UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
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For the fiscal year ended: December 31, 2004 |
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number: 0-16179
Gexa Corp.
(Exact name of registrant as specified in its charter)
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Texas |
76-0670175 |
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(State or other jurisdiction of incorporation or organization) |
(IRS Employer Identification No.) |
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20 Greenway Plaza, Suite 600, Houston, TX |
77046 |
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(Address of principal executive offices) |
(Zip Code) |
(713) - 470 - 0400
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, par value $0.01
(Title of class)
Indicate
by check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such
reports), and (2) has been subject to such filing requirements for the past 90
days.
Yes ý No
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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 an accelerated filer (as defined in Rule 12b-2 of the
Act).
Yes
o No ý
Aggregate market value of the voting stock of Gexa Corp. held by non-affiliates as of June 30, 2004 (based on the closing market price on June 30, 2004) was $9,688,122.
The number of shares outstanding of Gexa Corp. common stock, $0.01 par value, at March 23, 2005 was 10,063,160.
DOCUMENTS INCORPORATED BY REFERENCE: Portion of the registrant’s annual proxy statement, to be filed within 120 days after December 31, 2004, are incorporated by reference into Part III of the Form 10-K.
TABLE OF CONTENTS
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Forward Looking Statements
This annual report on Form 10-K includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (“Exchange Act”). All statements other than statements of historical fact are forward-looking statements. Forward-looking statements are subject to certain risks, trends and uncertainties that could cause actual results to differ materially from those projected. Among those risks, trends and uncertainties are our estimate of the sufficiency of existing capital sources, our ability to raise additional capital to fund cash requirements for future operations, our assumptions regarding the competitive restructuring and deregulation of the electricity market, competition from utility companies, our dependence on the services of certain key personnel and our ability to manage our growth successfully. Although we believe that in making such forward-looking statements our expectations are based upon reasonable assumptions, such statements may be influenced by factors that could cause actual outcomes and results to be materially different from those projected. We cannot assure you that the assumptions upon which these statements are based will prove to have been correct.
When used in this Form 10-K, the words “expect,” “anticipate,” “intend,” “plan,” “believe,” “seek,” “estimate”, “predicts”, “projects”, “targets”, “will likely result”, “may”, “could” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain these identifying words. Because these forward-looking statements involve risks and uncertainties, actual results could differ materially from those expressed or implied by these forward-looking statements for a number of important reasons, including those discussed under “Risk Factors” and elsewhere in this prospectus.
You should read these statements carefully because they discuss our expectations about our future performance, contain projections of our future operating results or our future financial condition, or state other “forward-looking” information. The occurrence of any of the events described in “Risk Factors” and elsewhere in this Form 10-K could substantially harm our business, results of operations and financial condition.
We cannot guarantee any future results, levels of activity, performance or achievements. Except as required by law, we undertake no obligation to update any of the forward-looking statements in this Form 10-K after the date of this Form 10-K.
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ITEM 1. BUSINESS
THE BUSINESS
Overview and Company History
Gexa Corp. (d/b/a Gexa Energy), located in Houston, Texas, is a retail electric provider (a “REP”). As of December 31, 2004, we provide electric power to our residential and commercial customers in the deregulated Texas electricity market. We also are currently licensed to supply retail electricity power to the Massachusetts electricity market and have submitted applications to become an electricity provider in New York and Maine.
In August 2001, the Public Utility Commission of the State of Texas (“PUCT”) approved our license to become a REP in Texas. As a REP, we sell electric energy and provide the related billing, customer service, collections and remittance services to residential and commercial customers. We offer our customers the attractive value proposition of lower electricity rates, flexible payment and pricing choices, simple offers with understandable terms and responsive customer service. In general, the Texas regulatory structure permits independent REPs (companies unaffiliated with an incumbent utility in a particular geographic area), such as Gexa, to procure and sell electricity at unregulated prices and pay the local transmission and distribution utilities a regulated tariff rate for delivering electricity to the customers. We are currently one of the largest independent REPs, not affiliated with a utility, operating in Texas that focuses on customers whose peak demand is under one megawatt (defined by the Texas Public Utility Commission as “price-to-beat” commercial customers), as measured by total megawatt hours sold and by customer count. We have grown to over 104,000 total meters as of December 31, 2004.
To date, we have focused our sales efforts on the under one megawatt commercial and the residential multi-family housing (apartment community) segments. We have also begun to deploy several low cost marketing strategies to further penetrate the single-family residential market. Employing several first-to-market, co-marketing partnerships with leading brands (e.g., Continental Airlines OnePass®, American Airlines AAdvantage® frequent flyer programs), we expect to leverage the brand equity of these partners to provide access to new single-family residential customers without incurring large marketing expenditures. The majority of our customers are located in the Houston and Dallas markets, although a growing number are located in a variety of other metropolitan and rural areas in south and west Texas, such as Corpus Christi and Lubbock.
We primarily offer one-year and two-year term contracts to our commercial customers and month-to-month terms to our residential customers. In the under one megawatt commercial segment, our position as an independent REP allows us to acquire customers primarily by switching the customers away from REPs that are affiliated with an incumbent utility. In the residential market, we have signed marketing agreements with major property management firms to serve their residential and on-site commercial accounts.
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With respect to energy supply, we utilize an agreement with TXU Portfolio Management Company LP (“TXU PM”), an unregulated entity of TXU Energy that buys and sells wholesale power, for the procurement of wholesale energy. We serve as our own qualified scheduling entity for open market purchases and sales of electricity. We forecast our energy demand and conduct procurement activities through an experienced team of in-house professionals. The forecast for electricity load requirements is based on our aggregate customer base currently served and anticipated weather conditions, as well as forecasted customer acquisition and attrition. We continuously monitor and update our supply positions based on our retail demand forecasts and market conditions. Our policy is to maintain a balanced supply/demand book to limit commodity risk exposure. We do not currently use derivative instruments and we do not plan to engage in uncovered or speculative trading of derivative instruments in the future, although we may use derivatives for hedging purposes in the future.
Our business strategy can be summarized as follows:
• establish marketing relationships with multi-family property managers and owners to market our services on-site to residents while also providing power to the commercial meters on-site;
• use our inside direct sales team, as well as a network of independent sales agents, to market our service to commercial customers;
• utilize strong branded partners (e.g., Continental Airlines, American Airlines) to provide access to a potential expanded customer base, particularly single-family residential customers, by providing a strong affinity-based electricity offering with other tangible benefits;
• operate and further develop a cost-effective and efficient billing and customer service infrastructure, utilizing a combination of internal resources and outsourced partners;
• leverage our credit support and energy supply agreement with TXU to provide a cost-effective supply of electricity to meet our customers’ needs; and
• evaluate opportunities to expand our business in the Texas marketplace and other deregulated markets on an opportunistic basis.
We intend to evaluate opportunities to expand our areas of operations in Texas as certain market regions in Texas elect to option-in to deregulation. In addition, there are a number of small REPs within the Texas market, and we intend to monitor the activities of these REPs and to pursue and evaluate opportunities to acquire such REPs to the extent it would provide value to us.
We will also continue to evaluate expansion opportunities in other deregulated electricity markets that offer growth potential in our core under one megawatt commercial, multi-family and single-family residential customers. Beyond Texas, 17 other states and the
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District of Columbia are currently open to competition in the U.S. with the majority of these in the Mid-Atlantic and Northeast regions. The pace of deregulation in these states varies based on historical moves to competition and responses to market events. While many states continue their support for retail competition and industry restructuring, other states that were considering deregulation have slowed their plans or postponed consideration. In addition, other states are reconsidering deregulation. We recently filed applications to become a retail electric provider in the deregulated electricity markets of New York and Maine and began servicing certain of our existing customers in Massachusetts in March 2005.
