it, as the parent company
of Commerce, unconditionally guaranteed to Tenaska full and prompt payment
of
all indebtedness and obligations owed to Tenaska. Tenaska has agreed to provide
credit to Commerce in an amount not to exceed $22 million. At October 31,
2007, Tenaska had extended approximately $14.8 million of trade credit to
the
Company. Tenaska also serves as the Company’s exclusive provider of qualified
scheduling services and marketing services in the region of Texas administered
by the Electric Reliability Council of Texas.
Pacific
Summit Energy LLC
In
September 2006, the Company and Commerce entered into several agreements
with
Pacific Summit LLC, or Pacific Summit, for the supply of natural gas to serve
end-use customers that we acquired in connection with the HESCO acquisition,
utilizing a base contract for the purchase and sale of natural gas, an
operating, lockbox control and security agreements. Under the agreements,
these
customers remit their payments into the lockbox used to pay Pacific Summit
for
natural gas supplies. Pacific Summit also extends credit to the Company to
buy
wholesale natural gas supplies, secured by funds pledged by the Company in
the
lockbox, its related accounts receivable and a $3.5 million letter of
credit. Under the security agreement, Commerce agreed to maintain a minimum
deposit amount in the lockbox account. The security agreement also provided
for
monthly withdrawals from the lockbox account, with payments to be made first
to
Pacific Summit for amounts due and payable, and second to Commerce for amounts
exceeding the adjusted minimum deposit amount, as defined in the security
agreement. At October 31, 2007, Pacific Summit had extended approximately
$9.5 million of trade credit to the Company under this
arrangement.
Contractual
Obligations
As
of
October 31, 2007, we had commitments of $30.4 million for energy
purchase, transportation and capacity contracts. These contracts are with
various suppliers and extend through December 2008.
Letters
of Credit and Surety Bonds
As
of
October 31, 2007, $11.6 million of letters of credit have been issued
to energy suppliers and others pursuant to the terms of our Credit Facility
and
$6.0 million in surety bonds have been issued.
Critical
Accounting Policies and Estimates
The
preparation of this
Quarterly Report on Form 10-Q requires us to make estimates and assumptions
that affect the reported amounts 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
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.
|
•
|
Accounting
for Derivative Instruments and Hedging Activities
— We purchase
substantially all of our power and natural gas under forward physical
delivery contracts for supply to our retail customers. These forward
physical delivery contracts are defined as commodity derivative
contracts
under Statement of Financial Accounting Standard, or SFAS No. 133,
“Accounting for Derivative Instruments and Hedging Activities”. Using the
exemption available for qualifying contracts under SFAS No. 133, we
apply the normal purchase and normal sale accounting treatment
to a
majority of our forward physical delivery contracts. Accordingly,
we
record revenue generated from customer sales as energy is delivered
to our
retail customers and the related energy cost under our forward
physical
delivery contracts is recorded as direct energy costs when received
from
our suppliers. We use financial derivative instruments (such as
swaps,
options and futures) as an effective way of assisting in managing
our
price risk in energy supply procurement. For forward or future
contracts
that do not meet the qualifying criteria for normal purchase, normal
sale
accounting treatment, we elect cash flow hedge accounting, where
appropriate.
|
We
also
utilize other financial derivatives, primarily swaps, options and futures
to
hedge our commodity price risks. Certain derivative instruments, which are
designated as economic hedges or as speculative, do not qualify for hedge
accounting treatment and require current period mark to market accounting
in
accordance with SFAS No. 133, with fair market value being used to
determine the related income or expense that is recorded each quarter in
the
statement of operations. As a result, the changes in fair value of derivatives
that do not meet the requirements of normal purchase and normal sale accounting
treatment or cash flow hedge accounting are recorded in operating income
(loss)
and as a current or long-term derivative asset or liability. The subsequent
changes in the fair value of these contracts could result in operating income
(loss) volatility as the fair value of the changes are recorded on a net
basis
in direct energy costs in our consolidated statement of operations for each
period.
