UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 

 

 

 

Form 10-K

 

 

 

 

 

Commission file number 001-32239

 

 

 

 

Commerce Energy Group, Inc.

(Exact name of registrant as specified in its charter)

 

 

 

Registrant’s telephone number, including area code

(714) 259-2500

 

Securities registered pursuant to Section 12(b) of the Act:

 

 

Securities registered pursuant to Section 12(g) of the Act:

 

None

 

(Title of class)

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes o     No þ

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes o     No þ

 

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 at least the past 90 days:  Yes þ     No o

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this Chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  o

 

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

 

Large Accelerated Filer o     Accelerated Filer o     Non-accelerated Filer þ

 

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

 

The aggregate market value of the Common Stock held by non-affiliates of the registrant as of January 31, 2007 was approximately $42,074,457 (computed using the closing price of $1.45 per share of Common Stock on January 31, 2007, as reported by the American Stock Exchange).

 

As of October 16, 2007, 30,372,618 shares of the registrant’s Common Stock were outstanding.

 

 

TABLE OF CONTENTS

 

 

You should carefully consider the risk factors described below, as well as the other information included in this Annual Report on Form 10-K prior to making a decision to invest in our securities. The risks and uncertainties described below are not the only ones facing our company. Additional risks and uncertainties not presently known or that we currently believe to be less significant may also adversely affect us. Unless the context requires otherwise, references to the “Company,” “Commerce,” “we,” “us,” and “our” refer specifically to Commerce Energy Group, Inc. and its subsidiaries.

 

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

 

On one or more occasions, we may make statements regarding our assumptions, projections, expectations, targets, intentions or beliefs about future events. All statements other than statements of historical facts included in this Annual Report on Form 10-K relating to expectation of future financial performance, continued growth, changes in economic conditions or capital markets and changes in customer usage patterns and preferences, are forward-looking statements.

 

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

 

In addition to the factors and other matters discussed in Item 1A. Risk Factors in this Annual Report on Form 10-K, some important factors that could cause actual results or outcomes for Commerce Energy Group, Inc. or our subsidiaries to differ materially from those discussed in forward-looking statements include:

 

 

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

 

PART I

 

 

Overview

 

Commerce Energy Group, Inc., or Commerce, is an independent energy marketer of retail electric power and natural gas supply to residential, commercial, industrial and institutional customers. We also provide consulting, technology and transaction data management services to energy-related businesses. Unless otherwise noted, as used herein, the “Company,” “we,” “us,” and “our” means Commerce Energy Group, Inc. and its subsidiaries.

 

Commerce operates through its two wholly-owned subsidiaries, Commerce Energy, Inc. and Skipping Stone Inc. Commerce Energy, Inc., or Commerce Energy, formerly Commonwealth Energy Corporation and doing business as “electricAmerica”, is licensed by the Federal Energy Regulatory Commission, or FERC, and by state regulatory agencies as an unregulated retail marketer of natural gas and electricity. As of July 31, 2007, we provided natural gas and electricity to approximately 196,000 residential, commercial, industrial and institutional customers in ten states. Skipping Stone Inc., or Skipping Stone, provides energy-related consulting and information to utilities, electricity generators, natural gas pipelines, wholesale energy merchants, energy technology providers and financial institutions.

 

Commerce’s predecessor, Commonwealth Energy Corporation, or Commonwealth, was formed in California in August 1997. On July 6, 2004, Commonwealth reorganized into a holding company structure, whereby Commonwealth became a wholly-owned subsidiary of Commerce.

 

Commerce was incorporated in the State of Delaware on December 18, 2003. Our executive offices are located at 600 Anton Boulevard, Suite 2000, Costa Mesa, California 92626 and our telephone number is (714) 259-2500. Our fiscal year ends July 31.

 

Industry Background

 

Electricity

 

In order to increase consumers’ competitive options beginning in 1992, the U.S. electric utility industry began a process of deregulation, which primarily served to unbundle generation, transmission, distribution and ancillary services into separate components of a utility’s service. As in other industries that have been deregulated, competition in the electric service industry was intended to provide consumers with a choice of multiple suppliers and was expected to promote product differentiation, lower costs and delivery of enhanced services. To obtain these benefits, customers in deregulated utility markets would be able to choose to switch their electric supply service from their local utility to an alternative supplier.

 

In 1996, some states, and some of the utilities within those states, proceeded to allow their end-use customers direct access to marketers, enabling them to purchase their electricity commodity from entities other than the local utilities in competitive retail markets. These proceedings created new market participants of which Commerce Energy is one. They are known in California as Electricity Service Providers, or ESPs, and in other states by this or similar terms. Presently, approximately one-half of the states in the United States have either enacted enabling legislation or issued regulatory orders to proceed with such retail direct access.

 

The electricity distribution infrastructure in place prior to deregulation remains largely unchanged, with the primary difference being that parties other than the local utility can utilize the delivery infrastructure by paying usage fees. ESPs use this established electricity network for the delivery of energy to their customers.

 

Electricity is a real-time commodity and cannot be stored. As soon as it is produced, it must be simultaneously delivered into the grid to meet the demand of end users. Most electricity grids and wholesale market clearing activities are managed by third party entities known as Independent System Operators or ISOs, or Regional Transmission Organizations or RTOs. The ISO or RTO is responsible for system reliability and ensures that physical electricity transactions between market participants are managed in such a way as to assure that proper electricity reserve margins are in place, grid capacity is maintained and supply and demand are balanced.

To maintain profitability, we must effectively manage or shape our purchased electricity supply to the real-time demand or load of our customers. These load-shaping activities, required by the hourly variability in the electricity usage patterns of our customers compared to the fixed hourly volume purchased from our suppliers, results in our holding of long or short energy positions. A long position occurs when we have committed to purchase more electricity than our customers need, and a short position occurs when our customers’ usage exceeds the amount of electricity we have committed to purchase. In both situations, we utilize the wholesale electricity spot market and ISO clearing markets to balance our long or short energy positions, selling supply when in a long position and buying when in a short position. It is not possible to be completely balanced on every delivery hour; therefore we always have some exposure to price volatility in the wholesale market for electric power.

 

Purchases and sales in the wholesale market are regulated by FERC, to whom we report regularly. Weather, generation capacity, transmission, distribution and other market and regulatory issues also are significant factors in determining our wholesale procurement and sales strategies in each of the markets we serve.

 

FERC has deregulated the wholesale electricity market by allowing power marketers and utilities who do not have market controlling power, to sell wholesale electric power at market rates (i.e., whatever rate the buyer and seller agree upon), as opposed to requiring that prices be cost-based (i.e., based on the supplier’s cost of the electricity).

 

FERC has further encouraged competition in the wholesale bulk power markets by promulgating open access transmission rules in 1996, which have led to the increasing commoditization of electricity markets. FERC’s open access transmission rules require transmission providers under its jurisdiction to allow eligible customers access to their transmission systems at cost-based rates. This has enabled purchasers of wholesale power to access a larger number of potential suppliers, thereby enhancing competition.

 

FERC has continued to promote increased competition in RTOs which have ultimate control over the bulk transmission system in a particular geographic area. Wholesale electricity or bulk power, once purchased and sold almost exclusively between traditional utilities under bilateral arrangements, is now traded by many different market participants on organized markets, including hourly, daily and monthly spot markets, power exchanges and financial markets, such as futures and options markets. Competitive markets now exist in many regions of the country for energy, automatic generation control, spinning reserves, other categories of ancillary services and capacity. Organizations such as the New York Mercantile Exchange, or NYMEX, and the Intercontinental Exchange, or ICE, offer trading opportunities in electricity futures and options at various locations across the country. The price of electricity is largely set by these competitive markets. Recently, the growth and evolution of wholesale electricity markets has been accelerated with the formation of RTOs. These RTOs are developing organized market structures for the purpose of providing more efficient and competitive wholesale marketplaces for the benefit of consumers in the regions in which they operate.

 

Retail electric marketers procure power supplies for delivery to end-use customers from a variety of wholesale power producers or merchant generation companies, either through term supply contracts or on a spot basis. In addition, short-term daily or hourly supply requirements can be purchased or sold through the balancing markets operated by the ISO or RTO. The physical distribution of electricity to retail customers remains the responsibility of the local utility, which collects fees for its services. Most states also allow the utility to provide additional services, such as reading meters, generating customer bills, collecting bills and taking requests for service changes or problems, while in other states the utility is not allowed to, or chooses not to, perform these services.

 

Natural Gas

 

The natural gas industry, government regulated since 1938, began a process of deregulation in the early 1980s leading to a dynamic industry with a highly competitive market place and a commodity that is widely traded in the daily and futures markets. The market price of natural gas is quoted at various locations or regional hubs around the country. These regional hubs are usually priced at a differential to the largest centralized point for natural gas spot and futures trading in the United States known as the Henry Hub, located in Louisiana, and used by the NYMEX as the contractual point of delivery for its natural gas futures contracts. There are over 70 major market hubs, or intersections of various pipeline systems, where natural gas transactions occur. In addition, purchases and sales are made at thousands of gas processing plants where gas enters the national grid, city gate interconnections where gas

leaves the national grid, and industrial and electric generator direct connections with large pipelines making up the national grid. Thousands of contracts are bought and sold daily at the market centers. These market centers have various degrees of liquidity in both the cash and forward markets. Prices may vary widely from hub to hub, reflecting regional market conditions. Additionally, thousands of transactions occur at non-market hub interconnections and often these transactions are based upon or priced relative to the major market hub or hubs in their vicinity.

 

Although transactional prices of natural gas are determined by market forces, the cost of transportation of natural gas from the outlet of gathering systems and processing plants to the “city gate” interconnection with local gas distributors is performed by regulated pipelines which essentially act as common carriers. Any market participant desiring transportation services from such pipelines must be offered such services on an equal basis with other market participants. Transportation from the city gate to the burner tip, a common term for where a consumer uses the gas, is performed by regulated local utilities. Unlike the interstate natural gas pipelines that act as common carriers, the local gas distribution companies are a mixture of common carrier, selective carrier, and non-carrier systems. Only common carrier and some selective carrier systems can be accessed to serve retail residential and commercial/industrial customers.

 

Retail natural gas providers for the most part procure natural gas supplies for delivery to end-use customers from a variety of wholesale natural gas suppliers, mostly at a relevant market hub, either through term supply contracts or on a spot basis. The physical distribution of natural gas to retail customers remains the responsibility of the local natural gas utility, which collects a fee for the use of its distribution system.

 

Core Products and Services

 

Our core business is the retail sale of electricity and natural gas to end-use customers. We also provide professional consulting and technology services to utilities, electricity generators, wholesale energy merchants, financial institutions and energy technology companies.

 

Commerce Energy, Inc.

 

We sell electricity and natural gas service to customers under both month-to-month and longer-term service contracts. The difference between the sales price of energy delivered to our customers and the related cost of our energy supplies, transmission costs, distribution costs and ancillary services costs provides our gross profit margin. The electricity and natural gas we sell is generally metered and delivered to our customers by the local utilities. The local utilities also provide billing and collection services for many of our customers on our behalf.

 

We buy electricity and natural gas in the wholesale market in time-specific, bulk or block quantities usually at fixed prices. With respect to electricity markets, we balance the differences between the actual sales demand or usage of our customers and our bulk or block purchases by buying and selling any shortfall or excess in the spot market. ISOs and RTOs perform real-time load balancing for each of the electric grids in which we operate. Similarly, with respect to natural gas markets, supply and demand balancing is performed by Commerce Energy in connection with agreements with the local distribution company or LDC utilities or by the LDCs themselves on behalf of Commerce Energy, for each of the natural gas markets in which we operate. We are charged or credited by the ISOs and LDCs for balancing the electricity and natural gas purchased and sold to our customers.

 

Skipping Stone Inc.

 

Skipping Stone offers a number of related professional consulting services and technologies to energy companies such as utilities, electricity generators, natural gas pipelines, wholesale energy merchants, energy technology providers and investment banks. Skipping Stone is focused on assisting clients with business process improvements, market research, training, Sarbanes-Oxley process level implementations, systems design and selection, and strategic and tactical planning for new market or merger activities. Additionally, Skipping Stone provides natural gas pipeline information to market participants and government customers through its technology center using its capacitycenter.com website.

Our Customers and Markets

 

As of July 31, 2007, we were delivering electricity and natural gas supply to customers in 10 states and 22 LDC markets. We periodically review and evaluate the profitability of our operations in each of these markets and the advantages to us of entering other potential LDC markets that are open for direct access sales to end-use customers. The review of entrance in a new market area would include exploring opportunities to acquire existing portfolios of customers from current suppliers in targeted markets.

 

We operate in one reportable business segment, energy retailing, in one geographic area, the United States. Our customer base consists of residential, commercial, industrial and institutional customers. Our business is not dependent upon any one customer or a few major customers and, during fiscal 2007, no one customer accounted for more than 10% of our net revenues. In addition to expansion of our core products and services into new deregulated markets and targeted customer classes, we are working to broaden the scope of our energy-related products and services to include energy efficiency offerings and additional outsourced services.

 

As of July 31, 2007, we served approximately 196,000 electricity and natural gas customers. Although a number of our customers, particularly in our commercial and industrial sales segment, have more than one account, we determine and report our customer count with each customer defined as an individual customer account. We served electricity customers in 12 LDC markets within six states: California, Pennsylvania, Michigan, Maryland, New Jersey and Texas and natural gas customers in 13 LDC markets within seven states: California, Florida, Georgia, Maryland, Nevada, Ohio and Pennsylvania.

 

Sales of electricity and natural gas comprised 64% and 34%, respectively, of total net revenues during fiscal 2007; 74% and 25%, respectively, during fiscal 2006; and 89% and 10%, respectively during fiscal 2005.

 

Skipping Stone is engaged by over 50 clients under master agreements, with up to a dozen active engagements in any given month. Approximately 1%-2% of total net revenues in fiscal 2005 through 2007 have been attributable to Skipping Stone.

 

Strategy

 

Commerce Energy’s profitability depends on our ability to achieve sufficient customer scale in order to create a profitable operating cost structure. To achieve this scale, we intend to substantially grow our customer base in markets that offer adequate gross margins, shed customers which may no longer be served economically, evaluate and align our market presence to achieve optimum returns on investments and seek out acquisition opportunities that will advance our growth goals. Growth plans include:

 

 

 

Sales and Marketing

 

Commerce Energy markets electricity and natural gas utilizing contract terms based either on fixed or variable rates. The majority of our fixed-rate contracts are for a duration of 12 to 24 months, with occasional shorter-term offerings based on market conditions and customer preferences. Our monthly variable rate contracts are cancellable after 30 days’ notice, allowing customer flexibility with respect to a longer term price or supplier commitment. During fiscal 2007, approximately 85% of our new customer sales contracts were under fixed-rate contract terms. As expected, following unprecedented increases in the wholesale cost of energy and significant volatility of market prices during the second half of calendar 2006, customers were more inclined to lock in certainty in the cost of their energy. As the wholesale market price of energy declines, we believe customers may increasingly move toward our monthly variable-rate contracts, thus allowing them to take advantage of decreasing market prices.

 

A variety of approaches are utilized in acquiring customers, including a professional sales force calling on C&I end-users and various mass market sales channels in pursuit of residential and small businesses. Historically, a majority of our customers have been acquired through telesales and network marketing. More recently, door-to-door sales have been added as well as targeted broadcast advertising, direct mail and on-line affiliates.

 

Service after the sale is a critical part of our success. During fiscal 2007, high levels of customer growth resulted in hiring and training new staff members, as well as improving technology platforms to expedite the processing of new customer accounts, to ensure timely and accurate billing and to provide one-call resolution to customer inquiries.

 

Our sales efforts are divided into two divisions: C&I, representing sales to medium-sized and larger commercial accounts, and Mass Market, comprised of residential customers and small businesses.