At December 31, 2004, we had 122 full-time employees and 14 part time employees and independent contractors. Our principal executive offices are located at 20 Greenway Plaza, Suite 600, Houston, Texas 77046, and the telephone number is (713) 470-0400.
Texas Market
In this section, we use the term “competitive REPs” to refer to independent REPs and affiliated REPs, only to the extent operating outside of their incumbent market, and the term “incumbent REPs” to refer to affiliate REPs only to the extent operating within their incumbent markets. The term “large commercial” refers to the market segment of non-residential customers whose peak demand over the preceding 12-month period was less than one megawatt but greater than 50 kilowatts. The term “small commercial” refers to the market segment of non-residential customers whose peak demand over the preceding 12-month period was less than 50 kilowatts.
The Texas deregulated marketplace for under one megawatt customers includes approximately 3,625 large commercial customers, 949,253 small commercial customers and 5.1 million residential customers, which we estimate represent collectively over a $10 billion per annum overall market. Approximately 62%, 27% and 21% of the large commercial, small commercial and residential customers, respectively, in Texas had chosen to be served by a competitive REP as of February 28, 2005, with the remainder being served by the incumbent REP.
Furthermore, customers choosing to be served by a competitive REP as of February 28, 2005, accounted for 67%, 69% and 26% of peak megawatt demand, measured by usage at February 28, 2005, in the large commercial, small commercial and residential markets, respectively.
Regulatory Environment
Deregulation of the wholesale electricity market in Texas began in 1995 with Senate Bill 373. This enabled independent power generators to establish operations in Texas alongside those of the regulated utilities and gain access to the transmission capabilities of the grid. This foundation, coupled with the passing of Senate Bill 7 in 1999, has enabled an integrated marketplace linking generators, energy delivery companies, retail electric providers, and an independent grid operator, the Electric Reliability Council of Texas (“ERCOT”), to offer choice to end-use electricity customers. There are currently five
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major markets open to competition as defined by ERCOT based on service areas in Texas covered by formerly integrated utilities.
Effective January 1, 2002, retail customers of independent operating utilities in the ERCOT region of Texas were allowed to choose a REP. A REP serves end-use customers by purchasing its electricity from competing power producers in the wholesale market, receiving delivery services from the regulated transmission and distribution service providers (formerly the integrated utilities) and performing basic customer service functions including billing, collections and handling customer service requests.
As part of Texas Senate Bill 7, the formerly integrated utilities were essentially split apart into three businesses: 1) unregulated wholesale businesses for power generation, 2) regulated transmission and distribution service providers (“TDSPs”) and 3) unregulated REPs. The REPs that were formed by the previously integrated utilities are referred to as “affiliated REPs” and as “incumbent REPs” when operating in their incumbent market. The incumbent REPs are subject to restrictions on their ability to compete on price in their own markets (the areas previously served by the integrated utility) to foster competition through price discounts from competitors. The two largest affiliated REPs in Texas are TXU Energy and Reliant Energy, who are incumbent REPs in the Dallas/Ft. Worth and Houston areas, respectively. The other affiliated REPs include First Choice (an affiliate of Texas New Mexico Power), American Electric Power/Central Power and Light, and American Electric Power/West Texas Utilities.
Effective January 1, 2002, all customers previously with the integrated utility, whose electricity demand was under one megawatt (commercial and residential), were transferred to the incumbent REPs to be served on a month-to-month rate, known as the “price-to-beat” until such time that these customers choose to be served by an independent REP. The “price-to-beat” rate, set by the PUCT, was to serve as the benchmark, allowing independent REPs, such as Gexa, the flexibility to set their own prices to customers in each market.
The “price-to-beat” rule requires the incumbent REPs to charge only one rate in their respective incumbent markets until certain conditions are met. For under one megawatt commercial consumers, incumbent REPs are required to charge the “price-to-beat” until either 40% of the load in the incumbent market is no longer served by the incumbent REP or until January 1, 2005. All of the incumbent REPs met the 40% threshold by the end of 2003, and therefore have the opportunity, but not the obligation, to charge a rate that is lower than the “price-to-beat” for the under one megawatt commercial market.
For residential customers, prior to January 1, 2005 incumbent REPs could only charge the “price-to-beat”. Beginning January 1, 2005, the incumbent REPs may offer a rate that is lower than the “price-to-beat”.
For both under one megawatt commercial consumers and residential customers, incumbent REPs are restricted from charging a rate that is higher than the “price-to-beat” in their incumbent market until after January 1, 2007, without the approval of the PUCT.
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Three critical elements required to have a successful retail electricity market are present in Texas. First, the wholesale energy market is competitive, thereby enabling retailers to purchase supply at competitive prices. Second, a common framework for operating throughout Texas has been established to enable retailers to effectuate switching, billing, service orders and other necessary transactions with ERCOT (as a clearinghouse) and with the TDSPs. Third, a regulatory framework has been established that encourages competition by enabling the incumbent REP to adjust the “price-to-beat” based on the movement in natural gas or purchased power prices. This unique “price-to-beat” mechanism ensures that the retail margins in the market can be preserved if commodity costs increase.
In 2004, the PUCT enacted legislation permitting REPs who are not affiliated with the incumbent utility in a particular market to directly disconnect services of customers who fail to pay their bills in a timely manner, with certain exceptions including extreme weather conditions and whether the customer’s meter is used to power life support systems. We anticipate that the ability to disconnect delinquent customers will have a positive impact on the receivables collection process for all market participants.
When we enter deregulated markets outside of Texas, we will be required to operate within the specific regulatory environments of such states and regions. The rules in the other markets do vary from Texas, with some aspects being more favorable and some less favorable than Texas. For example, we currently bear the full risk of bad debt in our Texas markets, including transmission and distribution charges. In most other states, the TDSP collects directly from the customer and bears all of the credit risk, although the per kilowatt-hour margins for REPs are typically lower in these states. We will evaluate the regulatory environment of each market in addition to the other operational, financial and customer considerations before determining whether to pursue a new market opportunity.
Operations
The primary responsibilities of a REP in Texas include customer account initiation and termination, energy supply management and scheduling, billing/remittance processing, and customer service. ERCOT oversees all aspects of the Texas power grid, and all retail electric providers must be certified by ERCOT to operate in the Texas markets. ERCOT was founded in 1970 to oversee the Texas power grid and under deregulation ERCOT serves as the Independent System Operator (“ERCOT ISO”) of the power grid in Texas and enables REPs, generators, TDSPs, and ultimately customers, to operate in a deregulated marketplace in Texas. ERCOT is continuously performing five major processes to support the retail provider:
• registration
• market operations
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• power operations
• load profiling, date acquisition and aggregation
• settlements, billing and financial transfer
In its simplest form, ERCOT is responsible for coordinating and monitoring all communications by and between the power generator, the retail electric provider and the TDSP. ERCOT oversees all aspects of these communications including customer sign up, meter reading and billing between the end user, power generator and REP.
With respect to account initiation and termination, we utilize several inbound methods to sign up new customers: telephone, fax, internet, and mail. These orders in turn are processed internally and sent through a service provider, Energy Services Group (“ESG”), to ERCOT, then to the TDSPs, and then back to us through ESG. Customers terminate their service in the same way.
We utilize ESG, a leading innovator in the automation of back-office business processes for the emerging deregulated energy industry, to process our market transactions for both account initiation/termination and meter reads. ESG, who is a certified processor of retail energy information for ERCOT, provides us with the software and programs to exchange data with ERCOT. This allows our billing system, the Gexa Energy Management System (“GEMS”) to receive and process all information necessary to bill our customers. ESG also provides us testing and system upgrade services to ensure all of our systems are compliant with current regulations and ERCOT protocols which are ever evolving.
GEMS not only bills all of our customers, but also provides critical accounting and reporting data used to track billings, accounts receivable, adjustments to receivables, customer deposits, and reports for managerial decision making. We continue to develop and improve the GEMS system to meet our specific needs for future billing enhancements and to comply with changing ERCOT protocols and PUCT regulations.