As
a
result of a sale on January 28, 2005 of two significant electricity forward
physical delivery contracts (on a net cash settlement basis) back to the
original supplier, the normal purchase and normal sale exemption under
SFAS No. 133 was no longer available for our Pennsylvania market
(PJM-ISO). Accordingly, for the period from February 2005 through July 2006,
we
designated forward physical delivery contracts entered into for our Pennsylvania
electricity market as cash flow hedges, whereby market to market accounting
gains or losses were deferred and reported as a component of Other Comprehensive
Income (Loss) until the time of physical delivery. Effective August 1,
2006, the normal purchase and normal sale exemption has been reinstated for
our
Pennsylvania market.
|
•
|
Utility
and independent system operator costs
— Included in direct
energy costs, along with the cost of energy that we purchase, are
scheduling costs, Independent System Operator, or ISO, fees, interstate
pipeline costs and utility service charges. The actual charges
and certain
energy costs are not finalized until subsequent settlement processes
are
performed for all distribution system participants. Prior to the
completion of settlements (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 information resulting in the need to adjust previous
estimates.
|
|
•
|
Allowance
for doubtful accounts
— We maintain allowances for doubtful
accounts for estimated losses resulting from non-payment of customer
billings. If the financial conditions of certain of our customers
were to
deteriorate, resulting in an impairment of their ability to make
payments,
additional allowances may be
required.
|
|
•
|
Net
revenue and unbilled receivables
— Our customers are billed
monthly at various dates throughout the month. Unbilled receivables
represent the estimated sale amount for power delivered to a customer
at
the end of a reporting period, but not yet billed. Unbilled receivables
from sales are estimated based upon the amount of power delivered,
but not
yet billed, multiplied by the estimated sales price per
unit.
|
|
•
|
Inventory
— Inventory consists of natural gas in storage as required by
state regulators and contracted obligations under customer choice
programs. Inventory is stated at the lower of cost or
market.
|
|
•
|
Customer
Acquisition Cost
— Direct Customer acquisition costs paid to
third parties and directly related to specific new customers are
deferred
and amortized over the life of the initial customer contract, typically
one year.
|
|
•
|
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.
|
Item
3.
Quantitative and Qualitative Disclosures about Market
Risk.
Our
activities expose us to a variety of market risks principally from the change
in
and volatility of commodity prices. We have established risk management policies
and procedures designed to manage these risks with a strong focus on the
retail
nature of our business and to reduce the potentially adverse effects these
risks
may have on our operating results. Our Board of Directors and the Audit
Committee of the Board oversee the risk management program, including the
approval of risk management policies and procedures. This program is predicated
on a strong risk management focus combined with the establishment of an
effective system of internal controls. We have a Risk Oversight Committee,
or
ROC, that is responsible for establishing risk management policies, reviewing
procedures for the identification, assessment, measurement and management
of
risks, and the monitoring and reporting of risk exposures. The ROC is comprised
of all key members of senior management and is chaired by the Vice President,
Chief Risk Officer.
Commodity
Risk Management
Commodity
price and volume risk arise from the potential for changes in the price of,
and
transportation costs for, electricity and natural gas, the volatility of
commodity prices, and customer usage fluctuations due to changes in weather
and/or customer usage patterns. A number of factors associated with the
structure and operation of the energy markets significantly influence the
level
and volatility of prices for energy commodities. These factors include seasonal
daily and hourly changes in demand, extreme peak demands due to weather
conditions, available supply resources, transportation availability and
reliability within and between geographic regions, procedures used to maintain
the integrity of the physical electricity system during extreme conditions,
and
changes in the nature and extent of federal and state regulations. These
factors
can affect energy commodity and derivative prices in different ways and to
different degrees.
Supplying
electricity and natural gas to our retail customers requires us to match
the
projected demand of our customers with contractual purchase commitments from
our
suppliers at fixed or indexed prices. We primarily use forward physical energy
purchases and derivative instruments to minimize significant, unanticipated
earnings fluctuations caused by commodity price volatility. Derivative
instruments are used to limit the unfavorable effect that price increases
will
have on electricity and natural gas purchases, effectively fixing the future
purchase price of electricity or natural gas for the applicable forecasted
usage
and protecting the Company from significant 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 the instrument has met specific hedge accounting criteria.