 

Commercial & Industrial

 

The C&I segment comprises electricity and natural gas sales to small and medium-size commercial consumers, municipal and government entities. These sales primarily consist of structured products and negotiated contracts developed to meet the budgetary needs and risk tolerance of an individual customer. The typical C&I customer possesses a high level of understanding of the energy business and current market conditions. Competition for these types of customers is robust, with several established competitors in each geographic market. C&I sales involve a longer sales cycle, higher energy usage and lower per unit margins than the typical mass market customer.

 

Commerce Energy has established itself as a preferred provider of customers with multi-location, multi-state requirements. Leveraging our information systems and operational capabilities, we are able to attract and retain customers such as retail chains, hotel/motel chains, food service chains and school districts, in addition to small- and medium-sized, single-location commercial consumers. Although other indirect sales channels are utilized, we make sales to this customer segment largely through the establishment of direct customer relationship by experienced account executives.

 

Mass Market

 

Sales to mass market customers are comprised of pre-defined service plans developed on the usage patterns of a typical small business or residential consumer. Historically, telesales and network marketing were utilized almost exclusively for the acquisition of customers in the mass market. In order to significantly increase our sales in this customer segment, we began utilizing a number of other sales channels for the acquisition of mass market customers, during fiscal 2007, including third-party door-to-door commissioned salespersons, online shopping sites, direct mail and targeted print and broadcast advertising.

 

Energy Supply

 

We do not own electricity generation assets or natural gas producing properties. All of the electricity and natural gas we sell to our customers is purchased in the wholesale market from third-party suppliers in time-specific

block quantities under short-term and long-term contracts, usually at fixed prices. Although we have open lines of credit with suppliers, contractual purchase terms with suppliers often require additional collateral to support our energy purchases. We utilize our available cash and letters of credit issued under our bank credit facility to meet any collateral requirements of our energy suppliers.

 

With respect to electricity markets, we balance the differences between the actual sales demand or usage of our customers and our bulk or block purchases by buying and selling any shortfall or excess in the spot market. ISOs and RTOs perform real-time load balancing for each of the electric grids in which we operate. Similarly, with respect to the natural gas market, supply and demand balancing is performed by Commerce Energy in connection with agreements with the LDC utilities or by the LDC themselves on behalf of Commerce Energy, for each of the natural gas markets in which we operate. We are charged or credited by the ISOs and LDCs for balancing of our electricity and natural gas purchased and sold for our account, and we are subject to costs or fees charged by the ISOs or LDCs for these electricity and natural gas balancing activities related to our account.

 

Wholesale electricity and natural gas are readily available from various third party suppliers in our markets, except for the state of Michigan, where all of our electricity is purchased from one supplier. In fiscal 2007, two electricity suppliers each accounted for 10% of our direct energy costs and one gas supplier accounted for 25% of our direct energy costs, and their relationships are not secured by long-term contracts. Based upon current information from our suppliers, we do not anticipate any shortage of supply. However, in the event of a supply shortage, there can be no assurance that we would be able to timely secure an alternative supply of electricity or natural gas at prices comparable to our current contracts, and the failure to replace a supplier in a timely manner at comparable prices could materially harm our operations.

 

We employ risk management policies and procedures to control and monitor the risks associated with volatile commodity markets and to assure a balanced energy-sales-and-supply portfolio within defined risk tolerances.

 

Competition

 

Commerce Energy, Inc.

 

In markets that are open to competitive choice of retail energy suppliers, there are generally three types of competitors: the incumbent utilities, utility-affiliated retail marketers and small to mid-size independent retail energy companies, such as Commerce Energy. Competition is based primarily on price, product offerings and customer service.

 

The competitive landscape differs in each utility service area, and within each targeted customer segment. For residential and small commercial customers in most service territories, the primary competitive challenges come from the incumbent utility and affiliated utility marketing companies. For the medium-sized commercial customer, competitive challenges come from the utility and its affiliated marketing company, as well as other independents. However, this segment is still the least targeted segment among our competition due to the difficulty in balancing cost of acquisition and margin objectives. The large commercial, institutional and industrial segments are very competitive in most markets with nearly all customers having already switched away from the utility to an alternate provider. National affiliated utility marketers, energy producers and other independent retail energy companies often compete for customers in this segment.

 

The incumbent regulated utilities and the nationally-branded utility affiliates typically benefit from the economies of scale derived from the strength of substantial asset-based balance sheets, and vertically integrated business models that combine production, transmission and distribution assets. For incumbent utilities these advantages are often offset by the lack of flexibility to offer multiple product choices to their customers, while the nationally- branded affiliates often struggle with long-term focus and cultural adaptation to a non-regulated market environment.

 

Increasing our market share depends on our ability to convince customers to switch to our service. The local utilities have the advantage of long-standing relationships with their customers, and they have longer operating histories, greater financial and other resources and greater name recognition in their markets than we do. In addition, local utilities have been subject to many years of regulatory oversight and thus have a significant amount of experience regarding the policy preferences of their regulators, as well as a critical economic interest in the

outcome of proceedings concerning their revenues and terms and conditions of service. Local utilities may seek to decrease their tariff retail rates to limit or to preclude the opportunities for competitive energy suppliers and may seek to establish rates, terms and conditions to the disadvantage of competitive energy suppliers. There is an emerging trend among some local utilities to exit the merchant function and actively encourage customers to change their energy supply service. This is sometimes encouraged by the framework for deregulation within which the local utility operates.

 

Among the retail marketers and wholesale merchants, competition is most intense for the larger volume commercial and industrial accounts. Our primary target customer segments are small to medium commercial customers. We expect that the combination of our existing residential customer base and our continued growth will enhance our ability to successfully compete for larger commercial and institutional customers.

 

Most customers who switch away from the local utility do so for economic benefit. Once switched, customer retention is based on continuing competitive pricing, reliability of supply and customer service.

 

Some of our competitors, including local utilities, have formed alliances and joint ventures in order to compete in the restructured retail electricity and natural gas industries. Many customers of these local utilities may decide to stay with their long-time energy provider if they have been satisfied with their service in the past. Therefore, it may be difficult for us to compete against local utilities and their affiliates.

 

We also may face competition from other nationally-branded providers of consumer products and services. Some of these competitors or potential competitors may be larger and better capitalized than we are.

 

Skipping Stone Inc.

 

We face competition in selling consulting and outsourced services from a large variety of companies. These competitors may be engaged in the energy business, as we are, or may be national and international management and information technology firms.

 

Seasonality

 

Our sales volumes and revenues are subject to fluctuations during the year due primarily to the impact of seasonal weather factors on customer energy demand and the related market prices of electricity and natural gas. Electricity sales volumes are historically higher in the summer months for cooling purposes, followed by the winter months for heating and lighting purposes. Natural gas sales volumes are higher in the winter heating season, with the lowest demand occurring during the summer.

 

Governmental Regulation

 

In states that have adopted deregulation, state Public Utility Commissions or PUCs, Public Service Commissions or PSCs, or equivalent bodies, have authority to license, certify and regulate certain activities of electric and natural gas retailers. Commerce Energy is subject to regulation by the Commissions in each state in which we sell electricity and natural gas. As of July 31, 2007, we were licensed or certified by the applicable Commissions in 11 states. These licenses and certificates permit us to sell electricity and natural gas to commercial, industrial, institutional and residential customers. The requirements for licensing and the level of regulation vary from state to state.

 

We consider each utility service territory within which we operate to be a distinct market due to the unique characteristics of each. A discussion of regulations for our market service areas follows.

 

State Regulations

 

Wholesale market rules are expected to change over the next several years as RTOs continue in their efforts through a variety of FERC-filed or state Commission rules and procedures to relieve congested transmission systems, encourage expansion of transmission networks and attempt to enhance competition in the bulk power markets. These changes will likely impact our retail electricity business in several RTOs in which we operate, specifically: Pennsylvania — New Jersey — Maryland or PJM Interconnection, referred to as the PJM Market, Electric Reliability Council of Texas, referred to as ERCOT, and the California Independent System Operator or

CAISO. These proposed changes could increase transmission charges in the form of congestion pricing to relieve congestion at certain delivery or interconnection points on a transmission system (nodal pricing and related measures) and through higher transmission capacity charges permitted by FERC to stimulate more investment in new transmission lines and facilities. While these changes will likely increase transmission charges, at least in the short run, they may lead to a more efficient and expanded transmission system within these RTOs that can accommodate more transactions, and help the Company to access more customers at the wholesale and retail level. There is no way to impute an exact effect through a cost/benefit analysis because there are many variables, and RTOs may be permitted different ways to achieve the same objective of enhancing competition in the bulk power, wholesale markets.

 

Electricity

 

California.  In 1996, California Assembly Bill 1890 codified the restructuring of the California electric industry and provided for the right of Direct Access. Direct Access 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 ESP. On September 20, 2001, the California Public Utilities Commission or CPUC, issued a ruling suspending electricity Direct Access. This ruling permits ESPs to keep their current customers and to solicit Direct Access customers served by other ESPs; however, it prohibits us from signing up new non-Direct Access customers in California, for an undetermined period of time. The amount of statewide load on Direct Access service has declined to approximately 10%.

 

On May 24, 2007, the CPUC voted 4-1 to begin a new proceeding — Order Instituting Rulemaking or OIR, which will examine, among other things, the legal authority of the CPUC to reopen the retail electric market unilaterally, (without further legislation), the public policy benefits of lifting the Direct Access suspension, and the retail rules governing a reconstituted Direct Access market. It is anticipated the OIR will be completed in the second half of 2008, and that as a result, the Direct Access market may reopen in 2009, unless legislation is introduced to prevent such a result.

 

Under legislative mandate, the CPUC is implementing the state’s Resource Adequacy Requirement or RAR. In September 2005, California Assembly Bill 380, covering electrical restructuring and resource adequacy was passed into law. This bill requires the CPUC, in consultation with the ISO, to establish RARs for all Load-Serving Entities or LSEs. The bill requires each LSE to secure generating capacity adequate to meet its load requirements, including but not limited to, peak demand and planning and operating reserves, deliverable to locations and at times as may be necessary to provide reliable electric service. The CPUC issued its Final Decision on system RARs on October 27, 2005. The Final Decision requires LSEs, including Investor-Owned Electric Utilities or IOUs, or ESPs, and Community Choice Aggregators or CCAs, to have capacity to serve their retail customers’ forecasted loads and a 15-17% reserve margin beginning in June 2006. On June 29, 2006, the CPUC issued its decision on local RARs, for which requirements are established annually under CPUC allocation principles. The CPUC adopted a penalty of $40 per kW-year on the amount a LSE is deficient in meeting the annual requirements, in addition to backstop procurement costs. As a LSE, Commerce Energy is subject to the RARs and its provisions, including penalties for non-compliance. The ability of Commerce Energy to recover costs associated with RAR from its customers will be subject to market pricing and competitive forces.

 

On September 26, 2006, California Senate Bill 107 was signed into law. The bill amends the existing law concerning renewable portfolio standards or RPS, for LSEs in the state. The bill accelerates the procurement targets such that 20% of retail sales are procured from eligible renewable energy resources no later than December 31, 2010. The former law required 20% by 2017. Rules to implement California’s RPS, including development of a renewable energy certificate market and flexible compliance measures, continue to evolve. As such, the associated costs to Commerce Energy or its customers are not fully known.

 

On September 27, 2006, California Assembly Bill 32, “The California Global Warming Solutions Act of 2006,” was signed into law. AB 32 sets in statute mechanisms to reduce greenhouse gas or GHG, emissions to 1990 levels, by the year 2020. Carbon dioxide or CO₂ makes up about 83% of California’s GHG emissions, largely from fossil fuel combustion. Transportation is responsible for 42% of CO₂ emissions and electric power emits 19.6% of CO₂ emissions. The impact of this bill is not yet known. The regulatory agencies continue to debate whether the

GHG reporting responsibilities and reduction requirements should be imposed as either a “first seller” or “load based” method. “First seller” method covers the generating plants responsible for GHG emissions. A “load based” method would pose a regulatory burden on us, and perhaps a cost increase to our retail customers.

 

CAISO is expected to implement a nodal market design on April 1, 2008, known as Market Redesign and Technology Upgrade or MRTU. The design provides better market efficiencies, in terms of congestion management and market price signals. However, the design poses systems complexity, higher transaction volumes, and requires greater hedging sophistication for market participants such as Commerce Energy. Additionally, MRTU may pose higher credit requirements because of congestion revenue rights being allocated to, and auctioned among, load-serving entities such as Commerce Energy. We are taking prudent steps to prepare for MRTU. We have engaged third-party project management and information technology services to guide this effort and convert our transaction systems.

 

California Refund Proceeding

 

In 2001, FERC ordered an evidentiary hearing (Docket No. EL00-95) to determine the amount of refunds due to California energy buyers for purchases made in the spot markets operated by the CAISO and the California Power Exchange or CPX, during the period October 2, 2000 through June 20, 2001, or the Refund Period. Among other holdings in the case, FERC determined that the Automated Power Exchange or the APX, and its market participants could be responsible for, or entitled to, refunds for transactions completed in the CAISO and the CPX spot markets through APX. FERC has not issued a final order determining “who owes how much to whom” in the California Refund Proceeding, and it is not clear when such an order will be issued. As discussed above, APX and its market participants have entered into a settlement that resolves how refunds owed to APX will be allocated among its market participants.

 

In the course of the California Refund Proceeding, FERC has issued dozens of orders. Most have been taken up on appeal before the United States Court of Appeals for the Ninth Circuit or the Ninth Circuit, which has issued opinions on some issues in the last several years. These cases are described below in the section as the California Litigation.

 

California Litigation. Lockyer v. FERC.   On September 9, 2004, the Ninth Circuit issued a decision on the California Attorney General’s challenge to the validity of FERC’s market-based rate system. This case was originally presented to FERC upon complaint that the adoption and implementation of market based rate authority was flawed. FERC dismissed the complaint after sellers refiled reports of sales in the CAISO and the CPX spot markets and bilateral sales to California Department of Water Resources during 2000 and 2001. The Ninth Circuit upheld FERC’s authority to authorize sales of electric energy at market-based rates, but found that the requirement that sales at market-based rates be reported quarterly to FERC for individual transactions is integral to a market-based rate regime. The State of California, among others, has publicly interpreted the decision as providing authority to FERC to order refunds for different time frames and based on different rationales than are currently pending in the California Refund Proceedings, discussed above in “California Refund Proceeding.” The decision remands to FERC the question of whether, and in what circumstances, to impose refunds or other remedies for any alleged failure to report sales transactions to FERC. On December 28, 2006, several energy sellers filed a petition for a writ of certiorari to the U.S. Supreme Court. The U.S. Supreme Court denied the petition. We cannot predict the scope or nature of, or ultimate resolution of this case.

 

CPUC v. FERC.  On August 2, 2006, after reviewing certain FERC decisions in the California Refund Proceedings, the Ninth Circuit decided that FERC erred in excluding potential relief for alleged tariff violations related to transactions in the CAISO and the CPX markets for periods that pre-dated October 2, 2000 and additionally ruled that FERC should consider remedies for certain bilateral transactions with the California Department of Water Resources previously considered outside the scope of the proceedings. The decision may expose Commerce to claims or liabilities for transactions outside the previously defined “refund period.” At this time, the ultimate financial outcome for Commerce is unclear.

 

To allow parties the opportunity to consider ways to settle disputes, the Ninth Circuit extended the deadline for seeking rehearing of the CPUC and Lockyer decisions to November 16, 2007 and delayed issuing the order

remanding the CPUC and Lockyer cases back to FERC. We are studying the court’s decision, but are unable to predict either the outcome of the proceedings or the ultimate financial effect to us.