Our customer service function is maintained internally, with customer service representatives able to provide service via the telephone, fax and email and using GEMS as the core customer information system. Most inquiries are for customers making payments over the phone, account initiation/termination, and understanding of the billing and usage data.
During 2004, we added approximately 20 customer service representatives to handle an increase in meters from approximately 62,000 meters as of December 31, 2003 to approximately 104,000 meters as of December 31, 2004. As a result of the increase in customer service staff, the number of meters serviced per customer representative decreased from 4,000 meters as of December 31, 2003 to 3,000 meters as of December 31, 2004, which has improved our telephone response times.
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Marketing and Sales
We have focused our marketing and sales effort on commercial accounts under one megawatt (small commercial) and the residential multi-family housing (apartment community) segments. During 2004, we have further penetrated the single-family residential segment. Employing several first-to-market, and co-marketing arrangements with leading brands (e.g., Continental Airlines OnePass®, American Airlines AAdvantage® frequent flyer programs), we expect to leverage the brand equity of these programs to provide access to new single-family residential customers without incurring large marketing expenditures.
Our customer base grew in 2004 at an average of 4 to 5 percent monthly during 2004. Our customer base is diverse with no single customer representing more than 3% of total revenue in 2004. At December 31, 2004, the majority of our customers are in the Houston and Dallas markets, with a growing presence in several other metropolitan and rural areas in south and west Texas including the cities of Corpus Christi and Lubbock.
We primarily offer one-year and two-year term contracts to our small commercial customers and month-to-month terms to our residential customers. The small commercial contracts have cancellation penalties that range from one to four months’ energy usage depending on the term. Residential agreements are on a month-to-month basis, which offers us pricing flexibility, but allows the customers to leave us at any time for a nominal fee.
In the small commercial market, our position as an independent REP allows us to acquire customers primarily by switching the customers away from affiliated REPs. In the residential market, we have signed marketing agreements with major property management firms to serve their residential and on-site commercial accounts. By effectively positioning ourselves as a low-cost provider and with the endorsement of the on-site property management companies, our strategy is to continue to cost effectively acquire new customers. We utilize a combination of internal sales representatives and independent sales representatives to acquire new customers. Our internal sales representatives receive a one-time commission when a customer is acquired, regardless of whether the customer is commercial or residential. Our independent sales representatives earn a one-time commission for residential customers and they earn an ongoing commission for small commercial customers during the duration that we serve the customer.
During 2004, the Company continues to benefit from the joint marketing agreement with Continental Airlines, Inc (“Continental”). Through the agreement, Continental and we market our electricity services to all Continental OnePass® members and Continental employees, enabling them to earn OnePass® miles for every dollar spent on electricity. Commissions to Continental from the program are based on monthly invoices received from Continental, and payable in a combination of cash and shares of our common stock. In conjunction with the Continental joint marketing agreement, we offered two other limited time programs during 2004. During the second quarter of 2004, if a customer signed up for the OnePass® program during the months of June and July
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and used a Chase credit card, they received 1,000 bonus miles. During the third quarter of 2004, if a customer signed up for the OnePass® program during the months of July, August, or September, and they used an American Express card, they received 1,000 bonus miles. Although these were limited time programs, we continue to maintain active relationships with both Chase and American Express.
During the second quarter of 2004, we entered into a marketing agreement with American Airlines, Inc. (“American Airlines”) to participate in the AAdvantage® program. American Airlines’ customers also receive AAdvantage® miles for every dollar spent on electricity. Payment to American Airlines occurs when we purchase miles. All miles within the AAdvantage® program are prepaid. This program is similar to the Continental program except that miles are prepaid and payment to American Airlines is only in cash.
Other Markets
Although our main service regions are all within the Texas market, we recently obtained a license to provide retail electricity in the Massachusetts market and anticipate offering service in New York in May, 2005, subject to receiving our license in New York. We also have submitted an application to provide retail electricity in Maine. Beyond these four markets, there are currently 14 additional states offering deregulated electricity services open to competition in the U.S, with the majority of these in the Mid-Atlantic and Northeast regions. The pace of deregulation in these states varies based on historical moves to competition and responses to market events. While many states continue their support for retail competition and industry restructuring, other states that were considering deregulation have slowed their plans or postponed consideration. In addition, other states are reconsidering deregulation.
As we enter these new regions and other regions in the future, we will be required to operate within the specific regulatory environments of such states and regions. The rules in these other markets do vary from Texas, with some aspects being more favorable and some less favorable. In Texas, the REP bears the full risk of bad debt, including the transmission and distribution charges, whereas in most other states, the TDSP collects from the customer and is exposed to the bad debt risk, as the REP is paid by the TDSP. However, in such lower risk markets we will likely experience lower margins. We will continue to evaluate the regulatory environment as well as other operational, financial and customer considerations before making a decision to pursue a new market opportunity.
Electricity Supply
With respect to energy supply in Texas, we utilize an agreement with TXU PM for the procurement of wholesale energy. We serve as our own qualified scheduling entity for open market purchases and sales of electricity. We forecast our energy demand and conduct procurement activities through an experienced team of in-house professionals. The forecast for electricity load requirements is based on our
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aggregate customer base currently served and anticipated weather conditions, as well as forecasted customer acquisition and attrition. We continuously monitor and update our supply positions based on our retail demand forecasts and market conditions. Our objective is to maintain a balanced supply/demand book to limit commodity risk exposure. We do not currently use derivative instruments and we do not plan to engage in uncovered or speculative trading of derivative instruments in the future, although we may use derivatives for hedging purposes in the future.
Our agreement with TXU PM provides both a source of electricity supply and vendor financing. Since our term commercial customer contracts generally have durations of one and two years, we endeavor to match term supply purchases to term customers obligations. We purchase electricity from TXU PM and from third parties based on our forecast of customer demand and monthly purchase limits imposed by TXU PM. Additionally, TXU PM reserves the right to review the credit-worthiness of all customers with peak demand of at least one megawatt. We pay a monthly credit fee to TXU PM based on our monthly electricity purchases from TXU PM, as well as small, fixed monthly administrative fees. TXU PM also provides credit guarantees to us to enable us to purchase electricity from third parties, in return for a monthly fee. The agreement has an initial term of five years, expiring in April 2008, and renews thereafter on a year-to-year basis unless either party gives notice of termination.
Purchasing this electricity exposes the wholesale electricity provider to credit risk that may exist due to any payment risk. Accordingly, TXU PM has three sources of security from us to support this agreement. First, TXU PM has a first lien on all of our assets, including our accounts receivable. Second, our customer receipts are managed through a lockbox arrangement with TXU PM under which certain costs of good sold items and the monthly TXU PM invoice are paid during each month with us receiving any remaining funds used for our operating expenses. TXU PM must approve all disbursements from our lockbox. Third, we are required to post a letter of credit, cash collateralized, in amounts determined by TXU PM pursuant our agreement.
We are currently in the process of negotiating agreements for electricity supply in markets outside of Texas.
Competition
Our competitors in the Texas market broadly fall into two categories. The first category consists of the affiliated REPs who inherited the “price-to-beat” customers (residential and small commercial) at the time the market opened to competition. As noted in “Regulatory Environment” above, the ability for the affiliated REPs to compete on price in their incumbent markets is dictated by specific rules. However, in all cases, the affiliated REPs enjoy the highest levels of brand recognition and familiarity, requiring competitive REPs, such as our company, to convince customers to switch their service away from the affiliated REPs. The affiliated REPs in Texas include: TXU Energy, Reliant Energy, First Choice Power, WTU Retail Energy, and CPL Retail Energy. The latter two affiliated REPs are owned by Direct Energy, a unit of Centrica PLC. Outside of their incumbent markets, these affiliated REPs compete on the same regulatory environment as does Gexa.