Subsequent changes in the fair value of the derivative assets and liabilities
designated as a cash flow hedge are recorded on a net basis in Other
Comprehensive Income (Loss) and subsequently reclassified as direct energy
cost
in the statement of operations as the energy is delivered. While some of
the
contracts we use to manage risk represent commodities or instruments for
which
prices are available from external sources, other commodities and certain
contracts are not actively traded and are valued using other pricing sources
and
modeling techniques to determine expected future market prices, contract
quantities, or both. We use our best estimates to determine the fair value
of
commodity and derivative contracts we hold and sell. These estimates consider
various factors including closing exchange and over-the-counter price
quotations, time value, volatility factors and credit exposure. We do 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
the requirements of our retail customers.
With
most
electricity and natural gas customers, we have the ability to change prices
with
short notice; and, therefore, the impact on gross profits from increases
in
energy prices is not material for these customers. However, sharp and sustained
price increases could result in customer attrition without corresponding
price
increases by local utilities and other competitors. Approximately 55% of
our
electricity customers and 33% of our natural gas customers are subject
to
multi-month fixed priced unhedged contracts and, accordingly a $10 per
megawatt
hour increase in the cost of purchased power and a $1.00 per mmbtu increase
in
the cost of purchased natural gas could result in an estimated $3,786,000
decrease in gross profit for power, and an estimated $1,018,000 decrease
in
gross profit for natural gas, respectively, for fiscal 2008.
Credit
Risk
Our
primary credit risks are exposure to our retail customers for default on
their
contractual obligations. Given the high credit quality of the majority
of our
energy suppliers, credit risk resulting from failure of our suppliers to
deliver
or perform on their contracted energy commitments is not considered
significant.
The
retail credit default or nonpayment risk is managed through established
credit
policies which actively require screening of customer credit prior to
contracting with a customer, potentially requiring deposits from customers
and/or actively discontinuing business with customers that do not pay
as
contractually obligated. At times, the Company is limited in the
types of credit policies which it may implement by applicable state rules
and
regulation in a market in which we sell energy. Retail credit quality
is dependent on the economy and the ability of our customers to manage
through
unfavorable economic cycles and other market changes. If the business
environment were to be negatively affected by changes in economic or
other
market conditions, our retail credit risk may be adversely
impacted.
Counterparty
credit risks result primarily from credit extended to us for our purchases
of
energy from our suppliers. Favorable credit terms from our suppliers make
it
easier to procure wholesale energy to service our customers; however, adverse
market conditions or poor financial performance by us may result in a reduction
or elimination of available unsecured counterparty credit lines. Additionally,
we have significant amounts of energy commitments to our contracted term
customers that we have hedged forward, often for several months. A significant
decrease in energy prices could adversely impact our cash collateral
requirements.
Interest
Rate Risk
As
we had
no long-term debt outstanding at October 31, 2007, our only exposure to
interest rate risks is limited to short-term borrowings and our investment
of
excess cash balances in interest-bearing instruments. As our borrowings
are only
short-term and are adjusted to market rates on a recurring basis, we do
not
believe we have interest rate risk on these borrowings. We generally invest
cash
equivalents in short-term credit instruments consisting primarily of high
credit
quality, short-term money market funds and insured, re-marketable government
agency securities with interest rate reset maturities of 90 days or less.
We do not expect any material loss from our investments and we believe
that our
potential interest rate exposure is not material. As our practice has been,
and
currently continues to be, to only invest in high-quality debt instruments
with
maturities or remarketing dates of 90 days or less, we currently are not
materially susceptible to interest rate risk on our investments.
Item
4.
Controls and Procedures.
Evaluation
of Disclosure Controls and Procedures
Our
Chief
Executive Officer and our Interim Chief Financial Officer have concluded,
based
upon their evaluation as of the end of the period covered by this Report,
that
our disclosure controls and procedures (as defined under Rule 13a-15(e)
under
the Securities Exchange Act of 1934, as amended, or the Exchange Act) are
effective to ensure that all information required to be disclosed by the
Company
in the reports filed or submitted by it under the Exchange Act is recorded,
processed, summarized and reported within the time periods specified in
the
SEC’s rules and forms, and include controls and procedures designed to ensure
that information required to be disclosed by the Company in such reports
is
accumulated and communicated to the Company’s management, including the Chief
Executive Officer and the Interim Chief Financial Officer, as appropriate,
and
allow timely decisions regarding required disclosure.
Changes
in Internal Control Over Financial Reporting
No
change
in the Company’s internal control over financial reporting occurred during the
Company’s last fiscal quarter that has materially affected, or is reasonably
likely to materially affect, the Company’s internal control over financial
reporting.