 

Pennsylvania.  In 1996, the Electricity Generation Customer Choice and Competition Act was passed. The law allowed electric consumers 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. Commerce Energy began serving customers in Pennsylvania in 1999.

 

Current utility default rates are capped until 2010 as a result of the restructuring related to the Electric Choice Law. As power prices rise significantly, it has become clear that the utility price cap is not realistic or representative of true market power costs. Squeezed between a capped utility rate, high wholesale electricity costs and the high cost of servicing customers in Pennsylvania due to the market rules and market structure, many companies, including Commerce Energy, have reduced the number of customers they serve in the state. The Pennsylvania Office of Consumer Advocate is circulating a pricing analysis in an attempt to show that post-rate-cap rate increases will be severe. This action is an attempt to support its position that the Electric Choice Law needs to be modified to eliminate the “prevailing market prices” standard and replace it with a “lowest reasonable cost” standard, in addition to other anti-competitive proposals that it is supporting.

 

There are no current rate cases or filings at the Pennsylvania PUC which would impact the Company’s financial results.

 

PJM.  PJM, the regional transmission organization, comprising the wholesale transmission system for our retail customers served in Pennsylvania, New Jersey and Maryland, implemented a new Capacity Market design effective June 1, 2007. Known as the Reliability Pricing Model or RPM, this design auctioned generating capacity between sellers and buyers. However, unlike the previous Capacity Market design, RPM divided the PJM system into three geographic zones, and awarded a single-clearing price for each zone and for each year of three years forward. Capacity prices under RPM were significantly higher than seen previously. As a capacity buyer on PJM, this new design made it difficult for us to remain competitive with default or bundled service offerings by the incumbent utility in certain retail markets such as Baltimore Gas & Electric or BGE.

 

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 consumers of Michigan electric distribution utilities, beginning January 1, 2002. We began marketing in Michigan’s Detroit Edison service territory in September 2002.

 

On February 4, 2005, Detroit Edison filed an application to unbundle and realign its electric rates. The application proposed the unbundling of Detroit Edison’s existing rate classes into their cost components attributable to the generation, including transmission, and distribution functions and the phasing out of rate class imbalances relative to cost of service. Detroit Edison explained that its application would allow the utility to unbundle its residential, commercial and industrial retail electric rate schedules into their separate components based on 2004 fully allocated embedded costs.

 

On December 22, 2005, the Michigan Public Service Commission or the MPSC approved Detroit Edison’s filing. The MPSC directed that distribution charges for choice and bundled customers should be brought into parity through aligning their rates, effective February 2006. This order resulted in a rate reduction for bundled commercial and industrial customers. This order had a major impact on Choice customers because the MPSC allowed the utility to shift costs earlier associated with energy charges to the distribution portion of the customer bill. As a result, Choice customers saw an increase in their distribution charges, which ultimately resulted in a “total bill” increase.

 

New efficient meter rules and a removal of Detroit Edison’s stranded cost charge in combination with a higher power cost recovery surcharge is closing the gap between the utility’s rate and the rate offered by suppliers. However, competition has been effectively halted in Michigan due to the design of Detroit Edison’s rate.

 

On April 19, 2007, a package of three pro-competitive bills was introduced in the state Senate. One of those bills was also introduced in the state House of Representatives. These bills are supported by members of the Customer Choice Coalition, an umbrella group of residential, commercial and industrial customers as well as alternate electric suppliers and independent generators. These bills take Michigan’s laws toward allowing choice

and competition in the electric system and open the door to additional movement toward a free market in a deliberate manner.

 

Maryland.  In 1999, the Maryland General Assembly passed the Electric Choice and Competition Act. Part of this Act required that all customers receive a rate reduction, followed by a rate freeze. The rate reduction of 6.5% for BGE customers was based on the last BGE rate case in 1993. The rate freeze in the BGE service territory expired on July 1, 2006. The market price obtained through the standard offer service competitive auction process in the BGE service territory increased 72%. This increase paved the way for Commerce Energy to start offering products to all classes of customers at rates that are market based and highly competitive to BGE’s standard offer service rate. Commerce Energy was licensed by the Maryland PSC on July 7, 2004.

 

In an attempt to mitigate the impact of the BGE rate increase, the Maryland General Assembly in special session in June, 2006 passed Senate Bill One which among other things limited the BGE rate increase to 15% for the period July 1, 2006 through May 31, 2007; however, that limit was imposed as a credit to the utility’s transportation fees and did not affect the commodity price increase.

 

In the closing hours of the 2007 session, the Maryland General Assembly passed SB 400. The bill instructs the PSC to conduct investigatory and evidentiary proceedings including the use of outside experts and consultants to reevaluate the general regulatory structure, agreements, orders and other prior actions of the PSC under the Electric Customer Choice and Competition Act of 1999, including the determination of, and allowances for, stranded costs. The PSC is required to file an interim report on or before December 1, 2007 to the governor and a final report to the General Assembly on or before December 1, 2008.

 

New Jersey.  Deregulation activities began in New Jersey in November 1999 when the Board of Public Utilities or the BPU, approved the implementation plan. Commerce Energy began marketing in New Jersey in the Public Service Gas & Electric Company or PSE&G, service territory in December 2003.

 

Since 2002, the four New Jersey Electric Distribution Companies including PSE&G have procured electric supply to serve their Basic Generation Service or BGS, customers through a statewide auction process held each year in February. BGS customers are customers who are not served by a third party supplier or competitive retailer. The utility uses a rolling procurement structure whereby each year one-third of the load is procured for a three-year period. A portion of the load that was bid on three years ago will come up for re-bidding in 2007. We anticipate that this will cause the auction rate to increase and create a BGS rate that is closer to the current market price.

 

The New Jersey Board of Public Service has proposed revisions to its energy competition standards. The rules will be applicable to electric power suppliers, gas suppliers, BGS providers and basic gas supply service or BGSS providers, electric public utilities, gas public utilities, aggregators, energy agents, energy public utilities and public utility holding companies.

 

The proposed rule changes include anti-slamming provisions, affiliate relations, licensing and registration, government aggregation programs and retail choice consumer protection changes. We believe that we are in compliance with these pending rule changes and see no material impact to our operations.

 

Texas  The Texas deregulation law, or SB7, was enacted in 1999, enabling the Texas electric market to open for retail competition and customer choice on January 1, 2002. On that date Texas consumers could choose their Retail Electric Provider or REP. Commerce Energy began serving electric customers in the Oncor (formerly TXU Electric Delivery) and CenterPoint service territories of ERCOT. On May 16, 2005, we expanded further into the Texas service territories of American Electric Power or AEP, and Texas New Mexico Power or TNMP. On January 1, 2007, the default service known as “Price to Beat” expired under SB7, resulting in full price competition between retailers affiliated with the incumbent utility and non-affiliated retailers. Approximately 55% of retail load, approximately 43% in the residential class alone, has switched to non-affiliated retail electric providers, such as Commerce Energy.

 

Wholesale costs for congestion management, system reliability, and balancing energy on the ERCOT grid may increase to an unknown extent for market participants, such as Commerce Energy. Specifically, cost responsibility and allocation for replacement reserve service, an ancillary service for ERCOT grid operations, continues under policy review in ERCOT’s stakeholder process, along with a proposal to implement “administrative pricing” as an

adder to the balancing energy market price under certain emergency conditions. Whether these costs will be directly assigned to certain market participants, or “uplifted” to all market participants based on a load-ratio share, is unknown and continues under policy development. Our ability to recover these charges from our retail customers is subject to market pricing and competitive forces.

 

ERCOT is expected to shift its current operation of the wholesale transmission system from zonal to nodal design in December 2008. The nodal design will assign congestion costs directly to those responsible, unlike the zonal design in which most congestion costs are “uplifted” to all market participants. However, like the nodal design expected for California, and currently existing in the PJM market, nodal poses systems complexity, higher transaction volumes, and requires greater hedging sophistication for market participants such as Commerce Energy. During the fiscal year ending July 31, 2008, or fiscal 2008, we will be working with our qualified scheduling entity on the ERCOT system to prepare for the nodal design changes.

 

Credit risks have increased for retail electric providers selling to residential customers. Under existing law, Commerce and other retail electric providers can only use electric bill payment history to deny service beginning on January 1, 2007. However, a common database providing electric bill payment history is not available for retail electric providers. Until the database is voluntarily created, or mandated by policy, we will continue to rely on the Public Utility Commission of Texas Customer Protection Rules to manage credit risk. Those rules give us the right to request a deposit or advanced payment and to disconnect for non-payment.

 

Natural Gas

 

Beginning with the Natural Gas Policy Act of 1978, the U.S. Congress initiated a process that ended federal control over the price of natural gas at the wellhead. This ultimately set in motion a series of public policy changes by the FERC and state utility commissions that have resulted in consumer choice programs for all natural gas users in certain states.

 

We serve natural gas customers in 13 utility gas market areas in the following seven states:

 

California.  We currently serve residential and small commercial customers in the Southern California Gas and Pacific Gas & Electric gas markets. We are the only core aggregation transportation provider to residential customers in these market areas. There are no current rate cases or filings pending before the California PUC that are anticipated to impact our financial results.

 

Florida.  In April 2000, the Florida Public Service Commission adopted rules that extend customer choice to all nonresidential users of natural gas in the State regardless of volume. This gives small businesses in Florida the same option that was previously available only to large industrial and commercial customers. The rules also specify that local distribution companies may offer transportation services to residential customers. Commerce Energy’s entry into the Florida natural gas market is a result of the acquisition of commercial and industrial customers purchased from Houston Energy Services Company, L.L.C., or HESCO, completed in September 2006. We operate in four LDC markets in Florida.

 

Georgia.  In 1997, the Georgia General Assembly passed the Georgia Natural Gas Competition and Deregulation Act, or the Georgia Gas Act. The Georgia Gas Act reorganized the Georgia retail natural gas market and allowed natural gas marketers to serve retail consumers. The Georgia Public Service Commission has implemented a comprehensive unbundling program in the state. Over 80% of the state’s residential gas consumers are serviced by certified gas marketers. The ability to disconnect customers for non-payment of invoices is severely constrained by system design and human resource limitations in this market. This may affect our ability to limit losses within this market.

 

Maryland.  In 1997, natural gas choice was brought to Maryland consumers. We provide gas service to residential and small commercial customers in the Baltimore Gas & Electric market area. There are other gas marketers that serve these types of customers. In July 2005, the Maryland Public Service Commission proposed enhanced customer protection rules, yet to be adopted which will be applied to the retail energy market. The approval of these rules will not impact financial results as the Company we are currently compliant.

Nevada.  In 1985, the Nevada State Legislature passed legislation permitting the selling of natural gas as a discretionary service in Nevada. Consequently, industrial and large commercial consumers of natural gas have been able to choose their supplier. Commerce Energy’s entry into the Nevada natural gas market is a result of the acquisition of commercial and industrial customers purchased from Houston Energy Services Company, completed in September 2006. We operate in one LDC market in Nevada.

 

Ohio.  In 1997, natural gas choice programs began in Ohio. We provide gas service to residential and small commercial customers in the Dominion East Ohio, or DEO, and Columbia Gas of Ohio service areas.

 

DEO will exit the merchant function in Ohio, and its plan was approved by the Public Utilities Commission of Ohio, or PUCO, earlier this year. The plan was divided into two sections, Phase I and Phase II. In Phase I, suppliers and marketers bid for supply only. In Phase II, suppliers and marketers will bid to serve any bundled customers remaining with DEO. On August 29, 2006, DEO conducted an auction for pricing of its natural gas wholesale supply of natural gas for the time period October 2006 through August 2008.

 

The auction participants will bid a monthly retail price adjustment to be added to the monthly NYMEX settlement price. The sum of these will become the Standard Offer Service, or SOS, price that will replace the current Gas Cost Recovery, or GCR, rate. The GCR rate has traditionally been calculated on a monthly basis using imbalances from prior months. The new SOS rate will more closely reflect true market costs.

 

It is expected that DEO will be submitting an application to the PUCO by October 31, 2007 for Phase II.

 

Pennsylvania.  In 1997, the natural gas supply service in Pennsylvania was fully opened to competition for all customer classes. The Natural Gas Choice and Competition Act specified that after five years (July 2004) the PUC was to initiate processes to evaluate the competitiveness of natural gas supply services in the state and report its findings to the General Assembly. As a result, the Pennsylvania PUC released a report on its findings in 2006. It was discovered that the State at this time could be more supportive of competition by changing some of the rules and taxes currently imposed on suppliers. A report regarding their findings is expected to be released later this year.

 

Federal Regulations

 

Federal Energy Regulatory Commission

 

We also are subject to regulation by various other federal, state and local governmental agencies. Our electric purchases and sales are subject to the jurisdiction of the Federal Energy Regulatory Commission, or FERC, under the Federal Power Act. We make sales of electricity pursuant to a Power Marketer certificate issued by FERC. While not generally regulating the rates or terms or conditions of electricity sales, FERC has the authority to institute proceedings to identify transactions involving rates that are not just and reasonable due to market manipulation and to reverse or unwind such transactions to ensure just and reasonable rates.

 

The Federal Energy Policy Act of 2005

 

On August 8, 2005, the Energy Policy Act of 2005, or EPA 2005, was signed into law. The scope of EPA 2005 is broad, addressing fossil, nuclear and renewable energy, energy efficiency and tax credits and incentives, across a range of energy producing and consuming sectors. Certain changes mandated by EPA 2005 may have a direct or indirect effect on our business. In particular, provisions intended to enhance the reliability of electric transmission and delivery systems, further the transparency of electricity and natural gas markets, encourage the construction of new electric transmission infrastructure, and facilitate the importation of natural gas should increase the efficiency of the competitive wholesale natural gas and electricity markets in which we participate. Furthermore, effective February 8, 2006, EPA 2005 replaced the Public Utility Holding Company Act of 1935, or PUHCA 1935, with the Public Utility Holding Company Act of 2005, or PUHCA 2005. PUHCA 2005 involves much less extensive regulation than PUHCA 1935, but does include provisions involving FERC access to books and records of public utility holding companies and their affiliates, as well as certain oversight over affiliate transactions. In accordance with EPA 2005, FERC has finalized rules (RM05-32-000) to address certain issues related to implementation of PUHCA 2005, including implementing the Federal access to books and records.

In the past, through a series of no action letters, the U.S. Securities and Exchange Commission, or the SEC, has concluded that electric and gas marketers who did not own or operate electric generation, transmission or distribution facilities or gas retail distribution facilities were not public-utility companies, and their parent companies were not public-utility holding companies, under PUHCA 1935. In its final rule, FERC confirmed that such electric and gas marketers are not public-utility companies under PUHCA 2005, and that their parent companies are not holding companies under PUHCA 2005 (provided such parent companies do not own other entities that would be considered public-utility companies), so they would not be subject to the provisions of the new law.

 

In June 2007, mandatory, enforceable reliability standards were imposed on the bulk power industry under the Energy Policy Act of 2005. The bulk power industry includes power plants and transmission infrastructure. The North American Electric Reliability Corporation or NERC is responsible for developing and enforcing 83 reliability standards. NERC maintains a compliance registry of 1,400 entities, and any violation of the reliability standards can result in enforcement actions and fines. We are not included among the 1,400 entities, but nonetheless believe that such standards will serve to protect the operation of the bulk power system, through which we procure and deliver wholesale power supplies to our retail loads.

 

Intellectual Property

 

Intellectual property assets include our proprietary software and service products, our registered trademarks (electricAmerica^®, Green Smart^®, 1-800-Electric^®, electric.com^®, capacitycenter.com^® and Utilihost, Inc.^®), our 1-800-Electric telephone number and rights to our internet domain names electric.com, commerceenergy.com and electricAmerica.com. We believe that each of our intellectual property assets offers us strategic advantages in our operations.