The second category of competitors consists of REPs that are not affiliated with any TDSPs. These include, but are not limited to, Green Mountain Energy, Cirro Energy,
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Strategic Energy, Constellation Energy and Utility Choice. Some of the REPs choose to compete only in small commercial, while others compete in both residential and small commercial. The sizes of these REPs vary as do their approach to the market.
While Texas has continued to see some new entrants during the past year, most of the focus in both the small commercial and the residential segments is on enticing customers to leave the affiliated REP’s service, and not on frequent switching between competitive retailers.
Subsequent Events
On March 28, 2005, the Company, and FPL Group, Inc., a Florida corporation (“FPL Group”), announced the execution of an Agreement and Plan of Merger, dated as of March 28, 2005 (the “Merger Agreement”), by and among FRM Holdings, LLC, a Delaware limited liability company (“FRM Holdings”), WPRM Acquisition Subsidiary, Inc., a Texas corporation and a wholly owned subsidiary of Holdings (“Merger Sub”), FPL Group and the Company, pursuant to which, subject to the satisfaction or waiver of the conditions therein, Merger Sub will merge with and into the Company (the “Merger”). As a result of the Merger, the Company will become an indirect wholly owned subsidiary of FPL Group. The Merger is intended to qualify as a tax-free reorganization under Section 368(a) of the Internal Revenue Code of 1986, as amended. Further information regarding the Merger is set forth in Note 19 to the Company’s 2004 financial statements included herein under Item 8. “Financial Statements and Supplementary Data”.
We have also recently undertaken certain changes in our disclosure controls and procedures in connection with a material weakness letter we received from our independent auditors, Hein & Associates, LLP on March 25, 2005. Further information regarding these changes is set forth herein in Item 9A. “Controls and Procedures—Changes to Disclosure Controls and Procedures.”
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RISK FACTORS
EARLY STAGE OPERATING COMPANY
We are an early stage operating company created for the purpose of providing electricity in deregulated electricity markets. We experienced significant growth in 2004, and future success is, to some degree, dependent upon our ability to continue to expand our operations through implementation of our business plan and model while devoting adequate resources to maintaining our existing customer base. We are subject to all of the risks inherent in attempting to expand a relatively new business venture. These risks include, but are not limited to, the possible inability to implement our business plan and the inability to fund the working capital requirements of our business plan. There can be no assurance that we will remain profitable, or that we will provide any return on invested capital.
We also operate in a new and very competitive industry that is emerging from the recent deregulation of the retail electricity market in Texas. The retail electric industry is in the early stages of development as a competitive industry and we expect there will be a great deal of change. Our success depends on our ability to adapt to changes in the industry, including changes to market dynamics and regulatory structures in Texas and in other markets which we may decide to enter in the future. It also depends on the continuing existence and development of market conditions, including regulatory matters, which enable independent retail electric providers to compete effectively against incumbent utilities and are favorable to our business model. Adverse changes in the industry, including its regulatory structure, could have a material adverse effect on our prospects, operating results and financial condition.
While our gross profits increased in 2004, we have also experienced a decrease in our gross profit percentage as a result of several factors including an increase in the number of commercial accounts we service. Due to competitive market forces, prices for commercial contracts typically yield lower margins per kWh than prices for residential contracts. We believe that as we grow a higher percentage of our revenues will be generated from commercial accounts and, therefore, expect that our gross margin percentage may continue to decline. Other factors may have an effect on our gross margin percentage and are described herein under the “Gross Profits” section of “Management’s Discussion and Analysis of Financial Condition and Result of Operations—Results of Operations.”
INABILITY TO MANAGE OUR GROWTH
Our customer base and operations have grown at a rapid rate in 2004. The further development of our operations will depend upon, among other things, our ability to expand our customer base in Texas and to enter new markets in a timely manner and at reasonable costs. In addition, our employee base has increased since inception and we anticipate that our employee base will continue to grow in order for us to accommodate our increased customer base. We may experience difficulty managing the growth of a portfolio of customers that is diverse both with respect to the types of services they will require, the
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market rules in their jurisdiction and the infrastructure delivering our products to those customers. Expanding our operations may also require continued development of our operating and financial controls and may place additional stress on our management and operational resources. If we are unable to manage our growth and development successfully, our operating results and financial condition could be materially adversely affected.
STRONG COMPETITION FROM INCUMBENT UTILITIES AND OTHER COMPETITORS
The market in which we compete is highly competitive, and we may not be able to compete effectively, especially against established industry competitors with significantly greater financial resources. We will face competition from many competitors with significantly greater financial resources, well-established brand names and large, existing installed customer bases. We expect the level of competition to intensify in the future. We expect significant competition from incumbent, traditional, and new electricity providers, many of whom have access to more significant capital resources.
In most markets, our principal competitor may be the local incumbent utility company or its affiliated incumbent REPs. This is the case in Texas where we currently operate. The incumbent utilities have the advantage of long-standing relationships with their customers, and they may have longer operating histories, greater financial and other resources and greater name recognition in their markets than we do. In addition, incumbent REPs have been subject to regulatory oversight, in some cases for close to a century, and thus have a significant amount of experience regarding the regulators’ policy preferences as well as a critical economic interest in the outcome of proceedings concerning their revenues and terms and conditions of service. Incumbent REPs may seek to decrease their tariffed retail rates to limit or to preclude the opportunities for competitive energy suppliers, and otherwise seek to establish rates, terms and conditions to the disadvantage of competitive REPs. Some of our competitors, including incumbent REPs, have formed alliances and joint ventures in order to compete in the restructured retail electricity and natural gas industry. Many customers of these incumbent REPs may decide to stay with their long-time energy provider if they have been satisfied with its service in the past. Therefore, it may be difficult for us to compete against incumbent REPs and their affiliates for customers who are satisfied with their historical utility provider.
In addition to competition from the incumbent and affiliated REPs, we face competition from a number of independent REPs. In Texas, these competitors include, but are not limited to, the following companies: Cirro Energy, Texas Commercial Energy, Liberty Power, Green Mountain and Direct Energy (an affiliate of American Electric Power). We also may face competition from large corporations in businesses with similar billing and customer service capabilities, such as telecommunication service providers, and nationally branded providers of consumer products and services that have a significant base of existing customers. Many of these competitors or potential competitors are larger than us and have access to more significant capital resources.
WE MAY HAVE DIFFICULTY RETAINING OUR EXISTING CUSTOMERS AND OBTAINING A SUFFICIENT NUMBER OF NEW CUSTOMERS
We anticipate that we will incur significant costs as we enter new markets outside of Texas 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 cannot assure that our future efforts to secure additional customers will provide the operating base needed to expand into additional markets. Many customers may be reluctant to switch to a new company for the supply of a commodity as critical to their well being as electric power. A major focus of our ongoing marketing effort is to demonstrate to potential customers that we will be a reliable provider with sufficient resources to meet our commitments. If our marketing strategy does not continue to be successful, our business, results of operations, and financial condition will be materially adversely affected.
We have been successful in gaining a significant number of customers in the markets where we operate. There exists, however, significant ongoing competition for these customers and we cannot assure that we will be able to retain such customers. In addition, as part of our business, we will periodically discontinue service to particular customers who represent a bad credit risk or where continued service to such customer is not economically advantageous to us. We believe our growth will continue in the Texas market, but not as rapidly as during 2004.
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CERTAIN COMPETITIVE RESTRICTIONS FOR THE RESIDENTIAL SEGMENT APPLICABLE TO INCUMBENT REPS EXPIRED ON JANUARY 1, 2005
In Texas, the “price-to-beat” rule requires the incumbent REPs to charge only one price until certain conditions are met. For under one megawatt commercial consumers, incumbent REPs can only charge the “price-to-beat” until either 40% of the load in the incumbent market is no longer served by incumbent REP or until January 1, 2005. All of the incumbent REPs met the 40% threshold by late 2003, and therefore may charge a rate that is lower than the “price-to-beat” for the under one megawatt commercial market.
For residential consumers, prior to January 1, 2005 incumbent REPs could only charge the “price-to-beat.” Beginning January 1, 2005, the incumbent REPs may offer a rate that is lower than the price-to-beat.
Our ability to obtain new customers or even retain existing customers may be adversely affected by the termination of these restrictions.
Further, for both under one megawatt commercial consumers and residential consumers, incumbent REPs are restricted from charging a rate that is higher than the “price-to-beat” in their incumbent market until after January 1, 2007, without the approval of the PUCT.
WEATHER AND OTHER RELATED COMMODITY RISKS MAY AFFECT OUR ABILITY TO MANAGE AND MAINTAIN A BALANCED SUPPLY/DEMAND BOOK
Commitments for future purchase of electricity supply (forward power contracts) are based not only on our expected customer base at a given point in time, but also weather forecasts for the geographical areas in which we operate. We maintain a long position in our forward power contracts (contracted electricity supply purchases are slightly greater than forecasted demand by our customers) to minimize the need to purchase power on the balancing markets at varying market prices. However, fluctuations in actual weather conditions can have an impact on the actual power needs of customers on a given day. Extreme weather conditions may force us to purchase electricity supply on the balancing markets on days when weather is unexpectedly severe, and the pricing for balancing market energy can be significantly higher on such days than the cost of electricity in our forward contracts. Unusually mild weather conditions could leave us with excess power which may be sold in the balancing markets at a loss if the balancing market price is lower than the Company’s forward contract prices.
Commodity pricing is an inherent component of our financial results. The prevailing market prices for electricity and fuel in the market may fluctuate substantially over relatively short periods of time, potentially adversely impacting our results of operations, financial condition and cash flows. Changes in market prices for electricity and fuel may result from any of the following:
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• weather conditions;
• seasonality;
• demand for energy commodities and general economic conditions;
• forced or unscheduled plant outages;
• disruption of electricity or gas transmission or transportation infrastructure or other constraints or inefficiencies;
• addition of generating capacity;
• availability of competitively priced alternative energy sources;
• availability and levels of storage and inventory for fuel stocks;
• natural gas, crude oil and refined products, and coal production levels;
• the creditworthiness or bankruptcy or other financial distress of market participants;
• changes in market liquidity;
• natural disasters, wars, embargoes, acts of terrorism and other catastrophic events; and
• federal, state and foreign governmental regulation and legislation.
WE HAVE A LEVERAGED CAPITAL STRUCTURE AND THE TERMS OF OUR DEBT MAY SEVERELY LIMIT OUR ABILITY TO PLAN FOR OR RESPOND TO CHANGES IN OUR BUSINESS
We have a leveraged capital structure due to the facility with Highbridge/Zwirn Special Opportunities Fund, L.P. (“Highbridge”) and our credit arrangements with TXU PM, which limits our financial flexibility. For a description of these obligations, see “Management Discussion and Analysis—Liquidity and Capital Resources” herein. Our level of indebtedness has several important effects on our future operations including:
• a substantial portion of our cash flow from operations will need to be dedicated to payment of interest on our indebtedness;
• covenants contained in our debt obligations require us to meet certain financial tests, and other restrictions limit our ability to borrow additional funds or dispose of assets and may affect our flexibility in planning for,
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and reacting to, changes in our business, including possible acquisition activities; and
• our ability to obtain financing in the future for working capital, capital expenditures, acquisitions, general corporate purposes and other purposes may be impaired.
Our ability to meet our debt service obligations and to reduce our total indebtedness will be dependent upon future performance, which will be subject to general economic conditions and financial, business and other factors affecting our operations, many of which are beyond our control. In addition, our ability to comply with the covenants in our debt agreements, as they currently exist or as they may be modified, may be affected by many events beyond our control and our future operating results may not allow us to comply with those financial covenants. Our failure to comply with the covenants could result in a default, which could cause our indebtedness to become immediately due and payable. If we are unable to repay those amounts, Highbridge, subject to the senior security interests of TXU PM, may proceed against the collateral. If those holders accelerate the payment of our subordinated debt, it is unlikely that we could pay that indebtedness immediately and continue to operate our business.
DELAY IN DEREGULATION IN OTHER STATES OR CHANGE IN COMPETITIVE MARKET RULES
To date, only a limited number of markets have opened to retail energy competition. In many of these markets, the market rules adopted have not resulted in energy service providers being able to compete successfully with the incumbent utilities, and customer-switching rates have been low. Only recently have a number of markets opened to competition under rules, some of which we believe may offer attractive competitive opportunities. Texas, our primary marketplace since inception, is among them. Our business model may depend 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 that market. Markets that we enter may have both favorable and unfavorable rules. While many markets outside of Texas continue their support for retail competition and industry restructuring, others that were considering deregulation have slowed their plans or postponed consideration. In addition, some states are reconsidering deregulation. 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, incumbent utilities, consumer advocacy groups, and potential market participants. As a result, the extent to which there are legitimate competitive opportunities for alternative energy suppliers in a given jurisdiction may vary widely, and we cannot assure you that regulatory structures will offer us competitive opportunities to sell energy to consumers on a
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profitable basis. The regulatory process could be negatively impacted by a number of factors, including interruptions of service, significant or rapid price increases, and other factors, which may be attributed by opponents of competition in these markets to restructuring and to the lack of regulatory control. The legislative and regulatory processes in some states take prolonged periods. In a number of jurisdictions, it may be many years from the date legislation is enacted until restructuring is completed.
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 you that federal legislation will not be passed in the future that could materially adversely affect our business.
EXTENSIVE GOVERNMENTAL REGULATION MAY INCREASE OUR COSTS AND SLOW OUR GROWTH
Significant regulations imposed at the international, federal, state and local levels govern the provision of utility services and affect our business and our existing and potential competitors. Delays in receiving required regulatory approvals, the enactment of new and adverse legislation, regulations or regulatory requirements or the application of existing laws and regulations to certain services may have a material adverse effect on our business, financial condition, results of operations and cash flow. In addition, future legislative, judicial and regulatory agency actions could alter competitive conditions in the markets in which we intend to operate, in ways not necessarily to our advantage.
ERCOT has and may continue to modify the market structure and other market mechanisms in an attempt to improve market efficiency. Moreover, existing regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to our commercial activities. These actions could have a material adverse effect on our results of operations, financial conditions and cash flows.
WE BEAR THE CREDIT RISK AND BILLING RESPONSIBILITY FOR OUR CUSTOMERS
In Texas, the primary market in which we currently operate, we are responsible for the billing and collection functions for our customers. As we seek to expand our operations into additional markets, the billing and collection functions may also be our responsibility. In many of 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 electricity bill in a timely manner, we may remain liable to our suppliers of electricity for the cost of those commodities and to the local utilities for services related to the transmission and distribution of electricity and 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.
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The Company has placed several initiatives in place to help manage the credit risk of our customers, including the following:
• increasing the number and amount of security deposits required;
• aggressive inside collection efforts;
• providing more convenient payment methods;
• engaging outside collection agencies; and
• charging late fees on past due balances.
In 2004, the PUCT enacted legislation which permits independent REPs to order the disconnection of electricity services of customers who fail to pay their bills in a timely manner, with certain exceptions including extreme weather conditions and whether the customer’s meter is used to power life support systems. We anticipate that the ability to disconnect delinquent customers will have a positive impact on the receivables collection process for all market participants. These actions, along with the reduction in problems related to receiving timely customer meter reads, contributed to a reduction in our bad debt expense as a percentage of sales from 3.4% as of December 31, 2003 to 2.6% as of December 31, 2004.