 

Our strategy for protection of our trademarks is to routinely file U.S. federal and foreign trademark applications for the various word names and logos used to market our services to licensees and the general public. The duration of the U.S. and foreign registered trademarks can typically be maintained indefinitely, provided proper fees are paid and trademarks are continually used or licensed by us.

 

Employees

 

As of July 31, 2007, we employed 255 full-time employees, including 45 in administration, 50 in marketing and sales, and 160 in operations. Our employees are not covered by a collective bargaining agreement or represented by a labor union. We have not experienced any work stoppages and consider our employee relations to be good.

 

Available Information

 

Our Internet address is www.CommerceEnergy.com. There, we make available, free of charge, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Our SEC reports can be accessed through the Investor Relations section of our Web site. The other information found on our Web site is not part of this or any other report we file or furnish to the SEC.

 

Any of the materials we file with the SEC may also be read and copied at the SEC’s Public Reference Room at 100 F Street, NE, Washington, D.C. 20549. Information on the operation of the SEC’s Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC maintains an Internet website that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at http://www.sec.gov.

 

 

If competitive restructuring of the retail energy market is delayed or does not result in viable competitive market rules, our business will be adversely affected.

 

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

 

Retail energy market restructuring has been and will continue to be a complicated regulatory process, with competing interests advanced not only by relevant state and federal utility regulators, but also by state legislators, federal legislators, local utilities, consumer advocacy groups and other market participants. As a result, the extent to which there are legitimate competitive opportunities for alternative energy suppliers in a given jurisdiction may vary widely, and we cannot be assured that regulatory structures will offer us competitive opportunities to sell energy to consumers on a profitable basis. The regulatory process could be negatively impacted by a number of factors, including interruptions of service and significant or rapid price increases. The legislative and regulatory processes in some states take prolonged periods of time. In a number of jurisdictions, it may be many years from the date legislation is enacted until the retail markets are truly open for competition.

 

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

 

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

 

We face many uncertainties that may cause substantial operating losses and we cannot assure stockholders that we can achieve and maintain profitability.

 

We intend to increase our operating expenses to develop and expand our business, including brand development, marketing and other promotional activities and the continued development of our billing, customer care and power procurement infrastructure. Our ability to operate profitably will depend on, among other things:

 

 

We may have difficulty obtaining a sufficient number of customers.

 

We anticipate that we will incur significant costs as we enter new markets and pursue customers by utilizing a variety of marketing methods. In order for us to recover these expenses, we must attract and retain a large number of customers to our service.

 

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

 

We depend upon internally developed, and, in the future will rely in part on vendor-developed, systems and processes to provide several critical functions for our business, and the loss of these functions could materially adversely impact our business.

 

We have developed our own systems and processes to operate our back-office functions, including customer enrollment, metering, forecasting, settlement and billing. We are currently in the process of replacing a number of our internally developed legacy software systems with vendor-developed systems. Problems that arise with the performance of such back-office functions could result in increased expenditures, delays in the launch of our commercial operations into new markets, or unfavorable customer experiences that could materially adversely affect our business strategy. Any interruption of these services could also be disruptive to our business. As we transition from our own systems to new vendor-developed systems, we may incur duplicative expenses for a period of time, and we may experience installation and integration issues with the new systems or delays in the implementation of the new systems. If we experience some or all of these new system implementation risks and these result in unreliable or inaccurate data for our financial reporting, we may not be able to establish a sufficient operating history for Sarbanes-Oxley 404 attestation requirements, which we expect we must meet by no later than fiscal year ending July 31, 2008 for management’s attestation, and July 31, 2009 for the attestation of our independent auditors. Should our market capitalization exceed $75 million (as defined) on January 31, 2008, we would require the attestation of our independent accountants on July 31, 2008.

 

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

 

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

 

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

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

 

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

 

The terms of our asset-based credit facility restrict, among other things, our ability to incur additional indebtedness, pay dividends or make certain other restricted payments, consummate certain asset sales, enter into certain transactions with affiliates, merge or consolidate with other persons or sell, assign, transfer, lease, converge or otherwise dispose of all or substantially all of our assets. Further, we and our subsidiary, Commerce Energy, are required to maintain specified financial ratios and satisfy certain financial condition tests. Our ability and Commerce Energy’s ability to meet those financial ratios and tests can be affected by events beyond our ability and control, respectively, and there can be no assurance that we will meet those tests. Substantially all of our assets and our operating subsidiaries’ assets are pledged as security under our asset-based credit facility.

 

We may need additional capital in the future and it may not be available on acceptable terms, or not at all.

 

In the future, we may need to raise additional capital to fund the working capital requirements of our operations and growth, enhance or expand the range of services or products we offer to our customers, or respond to competitive pressures or perceived opportunities, such as investment, acquisition and expansion activities; if such additional capital funds are not available when required or on acceptable terms, our business and financial results could suffer.

 

We may issue additional shares of common stock that may dilute the value of our common stock and adversely affect the market price of our common stock.

 

In addition to the approximately 30.4 million shares of our common stock outstanding at July 31, 2007, we may issue additional shares of common stock in the following scenarios: a significant number of additional shares of our common stock may be issued if we seek to raise capital through offerings of our common stock, securities convertible into our common stock, or rights to acquire such securities of our common stock. Additionally, as of July 31, 2007, we may issue approximately 7.0 million shares of our common stock pursuant to outstanding stock options; and 1.0 million shares of our common stock pursuant to awards under our 2006 Stock Incentive Plan.

 

A large issuance of shares of our common stock will decrease the ownership percentage of current outstanding shareholders and may result in a decrease in the market price of our common stock. Any large issuance may also result in a change in control of the Company.

 

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.

 

If the market price of wholesale electricity decreases below the price of the electricity we purchase under long-term contracts, the power suppliers may require us to post margin in the form of a letters of credit, or other collateral, to protect them against our potential default on the contract. If we are required to post such security, it could adversely affect our liquidity.

 

Some suppliers of electricity have been experiencing deteriorating credit quality.

 

We continue to monitor the credit quality of our energy suppliers to attempt to reduce the impact of any potential counterparty default. As of July 31, 2007, the majority of our counterparties are rated investment grade or above by the major rating agencies. These ratings are subject to change at any time with no advance warning. Deterioration in the credit quality of our energy suppliers could have an adverse impact on our sources of electricity purchases.

 

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

 

Under the regulatory structures adopted in most jurisdictions, we are required to enter into agreements with local utilities for use of the local distribution systems, and for the creation and operation of functional interfaces necessary for us to serve our customers. Any delay in these negotiations or our inability to enter into reasonable

agreements with those utilities could delay or negatively impact our ability to serve customers in those jurisdictions. This could have a material negative impact on our business, results of operations and financial condition.

 

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

 

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

 

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

 

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

 

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

 

In California, the FERC and other regulatory and judicial bodies continue to examine the behavior of market participants during the California Energy Crisis of 2000 and 2001, and to recalculate what market clearing and bi-lateral contract prices should have or might have been under alternative scenarios of behavior by market participants. In the event the historical costs of market operations were to be reallocated among market participants or recalculated in the event of bi-lateral contracts, this could have a material adverse financial impact on us, but the extent of any such amount cannot be predicted. Please see the discussion under Part 1, Item 1. Business — Governmental Regulation — Electricity — California.

 

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

 

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

 

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

 

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

 

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

 

 

 

We may experience difficulty in successfully identifying, integrating and managing the risks related to businesses or assets that we may acquire and in realizing the anticipated economic benefits related thereto.

 

We do not have a great deal of experience acquiring companies or large blocks of assets, and the companies and assets we have acquired have been small. We have evaluated, and expect to continue to evaluate, a wide array of potential strategic transactions. From time to time, we may engage in discussions regarding potential acquisitions. Any of these transactions could be material to our financial condition and results of operations. In addition, the process of integrating an acquired company, business or group of assets may create unforeseen operating difficulties and expenditures and risk. The areas where we may face risks include:

 

 

Also, the anticipated benefit of many of our acquisitions may not materialize. Future acquisitions or dispositions could result in potentially dilutive issuances of our equity securities, the incurrence of additional debt, contingent liabilities or amortization expenses, or write-offs of goodwill, any of which could harm our financial condition. Future acquisitions may require us to obtain additional equity or debt financing, which may not be available on favorable terms or at all.

 

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.

 

We purchase substantially all of our power and natural gas under forward physical delivery contracts, which are defined as commodity derivative contracts under SFAS No. 133. We also utilize other financial derivatives, primarily swaps, options and futures, to hedge our price risks. Accordingly, proper accounting for these contracts is very important to our overall ability to report timely and accurate financial results.

 

We have devoted significant resources to remediate and improve our internal controls. Although we believe that these efforts have strengthened our internal controls and addressed the concerns that gave rise to reportable conditions and material weaknesses in fiscal 2004 and 2005, we are continuing to work to improve our internal controls, particularly

in the area of energy accounting. We cannot be certain that these measures will ensure that we implement and maintain adequate controls over our financial processes and reporting in the future. Any failure to implement required new or improved controls, or difficulties encountered in their implementation, could harm our operating results or cause us to fail to meet our reporting obligations. Inferior internal controls could also cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our stock.

 

Investor confidence and share value may be adversely impacted if our independent registered public accountants are unable to provide us with the attestation of the adequacy of our internal controls over financial reporting, 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 us, as a public company to include a report in our Annual Report on Form 10-K that contains an assessment by management of the effectiveness of our internal controls over financial reporting for fiscal 2008. In addition, our independent registered public accountants must attest to and report on the effectiveness of our internal controls over financial reporting. The requirement pertaining to our independent registered public accountant’s attestation report may initially apply to our Annual Report on Form 10-K for the fiscal year ending July 31, 2008, if our market capitalization (as defined) exceeds $75 million on January 31, 2008. How companies implement these requirements, including internal control revisions, if any, to comply with Section 404’s requirements, and how independent registered public accountants will apply these new requirements and test companies’ internal controls, are continually evolving. Although we are diligently and vigorously reviewing our internal controls over financial reporting to comply with the new Section 404 requirements, we cannot be certain as to the outcome of the testing of our internal controls and any remediation efforts that may be needed. When independent registered public accountant attestation is required, there is the risk that our independent registered public accountants may not be satisfied with our internal controls over financial reporting or the level at which these controls are documented, designed, operated or reviewed, or that the independent registered public accountants interpret the requirements, rules or regulations differently than we do. 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.

 

 

Not Applicable.

 

 

Information About Our Executive Officers

 

The following table sets forth information regarding our executive officers, including their respective business experience during the last five years and age as of October 16, 2007. Executive officers are elected by, and serve at the pleasure of, the Board of Directors. There are no arrangements or understandings pursuant to which any of the persons listed below was selected as an executive officer.

 

 

 

We sublease approximately 39,000 square feet of office space in Costa Mesa, California, which houses our principal executive offices and administrative and operations space. This lease expires in September 2009. We also lease approximately 17,000 square feet of office space in Irving, Texas which expires in January 2010 and lease office space in Boston, Massachusetts and Houston, Texas. The Boston office consists of approximately 3,200 square feet under a lease that expires in June 2010, and the Houston office consists of approximately 5,000 square feet under a lease that expires in September 2009.

We believe that our current facilities are sufficient for the operation of our business, and we believe that suitable additional space in various local markets is available to accommodate any needs that may arise.

 

 

American Communications Network

 

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

 

On March 23, 2006, Commerce Energy filed a Demand for Arbitration with the AAA in New York of this dispute, asserting claims for declaratory relief, material breach of contract and breach of the implied covenant of good faith and fair dealing. Our Demand for Arbitration sought compensatory damages in an amount to be determined at the arbitration. On May 4, 2006, ACN filed with the AAA in New York its Demand for Arbitration of this dispute with the Commerce Energy. In its Demand, ACN alleges claims against Commerce Energy for breach of contract and breach of implied duty of good faith and fair dealing, seeking damages and restitution in amounts to be determined at the hearing.

 

On June 11, 2007, the Company, Commerce Energy, Peter Weigand, an individual, and ACN, entered into a Settlement Agreement and Mutual Release or the Settlement Agreement. Pursuant to the Settlement Agreement, Commerce and ACN mutually released all claims against one another, and Commerce made a cash payment of $3.9 million to ACN. In addition, the Company, Commerce Energy and ACN have filed with the American Arbitration Association a Stipulation to Dismiss All Claims with Prejudice relating to the pending arbitration proceeding between the Company, Commerce Energy and ACN, Case No. 13 198 Y 00688 06. Pursuant to the Settlement Agreement, the Company and Commerce Energy have no future financial or other obligations to ACN, other than customary covenants set forth in the Settlement Agreement.

 

California Refund Case

 

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 FERC by San Diego Gas and 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 CPX, and the CAISO, markets, Docket No. EL00-95; which we refer to as the California Refund Case. A part of that proceeding related to APX’s involvement in those markets.

 

On January 5, 2007, APX, we and certain other parties, whom we refer to as the Settling Parties, signed an APX Settlement and Release of Claims Agreement, or the APX Settlement Agreement, and filed such agreement along with a Joint Offer of Settlement and Motion for Expedited Consideration with FERC in the California Refund Case. The APX Settlement Agreement, among other things, established a mechanism for allocating refunds owed to APX and to resolve certain other matters and claims related to APX’s participation in the CPX and CAISO centralized spot markets for wholesale electricity from May 1, 2000 through June 20, 2001. The APX Settlement Agreement became effective on March 1, 2007.

 

Under the APX Settlement Agreement, several Settling Parties are entitled to payments from APX, with Commerce expected to receive up to approximately $6.5 million. We received $5.1 million of the settlement payment in April 2007 and received the remaining $1.4 million in August 2007. By entering into the APX Settlement Agreement, claims against us by any party to the APX Settlement Agreement for refunds, disgorgement of profits or other monetary or non-monetary remedies for APX-related claims shall be deemed resolved with prejudice and settled insofar as APX remains a net payment recipient (as that term is defined in the APX Settlement Agreement) in the proceeding at FERC.

In addition, the APX Settlement Agreement resolves and terminates certain disputes pending before FERC and the United States Court of Appeals for the Ninth Circuit relating to APX’s actions in the PX and CAISO centralized spot markets for wholesale electricity, as well as disputes among participants in the APX market and the appropriate allocation of monies due among the APX participants insofar as APX continues to be a net refund recipient (as that term is defined in the APX Settlement Agreement) during the settlement period.

 

The Settlement Agreement is subject to possible court review. We could be required to return or redistribute some or all of the funds received under the Settlement Agreement. Also see Part 1, Item 1. Business — Governmental Regulation — Electricity — California.

 

Lawrence Clayton, Jr.

 

On August 5, 2007, we received a statement of claims against us, which also references certain of our officers and directors, on behalf of Lawrence Clayton, Jr., the former Senior Vice President, Chief Financial Officer and Secretary of the Company, in connection with Mr. Clayton’s termination on July 25, 2007. In his statement of claims, Mr. Clayton disputes the basis for his termination. The principal relief sought by Mr. Clayton is a lump sum payment of approximately $1.6 million. In accordance with the dispute resolution procedure set forth in his employment agreement with the Company, a mediator has been selected for the resolution of this dispute and a mediation session has been scheduled to be held in November 2007. In the event that the mediation is not successful, the parties have agreed to binding arbitration pursuant to the Employment Dispute Rules of Judicial Arbitration and Mediation Services, Inc. We believe that no severance payments or other obligations were due to Mr. Clayton upon his termination and the Company has not accrued for such payments or any other litigation-related amounts. We intend to vigorously defend Mr. Clayton’s claims.

 

Other Matters

 

We currently are, and from time to time may become, involved in litigation concerning claims arising out of our operations in the normal course of business. While we cannot predict the ultimate outcome of our pending matters or how they will affect our results of operations or financial position, our management currently does not expect any of the legal proceedings to which we are currently a party, including the above-referenced claims raised by Mr. Clayton, to have a material adverse effect on our results of operations or financial position.