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DEPENDENCE ON PROVIDERS OF ELECTRICITY FOR RESALE AND RELIANCE ON TXU FOR FINANCIAL SUPPORT
We must rely on a limited number of suppliers of wholesale electricity in order to meet our customer’s needs. The unavailability of electricity from one or more of our suppliers at times of high demand could have an adverse impact on our financial condition if we are forced to purchase substantial electricity supply in the open market to meet customer demand at a time when energy prices are volatile. Our primary supplier of electricity in Texas is TXU PM. We have entered into a five-year wholesale credit agreement with TXU PM which allows us to purchase electricity in Texas with the credit backing of TXU PM. In exchange for the credit support, we granted TXU PM a first lien on our receivables, assets and contracts.
The TXU PM agreement also has a monthly limit for megawatt hours, which was increased in 2004 to enable us to continue to grow and handle the higher seasonal summer volumes. Given our recent growth experience, we anticipate that we may reach such monthly limit in future periods of high demand and may potentially need to increase such monthly limit through further negotiations with TXU PM or through other suppliers. There is no guaranty that TXU PM will be willing to increase this limit or that we could find alternate suppliers to provide such electrical demand on terms acceptable to us.
As of December 31, 2004, we had deposited approximately $5.8 million with JP Morgan Chase Bank to obtain letters of credit allowing us to purchase power on forward contracts from TXU PM, buy and sell power in the daily balancing markets and pay TDSP invoices for metering charges passed through to customers on thirty-five day terms. We believe that we have sufficient liquidity to support the letters of credit that may be required. However, we cannot assure that we will have sufficient liquidity in the future to support customer growth and anticipated increases in power purchases. As we grow, our letter of credit requirement may become larger and other terms may change and adversely affect us.
OUR SUCCESS IN TEXAS MAY NOT TRANSLATE TO OTHER DEREGULATED MARKETS
While we are actively reviewing various opportunities in markets outside Texas, there can be no assurance that we will be able to replicate our model outside of the Texas market. We also are currently licensed to supply retail electricity power to the Massachusetts electricity market and have submitted applications to become an electricity provider in New York and Maine. Other states that are currently in various phases of deregulation of their retail electricity market include: Arizona, Connecticut, Delaware, District of Columbia, Illinois, Maryland, Michigan, Nevada, New Hampshire, New Jersey, Ohio, Oregon, Pennsylvania, Rhode Island and Virginia. The regulations relating to the markets in these states vary from the regulations in Texas. In any particular market, there are a number of rules that will ultimately determine the attractiveness of that market. Markets that we seek to enter may have both favorable and unfavorable rules. In addition, the relative size,
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demographics and energy consumption patterns of a particular market may not allow us to use the same or similar growth strategies as we have used in Texas. In addition, we must be able to procure necessary supply and credit agreements through energy wholesalers in any markets that we seek to enter. There can be no assurance that we will be able to secure such agreements on terms that allow us to effectively serve these other markets.
RELIANCE ON INFORMATION TECHNOLOGY SYSTEMS
Our business is dependent on information sharing among market participants (including ERCOT, the TDSPs, and third-party service providers). This information includes customer enrollment information, ERCOT transactions, meter readings, invoices for wire line charges, etc. Therefore, our success as an independent REP is impacted by our ability to handle this information and we are dependant on third parties to provide timely and accurate information to us. We rely on a combination of internal systems including telephone, internet, load forecasting, as well as systems operated by third parties. Failure to receive timely and accurate information could have an adverse impact on our business.
We have implemented both processes and infrastructure to provide for redundancy of core data due to business interruption associated with our billing platform; however, that is only one component of our business model. In addition, our systems and those we rely upon from third parties need continued development and investment to ensure reliability and scalability as our business grows at a rapid rate.
Despite the implementation of security measures, our networks may be vulnerable to unauthorized access, computer viruses and other disruptive problems. A party who is able to circumvent security measures could misappropriate proprietary information or cause interruptions in our Internet operations. We may be required to expend significant capital or other resources to protect against the threat of security breaches or to alleviate problems caused by such breaches. Although we intend to continue to implement industry-standard security measures, there can be no assurance that measures implemented by us will not be circumvented in the future.
RELIANCE ON TDSPS AFFILIATED WITH OUR COMPETITORS TO PERFORM SOME FUNCTIONS FOR OUR CUSTOMERS
Under the regulatory structures adopted in most jurisdictions, we will be required to enter into agreements with local incumbent utilities for use of the local distribution systems, and for the creation and operation of functional interfaces necessary for us to serve our customers. While we currently enjoy acceptable agreements in Texas, any delay in future negotiations for access to new markets or our inability to enter into reasonable agreements to operate in new markets could delay or negatively impact our ability to serve customers in those jurisdictions, which could have a material negative impact on our business, results of operations, and financial condition.
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We are dependent on TDSPs for maintenance of the infrastructure through which we deliver electricity to our retail customers. Any infrastructure failure that interrupts or impairs delivery of electricity to our customers could negatively impact the satisfaction of our customers with our service and could have a material adverse effect on our results of operations, financial condition and cash flow. Additionally, we are dependant on TDSPs for performing service initiations and changes, and for reading our customers’ energy meters. We are required to rely on the TDSPs, or, in some cases, ERCOT, to provide us with our customers’ information regarding energy usage, and we may be limited in our ability to confirm the accuracy of the information. The provision of inaccurate information or delayed provision of such information by the TDSPs or ERCOT could have a material adverse effect on our business, results of operations, financial condition and cash flow. In addition, any operational problems with our new systems and processes could similarly have a material adverse effect on our business, results of operations, financial condition and cash flow.
PAYMENT DEFAULTS BY OTHER REPS TO ERCOT
In the event of a default by a REP of its payment obligations to ERCOT, the portion of that obligation that is unrecoverable by ERCOT from the defaulting REP is assumed by the remaining market participants in proportion to each participant’s load ratio share. As a REP and market participant in ERCOT, we would pay a portion of the amount owed to ERCOT should such a default occur, and ERCOT is not successful in recovering such amounts. Any such default of a REP in its obligations to ERCOT could have a material adverse effect on our business, results of operations, financial conditions and cash flows.
ERCOT HAS EXPERIENCED PROBLEMS WITH ITS INFORMATION SYSTEMS
ERCOT is the independent system operator responsible for maintaining reliable operations of the bulk electric power supply system in the ERCOT Region and for acting as a central agent for the registration of customers with their chosen retail electric supplier. Its responsibilities include ensuring that information relating to a customer’s choice of REP, including data needed for on-going servicing of customer accounts, is conveyed in a timely manner to the appropriate parties. Problems in the flow of information between ERCOT, the TDSPs and the REPs have resulted in delays and other problems in enrolling and billing customers. While the flow of information has improved materially over the course of the last two years of full market choice operations, remaining system and process problems are still being addressed. When customer enrollment transactions are not successfully processed by all involved parties, ownership records in the various systems supporting the market are not synchronized properly and subsequent transactions for billing and settlement are adversely affected. The impact can include us not being the electric provider-of-record for intended or agreed upon time periods, delays in receiving customer consumption data that is necessary for billing and settlement either through ERCOT or directly with TDSPs, as well as the incorrect application of rates or prices and imbalances in our electricity supply forecast and actual sales.
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IF WE ARE UNABLE TO MAINTAIN EFFECTIVE INTERNAL CONTROLS AND PROCEDURES, THERE COULD BE A MATERIAL ADVERSE EFFECT ON OUR OPERATIONS OR FINANCIAL RESULTS
During both the audit of our fiscal year end 2004 and 2003, our independent auditors, Hein & Associates LLP (“Hein”), issued material weakness letters noting significant deficiencies in our internal controls. The letters related to different matters.
On March 25, 2005, Hein issued a material weakness letter related to the audit of our fiscal year end 2004 identifying a deficiency in our internal controls. The deficiency identified by Hein was that we did not adequately provide information to Hein regarding a control deficiency over input of rates into our billing system and a resulting reserve accrual. In addition, Hein indicated that the Company failed to fully investigate and quantify the extent of the error caused by such control deficiency. The deficiency arose in connection with our determination of the size of our reserve for customer credits to be issued relating to errors in inputting rates on our billing system.
In response to the initial inquiries of Hein related to this matter, the Audit Committee of our Board of Directors, with the assistance of external counsel, conducted a review of this matter through discussions with the outside auditor, review of the applicable documents and interviews and discussions with our management. On March 25, 2005, the Audit Committee recommended an action plan related to this material weakness, which was implemented immediately, which included the following action items:
• In 2004, we created a Disclosure and Materiality Committee that includes our CEO, CFO, COO and those staff people responsible for SEC reporting and monitoring of new or amended regulations, including the employee responsible for investor relations. The committee shall be responsible for the determination that disclosure of all material information has been made in each applicable proposed public filing or furnishing of information by us pursuant to the Securities Act and the Exchange Act and that all disclosures are made on a timely basis. Our outside accountants and counsel will be invited to participate in any meeting of this committee and the timing of those meetings will be set to ensure their attendance.
• Any reserves suggested by our management for inclusion in our financial statements must be disclosed to and approved by the Audit Committee and
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disclosed to our outside auditors, in each case with sufficient detail to enable an understanding of the reasons for the reserve. Upon establishment of any such reserve, our management shall, in subsequent financial periods, perform the applicable investigation to confirm the need and size of such reserve, as applicable, and report those findings to the Audit Committee and outside auditors on a timely basis.
The audit committee’s report further concluded that the control deficiency related to input of rates into our billing system was corrected by the Company as of the third quarter of 2004, and probably did not result in a material error to the Company’s financial statements.
In addition, during the audit of our fiscal year 2003, Hein issued a material weakness letter relating to our internal controls and procedures. The material weakness identified by Hein was discovered in connection with a review by Hein of the our proposed changes to our revenue calculation method. Management began the process of reviewing our revenue calculation method in November 2003. The identified deficiencies were the following:
• inadequate U.S. GAAP, financial reporting and public company expertise and experience within our accounting department; and
• inadequate quality control over the financial reporting process, including inadequate review of facts, circumstances and events impacting estimates and judgments requiring accounting recognition or disclosure.
Hein also indicated at that time that our new method for calculating our revenues required additional review and testing. Previously, we estimated revenues based on billings (the “billing” method), but the availability of accurate and timely electricity supply delivery data for the entire 2003 fiscal year allowed us to estimate revenues based on measuring electricity as delivered to our customers (the “flow” method). In the fourth quarter of 2003 and first quarter of 2004, we conducted additional testing and review of the controls and the source data being used to calculate revenues as well as the flow method of
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revenue calculation. Based on that review, we adopted the flow method for determining its revenues in fiscal year 2003 and thereafter.
In response to this prior material weakness letter, the Audit Committee of our Board of Directors, with the assistance of independent counsel, began an investigation of the issues raised by our auditors, including our revenue calculation methods, which process was completed in the second quarter of 2004. The Audit Committee recommended, and the Board of Directors reviewed and adopted, an action plan during the second quarter of 2004. The action plan was fully implemented as of September 30, 2004, through the following actions:
• the institution of new document control procedures, including an updated disaster and recovery plan;
• David K. Holeman’s election as Vice President and Chief Financial Officer on June 2, 2004;
• the hiring of a Controller and a Manager of Financial Reporting, each with experience in SEC reporting and accounting, and a Human Resources Manager;
• the creation of interim policies and procedures for the issuance of press releases and the preparation of SEC reports;
• the establishment of an internal Disclosure Review Committee to review and coordinate SEC reports and prepared an interim policy regarding the notification of senior management and the Board of material developments;
• the completion of a training program for all relevant personnel regarding SEC reporting, Sarbanes-Oxley Act compliance, and related issues; and
• the selection of a provider for Sarbanes-Oxley Act Section 404 related services and to assist us in a review and assessment of our accounting policies and procedures.
We will continue to evaluate the effectiveness of internal controls and procedures on an ongoing basis. It should be noted that in designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired controlled objectives, and management necessarily was required to apply its judgment in evaluating the cost benefit relationship of possible controls and procedures. Based on the evaluation described above and the implementation of the action plans described above, our CEO and CFO have concluded that our disclosure controls and procedures are effective at reaching that level of reasonable assurance.
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Our management does not expect that our disclosure controls and procedures, or its internal control over financial reporting, will prevent all error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Over time, controls may become inadequate because of changes in conditions, or the degree of compliance with the policies or procedures may deteriorate. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.
Our Board of Directors, in coordination with our Audit Committee, will continually assess the sufficiency of these initiatives and make adjustments as necessary. If we are unable at any time to continue to maintain an effective system of internal controls and procedures, there could be a material adverse effect on our operations or financial results.
WE MAY HAVE A CONTINGENT LIABILITY ARISING OUT OF THE ISSUANCE OF SHARES TO THE STOCKHOLDERS OF GEXA GOLD
Gexa was formed as a Texas corporation in 2001 to conduct all of the Company’s business, and is the successor to Gexa Gold Corp., a Nevada corporation (“Gexa Gold”). Gexa and Gexa Gold executed an agreement in January 2001 whereby Gexa Gold would be reincorporated as a Texas corporation by merging with Gexa. However, no shareholder meeting was held and no documentation relating to the contemplated reincorporation merger of Gexa and Gexa Gold was filed with the Secretary of State of Nevada or of Texas or the Securities and Exchange Commission (“SEC”). Gexa Gold also forfeited its charter in 1998 for failure to pay its annual taxes and file its annual report in Nevada. However, Gexa has operated as if the reincorporation merger occurred, issued 377,957 shares of Gexa common stock to the stockholders of Gexa Gold, and has assumed effective as of January 31, 2001, the assets and liabilities of Gexa Gold and Gexa Gold’s obligation to file reports with the SEC. Gexa also filed a number of reports with the SEC in order to make Gexa Gold current in its SEC Reporting obligations. Gexa Gold had not filed the required SEC reports for nine years prior to Gexa’s succession to Gexa Gold in 2001.
Under Nevada law, the directors of Gexa Gold hold all of the property and assets of Gexa Gold in trust after its charter was forfeited and are able to act with respect to that property and assets in the same manner as is applicable to insolvent corporations under the Nevada Revised Statutes. In October 2003, after discovering that no merger documents had
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been filed, the former directors of Gexa Gold entered into a new agreement to transfer to Gexa all of Gexa Gold’s assets and liabilities as if the merger of Gexa and Gexa Gold had occurred as the parties intended. By this remedial action, the parties have effectuated their intention to merge Gexa Gold with Gexa in January 2001.
The 377,957 shares of common stock issued to the stockholders of Gexa Gold in 2001 were issued without being registered under the Securities Act of 1933, but exemptions from such registration requirements may be available. Gexa may have a contingent liability to the stockholders of Gexa Gold arising out of a possible violation of Section 5 of the Securities Act of 1933 in connection with the issuance of these unregistered shares if such exemptions are not available. As Gexa Gold common stock has no value and was not traded at the time of the issuance of the Gexa stock in 2001, Gexa does not believe the Gexa Gold stockholders have any measurable or recoverable damages relating to these possible claims. The statute of limitations may also limit the ability of some stockholders to bring any such claims. Additionally, the SEC could bring civil penalties against Gexa for Gexa Gold’s failure to file required reports and the failure to comply with SEC Rules relating to the merger of Gexa and Gexa Gold, which actions could include monetary penalties and other administrative remedies. If any such claims are asserted, we intend to contest the matter vigorously.
DEPENDENCE ON KEY PERSONNEL
We are substantially dependent upon the continued services of our present management, including Neil M. Leibman, our Chairman and CEO. To the extent that Mr. Leibman’s services become unavailable, we will be required to retain other qualified personnel. We are currently conducting a search for a new President and COO to replace James A. Burke, who resigned effective October 1, 2004. There can be no assurance that we will be able to recruit and hire a COO or other qualified persons under acceptable terms.