 

 

No matters were submitted to security holders in the fourth quarter of fiscal 2007.

 

PART II

 

 

Market Information

 

On July 8, 2004, our common stock began trading on the American Stock Exchange under the symbol “EGR.” The following table sets forth, the high and low sales price per share of common stock for the periods indicated, as reported on the American Stock Exchange:

 

 

 

On October 16, 2007, the high and low sales price per share on the American Stock Exchange for our common stock was $2.23 and $2.15, respectively.

 

Holders

 

On October 16, 2007, there were 1,600 holders of record of our Common Stock.

 

Dividend Policy

 

We have not declared or paid a cash dividend on our common stock, and we do not anticipate paying any cash dividends for the foreseeable future. We presently intend to retain earnings to grow our customer base, finance future operations, and make capital investments.

 

Our asset-based credit facility restricts our ability to pay cash dividends on our common stock and restricts the ability of our principal operating subsidiary Commerce Energy to pay dividends to us without the lenders’ consent. See “Credit Facility” within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 of this Annual Report on Form 10-K and Note 4 to the Notes to the Consolidated Financial Statements.

 

Equity Compensation Plan Information

 

Information concerning securities authorized for issuance under our equity compensation plans is set forth in Part III, Item 12 of this Annual Report on Form 10-K under the caption. “Securities Authorized for Issuance under Equity Compensation Plans,” and that information is incorporated herein by reference.

 

Recent Sales of Unregistered Securities

 

None.

 

Purchase of Equity Securities

 

None.

Performance Graph

 

The following performance graph shall not be deemed incorporated by reference by any general statement incorporating by reference this Annual Report on Form 10-K into any filing under the Securities Act of 1933, as amended, or under the Securities Exchange Act of 1934, as amended, except to the extent that the Company specifically incorporates this information by reference, and shall not otherwise be deemed filed under such Acts.

 

The Common Stock commenced trading on the American Stock Exchange on July 8, 2004. The last trading day of the Company’s fiscal year 2007 was July 31, 2007.

 

Comparison of Initial Trading Period Cumulative Return The comparisons in this table are required by the SEC and, therefore, are not intended to forecast or be indicative of possible future performance of the Common Stock.

 

The performance graph below illustrates a comparison of cumulative total returns based on an initial investment of $100 in the Common Stock as traded on the American Stock Exchange from July 31, 2004 to July 31, 2007, as compared with the S&P 500 Stock Index and the Utility Select Sector Index for the same period. The Utility Select Sector Index is a modified market capitalization based index intended to track the movement of companies that are components of the S&P 500 index and are utilities. Utilities include communications services, electrical power providers and natural gas distributors.

 

This performance chart assumes:

 

 

 

Value of Investment

 

 

The selected financial data in the following table sets forth (a) balance sheet data as of July 31, 2007 and 2006, and statements of operations data for the fiscal years ended July 31, 2007, 2006 and 2005 derived from our audited consolidated financial statements, which were audited by an independent registered public accounting firm, for the fiscal year ended July 31, 2005, and audited by Hein & Associates LLP, independent registered public accounting firm, for the fiscal year ended July 31, 2007 and 2006, which are included elsewhere in this filing, and (b) balance sheet data as of July 31, 2005, 2004 and 2003, and statements of operations data for the fiscal years ended July 31, 2004 and 2003, derived from our audited consolidated financial statements, which were audited by an independent registered public accounting firm, which are not included in this filing. The information below should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of this Annual Report on Form 10-K and our consolidated financial statements and the related notes thereto set forth herein.

 

 

 

 

We are an independent marketer of electricity and natural gas to end-user customers. As of July 31, 2007, we provided retail electricity and natural gas to residential, commercial, industrial and institutional customers in ten states. Our principal operating subsidiary, Commerce Energy, Inc., is licensed by the Federal Energy Regulatory Commission, or FERC, and by state regulatory agencies as an unregulated retail marketer of natural gas and electricity.

 

We were founded in 1997 as a retail electricity marketer in California. As of July 31, 2007, we supplied electricity to approximately 136,200 customers in California, Maryland, Michigan, New Jersey, Pennsylvania and Texas; and natural gas to approximately 59,300 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 transmission facilities, natural gas producing properties or pipelines. The electricity and natural gas we sell is generally metered and delivered to our customers by 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 retail business depends upon a number of factors, including the degree of deregulation in each state, our ability to acquire new customers and retain existing customers and our ability to acquire energy for our customers at competitive prices and on favorable credit terms.

 

APX Settlement

 

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. Subsequently, in April 2007, we received a payment of $5.1 million and the remaining settlement payment of $1.4 million in August 2007.

 

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.

 

ACN Energy Transaction

 

On February 9, 2005, we acquired certain assets of ACN Utility Services, Inc. or ACNU, a subsidiary of American Communications Network, Inc. or ACN, and its retail electricity business in Texas and Pennsylvania and its retail natural gas business in California, Georgia, Maryland, New York, Ohio and Pennsylvania. The aggregate

purchase price was $14.5 million in cash and 930,233 shares of our common stock, valued at $2.0 million. The common stock payment was contingent upon ACN meeting certain sales requirements during the year following the acquisition date. These sales requirements were not met and the shares were cancelled in April 2006. As a result, both goodwill and common stock were reduced by $2.0 million. We refer to this acquisition as the ACN Energy Transaction and the assets acquired as the ACN Energy Assets.

 

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

 

Market and Regulatory

 

As of July 31, 2007, we served electricity and gas customers in 10 states, operating within the jurisdictional territory of 22 different local utilities or LDCs. Among other things, tariff filings by these LDCs for changes in their allowed billing rate to their customers in the markets in which we operate, significantly impact the viability of our sales and marketing plans and our overall operating and financial results. Although regulatory requirements are determined by each state jurisdiction, and administered and monitored by state regulatory commissions, typically known as the PUC, operating rules and rate filings for each LDC even within the same state, are unique. Accordingly, we generally treat each LDC distribution territory as a distinct market.

 

Electricity

 

As of July 31, 2007, we marketed electricity in 12 LDC markets within the 6 states of California, Maryland, Michigan, New Jersey, Pennsylvania, and Texas.

 

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

 

Currently, several important rules are under review by the CPUC, including the Resource Adequacy Requirement and the Renewable Portfolio Standard. Additional costs to serve customers in California are anticipated from these proceedings; however, the CPUC decisions will determine the allocation of costs across all market participants. We cannot currently estimate the impact that these issues and anticipated additional costs may have on our future financial results.

 

In connection with FERC’s determination of the amounts of refunds due to California energy buyers for purchases made in the spot markets operated by the CAISO and the California PX during the period October 2, 2000 through June 20, 2001, referred to as the “refund period,” FERC has issued dozens of orders, most of which have been taken up on appeal before the United States Court of Appeals for the Ninth Circuit. Two of the cases, Lockyer v. FERC and CPUC v. FERC each present issues which may have an adverse financial impact upon us; however, at this time, we are unable to predict either the outcome of the proceedings or the ultimate financial effect on us.

 

Lockyer v. FERC.  On September 9, 2004, the Ninth Circuit issued a decision on the California Attorney General’s challenge to the validity of FERC’s market-based rate system. This case was originally presented to FERC upon complaint that the adoption and implementation of market based rate authority was flawed. FERC dismissed the complaint after sellers refiled reports of sales in the CAISO and the California PX spot markets and bilateral sales to California Department of Water Resources during 2000 and 2001. The Ninth Circuit upheld FERC’s authority to authorize sales of electric energy at market-based rates, but found that the requirement that sales at market-based rates be reported quarterly to FERC for individual transactions is integral to a market-based rate regime. The State of California, among others, has publicly interpreted the decision as providing authority to FERC to order refunds for different time frames and based on different rationales than are currently pending in the

California Refund Proceedings, discussed in the immediately proceeding paragraph The decision remands to FERC the question of whether, and in what circumstances, to impose refunds or other remedies for any alleged failure to report sales transactions to FERC. On December 28, 2006, several energy sellers filed a petition for a writ of certiorari to the U.S. Supreme Court. The U.S. Supreme Court denied the petition. We cannot predict the scope or nature of, or ultimate resolution of this case.

 

CPUC v. FERC.  On August 2, 2006, after reviewing certain FERC decisions in the California Refund Proceedings, the Ninth Circuit decided that FERC erred in excluding potential relief for alleged tariff violations related to transactions in the CAISO and the California PX markets for periods that pre-dated October 2, 2000 and additionally ruled that FERC should consider remedies for certain bilateral transactions with the California Department of Water Resources previously considered outside the scope of the proceedings. The decision may expose Commerce to claims or liabilities for transactions outside the previously defined “refund period.” At this time, the ultimate financial outcome for us is unclear.

 

There are proceedings and cases in other states in which we sell electricity, that could impact our financial results, but we are actively engaged in advocacy or coalition groups to mitigate any adverse policy outcomes.

 

Natural Gas

 

As of July 31, 2007, we marketed natural gas in 13 LDC markets within the seven states of California, Florida, Georgia, Maryland, Nevada, Ohio and Pennsylvania. Due to significant increases in the price of natural gas, a number of LDCs have filed or communicated expectations of filing for approval of rate increases to their customers. Although the impact of these filings cannot currently be estimated, they are not anticipated to adversely impact our financial results.

 

In 1997, natural gas choice programs began in Ohio. We provide gas service to residential and small commercial customers in the Dominion East Ohio, or DEO, and Columbia Gas of Ohio service areas.

 

DEO will exit the merchant function in Ohio, and its plan was approved by the Public Utilities Commission of Ohio, or PUCO, earlier this year. The plan was divided into two sections, Phase I and Phase II. In Phase I, suppliers and marketers bid for supply only. In Phase II, suppliers and marketers will bid to serve any bundled customers remaining with DEO. On August 29, 2006, DEO conducted an auction for pricing of its natural gas wholesale supply of natural gas for the time period October 2006 through August 2008.

 

The auction participants will bid a monthly retail price adjustment to be added to the monthly NYMEX settlement price. The sum of these will become the Standard Offer Service, or SOS, price that will replace the current Gas Cost Recovery, or GCR, rate. The GCR rate has traditionally been calculated on a monthly basis using imbalances from prior months. The new SOS rate will more closely reflect true market costs.

 

It is expected that DEO will be submitting an application to the PUCO by October 31, 2007 for Phase II.

Results of Operations

 

The following table summarizes the results of our operations for fiscal 2007, fiscal 2006, and fiscal 2005 (dollars in thousands):

 

 

 

 

Fiscal Year Ended July 31, 2007 Compared to Fiscal Year Ended July 31, 2006

 

Operating results for fiscal 2007 reflect income from operations of $9.3 million compared to a loss of $3.4 million for fiscal 2006. The principal reasons for the increase in income from operations was a $28.5 million increase in gross profit and partially offset by a $15.7 million increase in total operating expenses, comprised of selling and marketing expenses and general and administrative expenses. Our net income for fiscal 2007 was $5.5 million, compared to a net loss of $2.2 million in fiscal 2006, reflecting the improvement in operating results.

 

Gross profit increased $28.5 million to $57.2 million for fiscal 2007 from $28.8 million for fiscal 2006. Gross profit for fiscal 2007 includes $6.5 million for the APX Settlement. Gross profit from electricity totaled $46.6 million for fiscal 2007 compared to $22.9 million for fiscal 2006, reflecting the impact of customer growth in the Texas and Maryland markets. Gross profit for natural gas totaled $10.6 million for fiscal 2007 compared to $5.9 million for fiscal 2006. The increase in gross profit from natural gas reflected the impact of (i) customer growth in the Ohio markets; (ii) gross margin contribution from the commercial and industrial natural gas customers acquired in the September 2006 HESCO acquisition; and (iii) a mark-to-market loss incurred in the second quarter of fiscal 2006 on natural gas supply contracts.

Net revenue

 

The following table summarizes net revenues for fiscal 2007 and 2006 (dollars in thousands):

 

 

Net revenues increased $124.5 million, or 50%, to $371.6 million for fiscal 2007 from $247.1 million for fiscal 2006. The increase in net revenues was driven primarily by a 34% increase in electricity sales, a 104% increase in natural gas sales and the APX Settlement. Higher electricity sales reflects the impact of a 300% increase in sales volumes in Texas due to customer growth, partly offset by lower retail sales in the Pennsylvania/New Jersey and Michigan markets resulting from customer attrition. Higher natural gas sales primarily reflect the impact of the September 2006 acquisition of the HESCO customers.

 

Retail electricity sales increased $60.3 million to $236.6 million for fiscal 2007 from $176.3 million for fiscal 2006 reflecting both the impact of 16% higher sales prices, and a 16% increase in sales volume. For fiscal 2007, we sold 2,057 million kilowatt hours, or kWh, at an average retail price per kWh of $0.115, as compared to 1,767 million kWh sold at an average retail price per kWh of $0.099 in fiscal 2006. Excess electricity sales for fiscal 2007 decreased $6.1 million compared to fiscal 2006 reflecting the impact of shorter term forward supply commitments due primarily to higher wholesale electricity prices and increased price volatility.

 

Natural gas sales increased $64.3 million to $126.0 million for fiscal 2007 from $61.7 million for fiscal 2006 reflecting the impact of sales to customers acquired in the September 2006 the HESCO acquisition. In fiscal 2007, we sold 14.8 million dekatherms, or DTH, at an average retail price per DTH of $8.51, as compared to 5.2 million DTH, sold at an average retail price per DTH of $12.00 during fiscal 2006. From the date of the HESCO acquisition in September 2006 through July 31, 2007, natural gas sales to the customers that we acquired in that acquisition totaled $64.8 million on sales volume of 8.8 million DTH or $7.37 per DTH.

 

We had approximately 136,200 and 80,000 retail electricity customers at both July 31, 2007 and 2006, respectively, and approximately 59,300 and 57,000 natural gas customers at July 31, 2007 and 2006, respectively.

Direct energy costs

 

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

 

Direct energy costs for fiscal 2007 totaled $198.9 million and $115.4 million for electricity and natural gas, respectively, compared to $162.5 million and $55.8 million, respectively, for fiscal 2006. The increase in electricity costs is primarily due to a 16% increase in sales volume and an 11% increase in price. Electricity costs averaged $0.097 per kWh for fiscal 2007 compared to $0.087 per kWh for fiscal 2006. The increase in natural gas costs is primarily due to a 184% increase in sales volume reflecting the impact of the HESCO acquisition offset by a 28% decrease in price. Direct energy costs for natural gas averaged $7.79 per DTH for fiscal 2007 as compared to $10.85 per DTH in fiscal 2006.

 

Operating expenses

 

Selling and marketing expenses were $10.6 million for fiscal 2007, an increase of $5.4 million from $5.2 million for fiscal 2006, reflecting the impact of higher cost of advertising and sales programs, telemarketing, third-party commissions and direct mail costs related to the Company’s increased customer acquisition initiatives. These higher costs due to increased customer acquisition initiatives were partly offset by lower payroll costs.

 

General and administrative expenses were $37.3 million for fiscal 2007, an increase of $10.4 million, from $26.9 million for fiscal 2006, reflecting higher customer service, and information technology personnel costs, incentive compensation costs, and increased consulting expenses.

 

Other expenses

 

On June 11, 2007, Commerce Energy and ACN entered into an agreement settling all arbitration claims and disputes. The total agreed upon settlement of $3.9 million was paid and recorded in April 2007. Related legal fees of $0.7 million were included in general and administrative expenses.

 

Interest income

 

Our interest income was $1.3 million for fiscal 2007, an increase of $0.2 million from $1.1 million in fiscal 2006. The increase was primarily higher market yields realized on investments offset in part by lower investable balances.

 

Interest Expense

 

Our interest expense was $1.1 million for fiscal 2007, primarily due to recording all costs of our new credit facility as interest expense in accordance with FAS 91.

 

Income before Provision for Income Taxes

 

Our income before provision for income taxes was $5.7 million for fiscal 2007 an increase of $7.9 million, from $2.2 million loss for fiscal 2006, as a result of the items discussed above.

 

Provision for Income Taxes

 

We have a provision for income taxes for fiscal 2007 of $0.1 million, compared to none from the prior year. This amount reflects the application of Alternative Minimum Tax to the portion of our current year tax basis income which cannot be offset by our tax loss carryforwards. As a result, our effective income tax rate for fiscal 2007 was 2.2% compared to 0.0% for fiscal 2006.

Year Ended July 31, 2006 Compared to Year Ended July 31, 2005

 

Operating results for fiscal 2006 reflect a loss from operations of $3.4 million compared to a loss of $7.4 million for fiscal 2005. The principal reasons for the decrease in the loss from operations was a $0.6 million increase in gross profit and a $3.5 million decrease in total operating expenses, comprised of selling and marketing expenses, and general and administrative expenses. Our net loss for fiscal 2006 was $2.2 million, compared to a net loss of $6.1 million in fiscal 2005, reflecting the reduction in the loss from operations.

 

Gross profit for fiscal 2006 was $28.8 million, a 2% increase compared to gross profit of $28.2 million in fiscal 2005. Gross profit for fiscal 2005 included a gain of $7.2 million from the sale of electricity supply contracts in Pennsylvania. Gross profit from electricity sales for fiscal 2006 was down slightly from fiscal 2005, as the impact of higher gross margins on lower electricity sales volumes, due primarily to customer attrition, in our Pennsylvania and Michigan markets was less than the prior year. The lower gross profit from electricity was offset by a $1.3 million increase in gross profit from natural gas operations, reflecting a full year of operations in fiscal 2006 as compared to six months in fiscal 2005.

 

Net revenue

 

The following table summarizes net revenues for fiscal 2006 and 2005 (dollars in thousands):

 

 

Net revenues for fiscal 2006 were $247.1 million, a 3% or $6.8 million decrease from fiscal 2005. The decrease in net revenue was primarily attributable to:

 

(i) a $32.4 million decrease in excess energy sales reflecting the impact of shorter-term forward supply commitments resulting from significant increases in the volatility and price of wholesale electricity and the conversion of many retail customers to month-to-month variable priced sales contracts.

 

(ii) excess energy sales during fiscal 2005 including $9.3 million realized on the January 2005 sale of Pennsylvania electricity supply contracts back to the original supplier;

 

(iii) a $10.1 million decrease in retail electricity sales due to the impact of customer attrition and related lower sales volumes in the in Pennsylvania/New Jersey and Michigan markets, partly offset by increased sales volumes in Texas in fiscal 2006 due to a full year of operations and customer growth; and

(iv) a $36.2 million increase in natural gas sales due to a full year of operations as compared to six months of operations in fiscal 2005.

 

Retail electricity sales for fiscal 2006 were $176.3 million, a 5% decrease from fiscal 2005 reflecting a 33% decline in electric sales volumes partly offset by higher retail sales prices. In fiscal 2006, we sold 1,767 million kWh, at an average retail price per kWh of $0.099, as compared to 2,631 million kWh sold at an average retail price per kWh of $0.071 in fiscal 2005. California sales volumes decreased to 759 million kWh (average sales price per kWh of $0.088) in fiscal 2006 as compared to 819 million kWh (average price per kWh of $0.078) in fiscal 2005 due principally to normal customer attrition. Pennsylvania and New Jersey’s combined sales volumes in fiscal 2006 decreased 50% to 565 million kWh (average price per kWh of $0.112) as compared to 1,137 million kWh (average price of $0.067) in fiscal 2005. Sales volumes in Michigan in fiscal 2006 decreased 58% to 253 million kWh (average price per kWh of $0.083) as compared to 603 million kWh (average price per kWh of $0.061) in fiscal 2005. Sales volumes declines in both our Pennsylvania/New Jersey and Michigan markets reflect the impact of high customer attrition resulting from unfavorable competitive and regulatory changes leading to the return of customers to the incumbent utility. Texas sales volumes in fiscal 2006 increased to 190 million kWh (average sales price per kWh of $0.131) as compared to 72 million kWh in fiscal 2005 (average price per kWh of $0.130) reflecting the full year impact of the customers acquired in February 2005 and the impact of sales, marketing and customer acquisition initiatives in this market during the second half of fiscal 2006.

 

Natural gas sales for fiscal 2006 were $61.7 million, an increase of $36.2 million, or 142%, compared to 2005, reflecting a full year of these operations compared to only six months during fiscal 2005. During fiscal 2006, we sold approximately 5.1 million DTH at an average price of $12.00 per DTH as compared to 2.5 million at an average price of $10.26 per DTH in fiscal 2005.

 

We had approximately 80,000 retail electricity customers at both July 31, 2006 and 2005 and approximately 57,000 and 60,000 natural gas customers at July 31, 2006 and July 31, 2005, respectively.

 

Direct energy costs

 

Direct energy costs for fiscal 2006 totaled $218.3 million, a decrease of $7.4 million or 3% from fiscal 2005, and was comprised of $162.5 million for electricity and $55.8 million for natural gas. Electricity cost decreased 21% from fiscal 2005 due primarily to a 33% decline in retail sales volumes and lower excess energy sold. The average cost of electricity increased to $0.087 per kWh for fiscal 2006 as compared to $0.065 per kWh for fiscal 2005. The decrease in the total cost of electricity during fiscal 2006 was largely offset by a 170% increase in the cost of natural gas, reflecting a 107% increase in retail sales volumes due to a full year of natural gas operations in fiscal 2006 as compared to six months of operations in fiscal 2005 and an increase in the cost of natural gas supplies for fiscal 2006 to $10.85 per DTH compared to $8.42 per DTH for fiscal 2005.

 

Operating expenses

 

Selling and marketing expenses were $5.2 million for fiscal 2006, an increase of $1.1 million from $4.1 million for fiscal 2005, reflecting the impact of higher advertising, marketing, customer acquisition and telemarketing expenses. These higher costs were attributable to increased customer acquisition initiatives were partly offset by lower payroll costs.

 

General and administrative expenses were $26.9 million for fiscal 2006, a decrease of $4.6 million, from $31.5 million for fiscal 2005. A decrease of $4.5 million in severance costs related to former executive officers in fiscal 2005, and lower legal and bad debt expenses were partly offset by increased expenses related to a full year of operations of the ACN Energy Assets in fiscal 2006 as compared to six months of operations in fiscal 2005.

 

Other expenses

 

In July 2005, we sold our entire stock holdings in Turbocor for $2.0 million in cash resulting in recovery of previous provision for impairment as we then had no basis in Turbocor. There were no similar transactions in fiscal 2006. Additionally, in fiscal 2005, we incurred $1.6 million of initial formation litigation costs related to Commonwealth Energy Corporation’s (our predecessor Company) formation. Initial formation litigation expenses

include legal and litigation costs associated with the initial capital raising. There were no such expenses in fiscal 2006.

 

Interest income, net

 

Our interest income, net was $1.1 million for fiscal 2006, an increase of $0.2 million from $0.9 million in fiscal 2005. The increase in interest income was primarily due to higher market yields realized on investments offset in part by lower investable balances.

 

Benefit from Income Taxes

 

We reflected no benefit for income taxes for fiscal 2006 as a valuation allowance equal to the net deferred tax assets has been provided due to the uncertainty of future realization of the remaining net deferred tax asset at both July 31, 2006 and 2005.

 

Liquidity and Capital Resources

 

The following table summarizes our liquidity measures:

 

 

Consolidated Cash Flows

 

The following table summarizes our statements of cash flows:

 

 

Our principal sources of liquidity to fund ongoing operations have been existing cash and cash equivalents on hand, cash generated from operations and our credit facility which increases our borrowing capacity. Based upon our current level of operations and business conditions, we believe these sources will be sufficient to fund our expected capital expenditures and to meet our working capital requirements along with other cash needs over the next twelve months. We would need to add to our capital resources in fiscal 2008 if we expand our business, either from internal growth or acquisitions, if energy prices increase materially, or if energy industry volatility and/or uncertainty creates additional credit requirements. Cash used in operating activities for fiscal 2007 was $16.1 million, compared to cash provided by operations of $6.1 million in the prior year. For fiscal 2007, cash used in operating activities was comprised primarily of net income of $5.5 million, an increase of accounts payable of $11.1 million, offset by an increase of $38.7 million in accounts receivable, net, including a provision for doubtful accounts. These changes were primarily in support of our increased sales and customer acquisition initiatives including the customers acquired in the HESCO acquisition. For fiscal 2006, cash provided by operating activities was comprised primarily of a decrease of $8.4 million in prepaid expenses and other assets offset by an increase of

$2.8 million in accounts receivable, net, including provisions for doubtful accounts. This was primarily due to increased use of letters of credit under our new credit facility to replace deposits previously used to secure energy supply.

 

Cash used in investing activities was $8.2 million in fiscal 2007, as compared to $4.7 million used in investing activities in fiscal 2006. The cash used in investing activities in fiscal 2007 was spent equally for the upgrades in our key customer billing, risk management and customer contact platforms and for the purchase of the HESCO customer list. The cash used in fiscal 2006 was primarily for other upgrades in the previously discussed platforms.

 

Cash provided by financing activities during fiscal 2007 was $7.9 million, as compared to cash used in financing activities of $11.7 million during fiscal 2006. In fiscal 2007, restricted cash decreased by $6.7 million primarily due to transitioning cash-secured letters of credit to our new credit facility.

 

Credit terms from our suppliers often require us to post collateral against our energy purchases and against our mark-to-market exposure with certain of our suppliers. As of July 31, 2007, we had $10.5 million in restricted cash primarily in connection with a $10 million requirement of our new credit facility. We also have $3.5 million in deposits pledged as collateral to our energy suppliers in connection with energy purchase agreements.

 

As of July 31, 2007, cash and cash equivalents decreased to $6.6 million compared with $22.9 million at July 31, 2006. This decrease of $16.3 million was used primarily to fund accounts receivable growth to support our increasing customer load. Restricted cash and cash equivalents at July 31, 2007 was $17.0 million, compared to $40.1 million at July 31, 2006, for a decrease of $23.0 million. This decrease was also primarily due to our accounts receivable growth and to a lesser extent the purchase of HESCO customer lists and transitioning cash-secured letters of credit to our new credit facility.

 

Credit Facility

 

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 July 31, 2007, letters of credit issued under the facility totaled $18.9 million, and there were no outstanding borrowings. 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 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 Credit Facility also restricts our ability to pay cash dividends on our common stock; restricts Commerce Energy from making cash dividends to the Company without the consent of the Agent and The CIT Group/Business Credit, Inc., or, collectively, the Lenders; and limits the amount of our annual capital expenditures to $3.5 million without the consent of the Lenders. We must also maintain a minimum of $10 million of Eligible Cash Collateral, as defined in the Credit Facility, at all times.

 

In September 2006, the Company and Commerce Energy entered into a First Amendment to Loan and Security Agreement and Waiver, or the First Amendment, pursuant to which the Lenders waived prior or existing instances of covenant non-compliance relating to the maintenance of Eligible Cash Collateral, as defined in the Credit Facility, capital expenditures and the notification to the Lenders of the grant of certain liens to a natural gas supplier. Pursuant to the First Amendment, the Lenders also agreed to certain prospective waivers of covenants in the Credit Facility to enable Commerce Energy to consummate the HESCO acquisition of customers in compliance with the Credit Facility.

In October 2006, the Company and Commerce Energy entered into a Second Amendment to Loan and Security Agreement and Waiver, or the Second Amendment, pursuant to which the Lenders waived prior or existing instances of covenant non-compliance relating to the maintenance of a minimum Fixed Charge Coverage Ratio and a minimum amount of Excess Availability. The Lenders also agreed in the Second Amendment to defer prospective compliance with the Fixed Charge Coverage Ratio covenant and to reduce and restructure the amount of Excess Availability that Commerce will be required to maintain through April 2007.

 

On March 15, 2007, the Company and Commerce Energy entered into a Third Amendment to Loan and Security Agreement and Waiver, or the Third Amendment, pursuant to which the Lenders waived prior or existing instances of covenant non-compliance relating to the maintenance of a minimum Fixed Charge Coverage Ratio and a minimum amount of Excess Availability. The Lenders also agreed in the Third Amendment to extend the period of time during which the minimum amount of Excess Availability that Commerce Energy will be required to maintain established by the Second Amendment will be applicable.

 

On June 26, 2007, the Company and Commerce Energy entered into a Fourth Amendment to Loan and Security Agreement with the Agent, pursuant to which the Agent agreed to allow the Company to increase its Capital Expenditures, as defined in the Credit Facility, for fiscal 2007 and beyond to $6.0 million.

 

On August 1, 2007, the Company and Commerce Energy entered into a Fifth Amendment to Loan and Security Agreement and Waiver, with the Agent and the CIT Business Credit Group/Business Credit, Inc. pursuant to which the Lenders agreed to temporarily reduce and restructure the amount of Excess Availability required to be maintained by Commerce Energy.

 

On September 20, 2007, the Company, Commerce Energy entered into a letter agreement with the Agent and the CIT Business Credit Group/Business Credit, Inc., pursuant to which Commerce Energy was permitted during the period from September 20, 2007 until October 5, 2007, to exceed its Gross Borrowing Base, as defined in the letter agreement. In addition, during the same time period, the amount of Excess Availability required to be maintained by Commerce was temporarily reduced and restructured, and the letter agreement established the amount of Excess Availability that Commerce Energy is required to maintain under the Credit Facility for the period beginning October 6, 2007.

 

Net cash of $7.9 million was provided by financing activities for the year ending July 31, 2007 compared to net cash of $11.7 million used in the year ending July 31, 2006, reflecting the change in restricted cash and cash equivalents used to secure a performance bond in Pennsylvania and $2.3 million of cash used in the year ending July 31, 2006 to repurchase Company stock in connection with a settlement agreement with former executive officers, partially offset by proceeds from the exercise of stock options of $1.2 million.

 

Supply Agreements

 

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 Energy’s wholesale electricity supply needs in Texas. Pursuant to an EEI Master Power Purchase and Sale Agreement dated August 1, 2005 between Commerce Energy and Tenaska, or the Master Agreement, Tenaska agreed to supply electricity to Commerce Energy as set forth under the Master Agreement.

 

In connection with Tenaska’s supply of electricity to Commerce Energy, Commerce Energy and Tenaska entered into an agreement dated August 1, 2005, which we refer to as the QSE Agreement. Under the QSE Agreement, Tenaska agreed to serve as Commerce Energy’s exclusive provider of qualified scheduling services and marketing services with respect to electric energy within the region of Texas administered by the Electric Reliability Council of Texas.

 

A blocked account control agreement with lockbox services, dated August 1, 2005, or the Tenaska Lockbox Agreement, by and among Commerce Energy, Tenaska and U.S. Bank National Association established a lockbox and a related account to be maintained at U.S Bank for deposit by Commerce Energy of all revenues received from certain electricity end-use customers in Texas. We refer to this account as the U.S. Bank Lockbox Account. Until

Tenaska provides notice to U.S. Bank to the contrary, funds in the Tenaska Lockbox Account are to be disbursed as Commerce Energy may direct.

 

Commerce Energy and Tenaska also entered into a security agreement, or the Tenaska Security Agreement, dated August 1, 2006, as amended on March 7, 2006 and June 22, 2006. To secure Commerce Energy’s performance and compliance with its obligations under the Master Agreement, the QSE Agreement, the Tenaska Security Agreement, the Tenaska Lockbox Agreement and the related transaction documents, Commerce Energy granted to Tenaska a continuing security interest in Commerce Energy’s interest in the U.S. Bank Lockbox Account, Commerce’s Energy’s contracts with certain retail electricity sales customers and the revenues and accounts receivable resulting from such contracts. In addition, Commerce Energy agreed to deposit all revenues received from certain electric energy customers into the U.S. Bank Lockbox Account and to maintain a minimum deposit amount in the Tenaska Lockbox Account of $100,000. Tenaska agreed to provide credit to Commerce Energy in an amount not to exceed $22 million. As of July 31, 2007, Tenaska extended approximately $22.0 million of credit to Commerce Energy under this arrangement.

 

On August 1, 2005, Tenaska and the Company entered into a Guaranty Agreement, pursuant to which it, as the parent company of Commerce Energy, unconditionally guaranteed to Tenaska full and prompt payment of all indebtedness and obligations owed to Tenaska.

 

Pacific Summit Energy LLC

 

In September 2006, Commerce Energy entered into several agreements with Pacific Summit Energy LLC, or Pacific Summit, for the supply of natural gas to serve end-use customers that we acquired in connection with the HESCO acquisition. Pursuant to a base contract for sale and purchase of natural gas, dated September 20, 2006 between Commerce Energy and Pacific Summit, or the Base Contract, Pacific Summit agreed to supply natural gas to Commerce Energy as set forth under the Base Contract.

 

Pursuant to an operating agreement, dated September 20, 2006 between Commerce Energy and Pacific Summit, or the Operating Agreement, Pacific Summit agreed to sell to Commerce Energy natural gas for resale to designated customers that Commerce Energy acquired from HESCO. We refer to these customers as the Acquired Customers. Commerce Energy agreed to purchase all of its natural gas requirements for the Acquired Customers exclusively from Pacific Summit, and Pacific Summit agreed to meet the demand for natural gas for such customers at prices to be set in separate transaction confirmations according to market prices. Credit is regularly extended to Commerce Energy by Pacific Summit, and Commerce Energy agreed to enter into a lockbox agreement and a security agreement with Pacific Summit to secure payment of amounts owed to Pacific Summit under the Operating Agreement. As of July 31, 2007, Pacific Summit extended approximately $12.0 million of credit to Commerce Energy under the Operating Agreement.

 

A blocked account control agreement with lockbox services, dated September 20, 2006, or the Pacific Summit Lockbox Agreement, by and among Commerce Energy, Pacific Summit and Wachovia Bank NA established a lockbox and a related account to be maintained at Wachovia Bank NA for deposit by Commerce Energy of all revenues received from the Acquired Customers. We refer to this account as the Wachovia Lockbox Account.

 

Commerce Energy and Pacific Summit entered into a security agreement dated September 20, 2006, or the Pacific Summit Security Agreement. To secure Commerce Energy’s performance and compliance with its obligations under the Base Contract, the Operating Agreement, the Pacific Summit Security Agreement, the Pacific Summit Lockbox Agreement and related transaction documents, Commerce Energy granted to Pacific Summit a continuing security interest in Commerce Energy’s interest in the Wachovia Lockbox Account, Commerce’s Energy’s contracts with the Acquired Customers and the revenues and accounts receivable resulting from such contracts. In addition, under the Pacific Summit Security Agreement, Commerce Energy agreed to maintain a minimum deposit amount in the Wachovia Lockbox Account. The Pacific Summit Security Agreement also provided for monthly withdrawals from the Wachovia Lockbox Account, with payments to be made first to Pacific Summit for amounts due and payable, and second to Commerce Energy for amounts exceeding the Adjusted Minimum Deposit Amount, as defined in the Pacific Summit Security Agreement.

Planned capital expenditures

 

Our planned capital expenditures for fiscal 2008 are approximately $6.0 million and are comprised of carryover expenditures related to key upgrades of our risk management, customer billing and customer load forecasting systems and other information systems and hardware upgrades related to improved customer order entry and increased customer service. These expenditures are expected to be pro rata throughout the year and funded out of working capital.

 

Off-Balance sheet arrangements

 

We have no off-balance sheet arrangements and have no transactions involving unconsolidated, limited purpose entities.

 

Contractual obligations

 

As of July 31, 2007, we had commitments of $63.1 million for energy purchase, transportation and capacity contracts. These contracts are with various suppliers and extend through June 2008.

 

Our most significant operating lease pertains to our corporate office facilities. All of our other operating leases pertain to various equipment, technology and secondary office facilities. Certain of these operating leases are non-cancelable and contain clauses that pass through increases in building operating expenses. We incurred aggregate rent expense under operating leases of $1.2 million, $1.3 million and $1.2 million during fiscal 2007, 2006 and 2005, respectively.

 

The following table shows our contractual commitments for energy purchase and operating leases as of July 31, 2007 (dollars in thousands):

 

 

Additionally, as of July 31, 2007, $19.3 million of letters of credit have been issued to energy suppliers and others pursuant to the terms of our credit facility and $7.8 million in surety bonds have been issued.

 

Seasonal Influences

 

Demand for electricity and natural gas is continually influenced by both seasonal and abnormal weather patterns. To the extent that one or more of our markets experiences a period of unexpected weather, we may be required to either procure additional energy to service our customers or to sell surplus energy in the open market. Generally, unexpectedly higher or lower than normal energy demand from our customers increases the relative cost of our energy supplies.

 

Critical Accounting Policies and Estimates

 

The preparation of this Annual Report on Form 10-K 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.

 

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.

 

 

 

Recent Accounting Pronouncements

 

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities Including an Amendment of FASB Statement No. 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 currently evaluating the impact this statement will have on its financial statements.

 

In September 2006, the SEC staff published SAB No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements”. SAB 108 addresses quantifying the financial statement effects of misstatements and considering the effects of prior year uncorrected errors on the statements of operations as well as the balance sheets. SAB No. 108 does not change the requirements under SAB No. 99 regarding qualitative considerations in assessing the materiality of misstatements. The Company adopted SAB No. 108 during the fourth quarter of fiscal year 2007, and the adoption had no impact on its results of operations or financial condition as of and for the fiscal year ended July 31, 2007.

 

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 currently evaluating the impact this statement will have on its financial statements.

 

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 provisions are effective for the Company as of August 1, 2007. The Company is currently evaluating the impact this statement will have on its financial statements.

 

 

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 $1,564,000 decrease in gross profit for power, and an estimated $954,000 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 actively discontinuing business with customers that do not pay as contractually obligated. 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

 

Since we had no short or long-term debt outstanding at July 31, 2007, our only exposure to interest rate risks is limited to our investment of excess cash balances in interest-bearing instruments. 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 risks.

 

 

The financial statement information, including the reports of the independent registered public accounting firms, required by this Item 8 is set forth on pages F-1 to F-28 of this Annual Report on Form 10-K and is hereby incorporated into this Item 8 by reference. The Quarterly Financial Information required by this Item 8 is set forth on page F-28 (Note 16 to the Notes to Consolidated Financial Statements) of this Annual Report on Form 10-K and is hereby incorporated into this Item 8 by reference.

 

 

None.

 

 

Evaluation of Disclosure Controls and Procedures.

 

Our Chief Executive Officer and our Interim Chief Financial Officer have concluded, based on their evaluations of the end of the period covered by this report, that our disclosure controls and procedures (as defined in Rule 13a-15(e) or 15d-15(e) under the Securities Exchange Act of 1934, as amended) are effective to ensure that all information required to be disclosed by us in the reports filed or submitted by us under the Securities 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 us in such reports is accumulated and communicated to our management, including the Chief Executive Officer and the Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

 

Changes in Internal Controls.

 

In connection with the above-referenced evaluation, no change in our internal control over financial reporting occurred during the fourth quarter of fiscal 2007 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

 

None.

 

PART III

 

 

Information About Our Directors

 

Our Certificate of Incorporation and Bylaws provide for a “classified” Board of Directors. The number of authorized directors is currently six. At present, there are two Class I directors, whose terms expire at the next annual meeting of stockholders; two Class II directors, whose terms expire at the Company’s annual meeting of stockholders to be held after the completion of fiscal 2008; and two Class III directors, whose terms expire at the Company’s annual meeting of stockholders to be held after the completion of fiscal 2009. The following table sets forth information regarding our directors, including their ages as of October 16, 2007, and business experience during the past five years. Each of our directors has served continuously as one of our directors since the date indicated in his biography below.

 

 

There are no arrangements or other understandings pursuant to which any of the persons listed in the table above was selected as a director or nominee.

 

Information with Respect to Our Executive Officers

 

Information regarding our executive officers is included in Item 1C of Part I of this Annual Report on Form 10-K under the caption “Executive Officers of the Registrant,” and is hereby incorporated herein by reference.

 

Section 16(a) Beneficial Ownership Reporting Compliance

 

Section 16(a) of the Exchange Act requires our directors and executive officers, and persons who beneficially own more than 10% of a registered class of our equity securities to file with the SEC initial reports of ownership and reports of changes in ownership of our common stock and other equity securities. Officers, directors and beneficial owners of more than 10% of our common stock are required by SEC regulations to furnish us with copies of all Section 16(a) forms they file.

 

To our knowledge, based solely on our review of the copies of such reports furnished to us and written representations that no other reports were required during fiscal 2007, and except as disclosed in the following paragraph, our officers, directors and beneficial owners of more than 10% of our common stock complied with all Section 16(a) filing requirements during fiscal 2007.

 

Each of the following non-employee directors made a late filing of a Form 4 under Section 16(a) of the Exchange Act that related to the award of the shares of restricted stock regarding director compensation in January 2007: Charles E. Bayless, Mark S. Juergensen, Dennis R. Leibel and Robert C. Perkins.

 

Code of Ethics

 

We have adopted a Code of Business Conduct and Ethics that applies to all of our directors, officers and employees including our principal executive officer, principal financial officer and principal accounting officer and all of our other officers and employees. In the event that we make any amendment to, or grant any waiver of, a provision of the Code of Business Conduct and Ethics that applies to our principal executive officer, principal financial officer or principal accounting officer, we intend to disclose such amendment or waiver by including such information as an exhibit in future filings.

 

Audit Committee and Audit Committee Financial Expert

 

Charles E. Bayless, Gary J. Hessenauer, Mark S. Juergensen, Dennis R. Leibel and Robert C. Perkins are the members of our Audit Committee. Our Board of Directors has determined that each member of the Audit Committee is “independent” as defined under the rules of the SEC and the American Stock Exchange. In addition, the Board of Directors has determined that Mr. Perkins, the Chairman of the Audit Committee, is an “audit committee financial expert” as defined under the rules of the SEC.

 

 

Compensation Discussion and Analysis for Named Executive Officers

 

Overview — Compensation Objectives

 

The primary objective of the compensation committee of our board of directors with respect to executive compensation is to attract, retain and motivate the best possible executive talent. The focus is to tie short and long-term cash and equity incentives to the achievement of measurable corporate objectives and to align executives’ incentives with stockholder value creation. To achieve these objectives, the compensation committee has adopted a compensation approach that ties a portion of the executives’ overall compensation to our operational performance and a portion to their attainment of individually-assigned goals designed to expand our business and improve our internal structures and processes.

 

We must match market cash compensation levels and satisfy the day-to-day financial requirements of our executive officer candidates through competitive base salaries, cash bonuses and equity grants. We compete for key personnel on (i) the basis of our vision of future success, (ii) our culture and company values, (iii) the cohesiveness and productivity of our teams, and (iv) the excellence of our technical and management personnel. In all of these areas, we compete with other energy companies, where there is significant competition for talented employees. While the Company places an emphasis on recruiting in the national energy sector for senior and key executive talent, it also recruits from a broader “all industry” group of public and private companies based primarily in Southern California and Texas, the two principal markets in which we operate. Accordingly, our compensation philosophy has been to maintain an aggressive and flexible pay posture for total compensation, as well as other components of total compensation. In addition, with the same competitive pay issues to consider, our compensation committee has developed incentive bonus and equity plans designed to align stockholder and employee interests.

 

We have adopted an approach to compensation comprised of a mix of short- and long-term components and a mix of cash and equity elements in proportions we believe will provide the proper incentives, reward our senior management team and help us achieve the following goals:

 

 

The compensation of our executive officers is based in part on the terms of employment agreements and offer letters we entered into with several of our executive officers, which set forth the initial base salaries and initial option grants for our executive officers, as well as the terms of our cash bonus plans. See “Employment Agreements” and “Cash Bonus Plans” below.

 

In our fiscal year ended July 31, 2007, or fiscal 2007, we believe that our compensation offering for executive officer talent of base salary, bonus plan and equity grant provided a competitive compensation package to attract, retain and motivate quality management talent. The establishment of financial targets as our goals in the Bonus Program for fiscal 2007 reinforced two other compensation goals; namely, alignment of our executive officers’ compensation with our business objectives and the interests of our stockholders and the fostering of a goal-oriented, highly motivated management team whose participants have a clear understanding of business objectives and shared corporate values. In fiscal 2007, we achieved our stretch financial target under the Bonus Program, thereby creating a higher bonus potential for each of the eligible executive officers. These same two compensation goals also were important in the decision to grant options and shares of restricted stock to the new senior vice president and general counsel who was hired during the fiscal 2007, the only equity grants made to executive officers in fiscal 2007. These grants are discussed in this Compensation Discussion and Analysis under the caption “Equity-Based Incentives.” The individual performance goals set by the chief executive officer and the compensation committee

for the named executive officers that were used to calculate bonus amounts under the Bonus Program for fiscal 2007 were designed to link the executive officer’s bonus with our performance and the attainment of individual goals within that framework of corporate growth. Targeted objectives for the chief executive officer and the other executive officers under the Bonus Program fell into the following categories: financial performance, investor awareness, and increase in customer growth, risk management, and leadership.

 

Role of Our Compensation Committee

 

Our compensation committee approves, administers and interprets our executive compensation and benefit policies. Our compensation committee was appointed by our board of directors, and consists entirely of directors who are “outside directors” for purposes of Section 162(m) of the Internal Revenue Code, as amended, or the Code, and “non-employee directors” for purposes of Rule 16b-3 under the Exchange Act. Our compensation committee is comprised of Gary J. Hessenauer, Mark S. Juergensen, Dennis R. Leibel and Robert C. Perkins. Mr. Leibel is our compensation committee chairperson.

 

The compensation committee considers recommendations from Steven S. Boss, our chief executive officer, in determining executive compensation. While Mr. Boss discusses his recommendations with the compensation committee, he does not participate in determining his own compensation. In making his recommendations, Mr. Boss receives input from our Human Resources department and has access to third-party compensation surveys such as the 2007 Employers Group Compensation Survey and on-line compensation data of publicly-traded companies. This information is also available to our compensation committee. None of our other executive officers participate in the compensation committee’s discussions regarding executive compensation. The compensation committee does not delegate any of its functions to others in determining executive compensation. The compensation committee considers the business goals set for that year, as well as changes in corporate market focus and goals for the next fiscal year. The compensation committee reviews with our management the business plans for the new fiscal year relative to the prior fiscal year.

 

Our compensation committee has taken the following steps to ensure that our approach to executive compensation and benefits is consistent with both our compensation philosophy and our corporate governance guidelines:

 

 

Components of our Compensation Approach

 

Our compensation approach consists of five components:

 

 

We chose to build our executive compensation approach around these elements because we believe that together they have been and will continue to be effective in achieving our overall objectives. We utilize short-term

compensation, including base salary and cash bonuses, to motivate and reward our key executives. The use and weight of each compensation element is based on a subjective determination by the compensation committee of the importance of each element in meeting our overall objectives. We believe that the proportion of compensation at risk should increase as an employee’s level of responsibility increases. We believe that, in addition to base salaries and bonuses, restricted stock awards and other equity-based awards are the primary compensation-related motivator in attracting and retaining qualified employees. Although our compensation committee has in the past engaged the services of compensation consultants, in fiscal 2007, the compensation committee did not engage in the services of a compensation consultant with the exception of structuring our Bonus Program, described below. We have not benchmarked any element of our compensation as it pertains to our executives in fiscal 2007.

 

Base Salary.  Base salaries will typically be used to recognize the experience, skills, knowledge and responsibilities required of each executive officer, as well as competitive market conditions. The base salary of our named executive officers will be reviewed on an annual basis and adjustments are made to reflect performance-based factors, as well as competitive conditions. We do not apply specific formulas to determine increases.

 

In fiscal 2007, Thomas S. Ulry, our senior vice president, sales and marketing, received a $25,000 annual increase in base salary from $228,000 to $253,000 and Nick Cioll, our vice president, chief risk officer, received a $20,000 annual increase in base salary from $152,500 to $172,500, each effective October 1, 2006, in recognition of their superior performance in fiscal 2006 and, in the case of Mr. Cioll, also in recognition of his recent promotion to his current position. In fiscal 2007, we hired Erik A. Lopez, Sr. as our senior vice president and general counsel. The compensation committee established a base salary for Mr. Lopez of $265,000. Among the factors that the compensation committee considered in the course of establishing that base salary were on-line salary data, a third-party compensation survey and the potential earnings potential that Mr. Lopez may have been foregoing from his prior employment. We also entered into an agreement with Tatum LLC to engage the services of J. Robert Hipps as our interim chief financial officer at $37,500 per month for a minimum period of three months. The terms of such agreement with Tatum were believed by the compensation committee to be market, based upon Mr. Hipps’ qualifications and experience.

 

In fiscal 2007, Mr. Clayton incurred costs for long-distance travel commuting expenses in the amount of $59,274 in connection with commuting from his home in Texas to our corporate headquarters in Costa Mesa, California. We paid these non-reimbursable costs to Mr. Clayton and added such costs to his base salary.

 

Annual Cash Bonuses.  We believe that as an employee’s level of responsibility increases, a greater portion of the individual’s cash compensation should be variable and linked to both quantitative and qualitative expectations, including key operational and strategic metrics. To that end, in fiscal 2007, we established annual cash Bonus Program which is administered by the compensation committee. These bonuses, if earned, are paid after the end of the fiscal year. All of our named executive officers, with the exception J. Robert Hipps, were eligible to participate in the Bonus Program in fiscal 2007; however, in order to vest in a bonus amount, an executive officer must be an active employee on the date the bonus is paid. Mr. Hipps was not eligible to participate because he was not an employee during the first nine months of the fiscal year.

 

For fiscal 2007, bonus payments to our chief executive officer and the other executive officers were based on meeting and/or exceeding Company financial goals set by the compensation committee and achieving other business goals set for the respective executives by the compensation committee. Pursuant to the terms of the Bonus Program, the bonus award for each executive officer was calculated based upon the product of (i) the named executive officer’s base annual salary as of April 30, 2007, (ii) the named executive officer’s potential bonus percentage assigned by the compensation committee to the level of such employee (i.e., 20-70% for the chief executive officer and 12-40% for the other executive officers), and (ii) the named executive officer’s earned bonus percentage based upon the attainment of certain individual business goals set by the compensation committee with recommendations by the chief executive officer; and reduced (but not below zero) by amounts, if any, from the Company’s commission incentive program. Messrs. Boss, Ulry or Cioll were not eligible to participate in the Company’s commission incentive program.

Under the Bonus Program, a participant’s potential bonus percentage is determined based upon the Company’s net income which is defined under the Bonus Program to mean net income from operations, including interest income and expense, for any fiscal year after bonus accruals under the Bonus Program are deducted. At the beginning of each fiscal year, the compensation committee establishes four levels of net income goals and assigns potential bonus percentages for each such corresponding level. In fiscal 2007, we attained net income as defined in the Bonus Program of $3.6 million. At that level of net income, the applicable bonus percentage for the chief executive officer was 30% and 18% for the other executive officers. At the time the compensation committee set the Level II target, it believed attainment of the goal to be achievable, but somewhat of a stretch. Levels I, II, III and IV of the net income goals under the Bonus Program were set at $1.35, $3.0, $4.0 and $5.0 million, respectively. In addition to a bonus payment, if the Level IV target had been exceeded, the Committee could have established a bonus pool and distributed it among the bonus groups, including the named executive officers, as the Committee determine in its sole discretion.

 

In determining the earned bonus percentage, the compensation committee assigned to the chief executive officer and each of the other executive officers specific individual objectives in several of the following categories: increase in overall Company financial performance; increase in investor awareness; financial risk management; peer and leadership development; and customer maintenance and growth. Each category was assigned a specific percentage weight at the commencement of the Plan. In establishing the performance objectives of the executive officers, the chief executive officer and members of the executive team made recommendations, which were approved by members of the compensation committee. Each executive, including each executive officer, had individual objectives for the year which were designed to contribute to the achievement of our corporate objectives. For purposes of determining whether our executive officers met each of the individual goals and objectives assigned to them, the compensation committee met with our chief executive officer and then deliberated among themselves without the chief executive officer present. Messrs. Boss, Ulry and Cioll each had individual objectives that the Company reach $1.35 million in net income which was met and exceeded by 168%. The weighting for that factor among the three executive officers was 70% for Mr. Boss, 40% for Mr. Ulry and 40% for Mr. Cioll. Mr. Boss also had individual objectives relating to increasing institutional or strategic investors and each of the three named executive officers were assigned internal leadership goals. Mr. Ulry was also assigned Company performance objectives to (i) improve profitability by originated gross margin of $18 million, a goal exceeded by 172%; (ii) increase customer growth by at least 98,000 new customer accounts, a goal exceeded by 120%; and (iii) achieve at least an 80% customer renewal rate, a goal also met. Mr. Cioll was assigned several individual projects related to improving the risk management operation of the business. In fiscal 2007, the earned bonus percentages for Steven S. Boss, our chief executive officer, Thomas L. Ulry, our senior vice president, sales and marketing, and Nick Cioll, our vice president, chief risk officer, were 90%, 100% and 85%, respectively. The reason for Mr. Boss not realizing the maximum earned bonus percentage was a subjective determination by the compensation committee regarding progress made on team building initiatives and the reason for Mr. Cioll not realizing his maximum earned bonus percentage was a determination by the compensation committee that certain elements of the new risk management program were not operational and a subjective determination relating to certain new risk management reports. As a result, Mr. Boss’s bonus for fiscal 2007 was $111,242 or 27% of his base salary as of April 30, 2007, Mr. Ulry’s bonus for fiscal 2007 was $45,538, or 18% of his base salary as of April 30, 2007 and Mr. Cioll bonus for fiscal 2007 was $26,392, or 15.3% of his base salaries as of April 30, 2007. The bonus amounts for Messrs. Boss, Ulry and Cioll which relate to fiscal 2007 have not been paid. To receive the bonus payment, each named executive officer must be an active employee of the Company and be in good standing on the date the bonus is paid, which is expected to be in November 2007.

 

We have not paid any significant signing or promotion bonuses to our named executive officers, nor have we guaranteed any future bonuses to our named executive officers.

 

Discretionary Bonuses.  The compensation committee has the discretion to award discretionary bonuses to named executive officers. In fiscal 2007, the compensation committee awarded discretionary bonus to Thomas L. Ulry and Nick Cioll in the amount of $25,000 and $20,000, respectively, in recognition of their outstanding contributions in fiscal 2006. In awarding the amount of the bonus, the compensation committee recognized the more senior position of Mr. Ulry and the importance of the sales function of the Company as one of the key drivers to increase stockholder value.

Equity-Based Incentives.  Salaries and bonuses are intended to compensate our named executive officers for short-term performance. We also have adopted an equity incentive approach intended to reward longer-term performance and to help align the interests of our named executive officers with those of our stockholders. We believe that long-term performance is achieved through an ownership culture that rewards performance by our named executive officers through the use of equity incentives. Our equity incentive plans have been established to provide our employees, including our named executive officers, with incentives to help align those employees’ interests with the interests of our stockholders. Our equity incentive plans have provided the principal method for our named executive officers to acquire equity interests in our company.

 

The size and terms of the initial option grant and restricted share award made to each executive officer upon joining us are primarily based on competitive conditions applicable to the executive officer’s specific position and are set forth in the executive officer’s employment agreement or offer letter from us. In addition, the compensation committee considers the number of options and restricted shares owned by other executives in comparable positions within our company.

 

The equity awards we make to our named executive officers will be driven by our sustained, performance over time, our named executive officers’ ability to impact our results that drive stockholder value, their level of responsibility within our company, their potential to fill roles of increasing responsibility, and competitive equity award levels for similar positions in comparable companies. Equity forms a key part of the overall compensation for each executive officer and will be considered each year as part of the annual performance review process and incentive payout calculation.

 

We do not have a policy regarding the granting of equity, or the purchase and retention of equity, by our named executive officers.

 

During fiscal 2007, we made one stock option award in the aggregate amount of 45,000 shares of our common stock and one restricted stock award in the aggregate amount of 60,000 shares of our common stock to our then newly-hired senior vice president, general counsel under our 2006 Stock Incentive Plan. The amount of the stock option grant and the restricted stock award was the result of negotiations with the executive officer during the hiring process in order to both recruit the executive officer to his current position and incentivize him to increase stockholder value over the life of the awards. The option was granted at the fair market value on the date of grant which is the closing price on the American Stock Exchange. The option and the shares of restricted stock vest over a three-year period with one third vesting on each anniversary of the commencement date of employment. All equity awards to our employees, including named executive officers, and to our directors have been granted and reflected in our consolidated financial statements, based upon the applicable accounting guidance, with the exercise price equal to the fair market value on the grant date based on the valuation determined by the compensation committee of our board of directors.

 

In fiscal 2007, we also amended the employment agreements and the related restricted stock agreements for two named executive officers establishing a positive net income performance target for fiscal 2007 for the vesting of 75,000 shares of restricted stock for Steven S. Boss, our chief executive officer, and 15,000 shares of restricted stock for Lawrence Clayton, Jr., our former chief financial officer. In selecting such performance target, the compensation committee, believed the target to be easily attainable. Pursuant to Mr. Boss’ employment agreement, upon joining the Company in August 2005, he was awarded 200,000 shares of restricted stock; 50,000 shares of which vested upon his first anniversary with us; and 150,000 shares which vested over the next three years in 50,000 share increments based upon the achievement of performance targets for fiscal 2006, 2007 and 2008 established by the compensation committee. During fiscal 2006, the compensation committee did not set any performance targets for vesting. The parties rectified the failure of one tranche of restricted shares to have the opportunity to vest by entering into the amendment which provided that 75,000 shares of restricted stock shall vest if we achieved positive net income, as defined in GAAP, in fiscal 2007 and 75,000 shares of restricted stock shall vest based upon the achievement of performance targets to be established by the compensation committee for the fiscal year ending July 31, 2008. For each tranche of restricted shares to vest, Mr. Boss must be an employee of us at the time we file our respective annual reports on Form 10-K with the SEC. See “Employment Agreements”.

 

Other Benefits.  We have a 401(k) plan in which substantially all of our employees are entitled to participate. Employees contribute their own funds, as salary deductions, on a pre-tax basis. Contributions may be made up to

plan limits, subject to government limitations. The plan permits us to make matching contributions if we choose and we have historically provided matching contributions of up to three percent, based on 50% of employees’ contributions of up to 6% of defined compensation. We also offer an Amended and Restated 2005 Employee Stock Purchase Plan, or the ESPP, which became effective in July 2006. The ESPP, which has been approved by our board of directors and our stockholders, provides for eligible employees to purchase our common stock through payroll deductions. The ESPP generally allows employees to elect to purchase our common stock each month in an amount not to exceed an annual rate of accrual of $25,000 per calendar year in fair value of our common stock at the lower of the first or last day’s closing price for each month’s offering period, less a discount of 15%. The ESPP does not discriminate between executive and non-executive employees. We provide health care, dental, vision and life insurance, employee assistance plans and both short- and long-term disability, accidental death and dismemberment benefits to all full-time employees, including our named executive officers. We believe these benefits are comparable with companies with which we compete for employees. These benefits are available to all employees, subject to applicable laws. Certain of these plans require varying levels of employee contributions including deductibles and co-pays depending on the plans chosen by the employee. These contributions are the same for all employees including our named executive officers.

 

Severance and Termination Protection

 

Employment and Letter Agreements.  Under their employment and letter agreements, respectively, Messrs. Boss and Ulry are entitled to certain severance and change of control benefits, the terms of which are described in detail below under “Employment Contracts” and “Letter Agreements.”

 

Acceleration of Vesting of Equity-Based Awards.  In the event of a change in control of us, certain provisions of our 1999 Equity Incentive Plan and the 2006 Stock Incentive Plan allow, at the discretion of the compensation committee for up to the full acceleration of unvested equity awards in the event an acquirer neither assumes awards outstanding under these plans nor issues our award holders substitute equity awards. See “Employee Benefit Plans” below.

 

Accounting and Tax Considerations

 

Effective August 5, 2005, we adopted the fair value provisions of Financial Accounting Standards Board Statement No. 123(R) (revised 2004), “Share-Based Payment,” or SFAS 123(R). Under SFAS 123(R), we are required to estimate and record an expense for each award of equity compensation (including stock options) over the vesting period of the award.

 

Internal Revenue Code Section 162(m) limits the amount that we may deduct for compensation paid to our chief executive officer and to each of our four most highly compensated officers to $1,000,000 per person, unless certain exemption requirements are met. Exemptions to this deductibility limit may be made for various forms of “performance-based compensation.” In the past, annual cash compensation to our named executive officers has not exceeded $1,000,000 per person, so the compensation has been deductible. In addition to salary and bonus compensation, upon the exercise of stock options that are not treated as incentive stock options, the excess of the current market price over the option price, or option spread, is treated as compensation, and accordingly, in any year, such option exercise may cause an officer’s total compensation to exceed $1,000,000. Under certain regulations, option spread compensation from options that meet certain requirements will not be subject to the $1,000,000 cap on deductibility, and in the past we have granted options that met those requirements. The compensation committee has not yet established a policy for determining which forms of incentive compensation awarded to our named executive officers shall be designed to qualify as “performance-based compensation.” To maintain flexibility in compensating our named executive officers in a manner designed to promote our objectives, the compensation committee has not adopted a policy that requires all compensation to be deductible. However, the compensation committee intends to evaluate the effects of the compensation limits of Section 162(m) on any compensation it proposes to grant, and the compensation committee intends to provide future compensation in a manner consistent with our best interests and those of our stockholders.

Financial Restatements

 

Our compensation committee does not have an established practice regarding the adjustment or recovery of awards or payment if the relevant performance measures upon which they are based are restated or otherwise adjusted in a manner that would reduce the size of an award or payment previously made. The board of directors will determine whether to seek recovery of incentive compensation under the Bonus Program in the event of a financial restatement or similar event based on the facts and circumstances surrounding a financial or similar event, should one occur. Among the key factors that the compensation committee will consider is whether the executive officer engaged in fraud or misconduct that resulted in need for a restatement.

 

Summary Compensation Table

 

The following table provides information regarding the compensation earned during the fiscal year ended July 31, 2007 by our chief executive officer, our interim chief financial officer, our former chief financial officer and our three other most highly compensated executive officers who were employed by us as of July 31, 2007. We refer to these executive officers as our “named executive officers.”

 

 

 

 

Grants of Plan-Based Awards in Fiscal 2007

 

The following table presents information concerning grants of plan-based awards to each of the named executive officers during the year ended July 31, 2007. The exercise price per share of each option granted to our named executive officers was equal to the fair market value of our common stock, as determined by our compensation committee on the date of the grant.