WE ARE SUBSTANTIALLY CONTROLLED BY OUR CHAIRMAN AND CHIEF EXECUTIVE OFFICER
Our Chairman and Chief Executive Officer, Neil M. Leibman, beneficially owns or controls shares of our common stock and other convertible securities representing approximately 36.3% of the issued and outstanding shares of our common stock. As a result, Mr. Leibman has the ability to exercise substantial control over our affairs and corporate actions requiring shareholder approval, including electing directors, a merger, or selling all or substantially all of our assets. Control by Mr. Leibman could delay, deter or prevent a change in control and could adversely affect the price that investors might be willing to pay in the future for our securities.
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STATE BLUE SKY REGISTRATION; POTENTIAL LIMITATIONS ON RESALE OF THE SECURITIES
Because our common stock has not been registered for resale under the Act or the “blue sky” laws of any state, the holders of such shares and persons who desire to purchase them in any trading market that might develop in the future, should be aware that there may be significant state blue-sky law restrictions upon the ability of investors to resell our securities. Accordingly, investors should consider the secondary market for our securities to be a limited one.
We intend to seek coverage and publication of information regarding the Company in an accepted publication manual which permits a manual exemption. The manual exemption permits a security to be distributed in a particular state without being registered if the issuer of that security has a listing for that security in a securities manual recognized by the state. However, it is not enough for the security to be listed in a recognized manual. The listing entry must contain (1) the names of issuers, officers, and directors, (2) an issuer’s balance sheet and (3) a profit and loss statement for either the fiscal year preceding the balance sheet or for the most recent fiscal year of operations. Furthermore, the manual exemption is a non-issuer exemption restricted to secondary trading transactions, making it unavailable for issuers selling newly issued securities.
Most of the accepted manuals are those published in Standard and Poor’s, Moody’s Investor Service, Fitch’s Investment Service, and Best’s Insurance Reports, and many states expressly recognize these manuals. A smaller number of states declare that they “recognize securities manuals” but do not specify the recognized manuals. The following states do not have any provisions and therefore do not expressly recognize the manual exemption: Alabama, California, Georgia, Illinois, Kentucky, Louisiana, Montana, South Dakota, Tennessee, Vermont and Wisconsin.
POTENTIAL REQUIREMENT TO COMPLY WITH PENNY STOCK RULES
Our securities are considered “penny stocks” as defined in the Exchange Act and the rules thereunder, to the extent the price of shares of our common stock is less than $5.00. Unless our common stock is otherwise excluded from the definition of “penny stock,” the penny stock rules apply with respect to that particular security. The penny stock rules require a broker-dealer prior to a transaction in penny stock not otherwise exempt from the rules, to deliver a standardized risk disclosure document prepared by the SEC that provides information about penny stocks and the nature and level of risks in the penny stock market. The broker-dealer also must provide the customer with current bid and offer quotations for the penny stock, the compensation of the broker-dealer and its sales person in the transaction, and monthly account statements showing the market value of each penny stock held in the customer’s account. In addition, the penny stock rules require that the broker-dealer, not otherwise exempt from such rules, must make a special written determination that the penny stock is suitable for the purchaser and receive the purchaser’s written agreement to the transaction. These disclosure rules have the effect of reducing the
29
level of trading activity in the secondary market for a stock that becomes subject to the penny stock rules. So long as our common stock is subject to the penny stock rules, it may become more difficult to sell such securities. Such requirements, if applicable, would result in a reduction in the level of trading activity for our common stock and would make it more difficult for investors to sell shares of our common stock.
LITIGATION RISKS
We currently are involved in various litigation matters which are described herein in the section entitled “Legal Proceedings”. Any such claim or any future claims, regardless of merit:
• is time consuming and costly to defend and may harm our reputation;
• diverts management’s attention and resources; and
• if resolved adversely against us, could require the payment of monetary damages.
Any of these consequences could impair our financial condition and adversely affect our ability to conduct our business.
POTENTIAL NEGATIVE EFFECT ON OUR STOCK PRICE RELATED TO SHARES ELIGIBLE FOR FUTURE SALE
The issuance of a significant number of shares of common stock upon the exercise of stock options and warrants, or the availability for sale or sale of a substantial number of the shares of common stock eligible for future sale under effective registration statements, Rule 144 or otherwise, could adversely affect the market price of the common stock. We have reserved approximately 3.6 million shares of common stock for issuance under outstanding options and warrants, of which 2.4 million are registered for resale on currently effective registration statements. Further, we are aware that (1) affiliates of Corsair Capital Management, LLC currently hold 1,176,008 shares of our common stock and currently exercisable options to purchase an additional 105,000 shares of our common stock and (2) affiliates of Perry Corp. currently hold 950,000 shares of our common stock, all of which shares have been registered for resale under the Securities Act and are available for sales in the market without restriction. In addition, an additional 3,812,432 shares beneficially held by Neil M. Leibman, our Chairman and Chief Executive Officer, will become eligible for resale under Rule 144, subject to limitations on Mr. Leibman as an “affiliate” of the Company, upon the expiration of his lock-up agreement with Oppenheimer & Co. Inc., which expires on the later of 180 days after closing of the Oppenheimer financing (November 23, 2004) or 90 days after the effectiveness of our registration on Form S-1 (No. 333-121548) (which went effective on March 7, 2005).
30
AVAILABLE INFORMATION
We will make available our annual report on Form 10-K, our quarterly reports on Form 10-Q, our current reports on Form 8-K, and amendments to those reports, filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, free of charge through our Internet website at www.gexaenergy.com as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission.
The information contained on our website is not incorporated by reference into this Form 10-K and should not be considered to be a part of this Form 10-K.
31
ITEM 2. PROPERTIES
Our offices are presently located at 20 Greenway Plaza, Suite 600, Houston, Texas 77002. The office facility consists of approximately 27,000 square feet of office space under lease through January 2011. We remain liable for monthly rent obligations under the lease for our old office space at 24 Greenway Plaza, but, during the third quarter of 2004, we entered into a sublease agreement for the old office space whereby the sublease tenant, Consultants Choice Inc., pays approximately 40% of our monthly rental obligation.
ITEM 3. LEGAL PROCEEDINGS
During 2003, we were sued in the matter of Kyle Holland vs. Gexa Corp. et al. in the United States District Court, Western District of Texas. Mr. Holland alleged damages in connection with his acquisition of our common stock. The complaint seeks unspecified damages. On March 15, 2005, this case was dismissed without prejudice for failure to state a claim. While this lawsuit could be refiled at a later date, we believe the lawsuit has no merit and will vigorously defend any such refiled action.
On July 15, 2004, a class action lawsuit Frederick T. Pappey, et al. vs. Gexa Corp., Neil Leibman, Marcie Zlotnik and Sarah Veach, Civil Action No. H-04-2869, was filed in the United States District Court for the Southern District of Texas, Houston District. The complaint alleges, among other things, that our publicly filed reports and public statements contained false and misleading information, which resulted in damages to the plaintiff and members of the proposed class when they purchased our securities. Specifically, the complaint alleges that we overstated revenue during the second and third quarters of 2003 by $2.07 million and $2.05 million, respectively, by utilizing an improper accounting method for calculating sales of electric power. The complaint alleges that our conduct and the conduct of the other defendants violated Sections 10(b) and 10b-5 and that the individual defendants violated Section 20(a) of the Securities Exchange Act of 1934. The complaint seeks unspecified damages. On December 20, 2004, the lawsuit was dismissed without prejudice. While this lawsuit could be refiled at a later date, we believe the lawsuit has no merit and will vigorously defend any such refiled action.
On November 30, 2004, we entered into a settlement with Capello Capital Corp. (“Capello”) relating to the matter of Capello Capital Corp. vs. Gexa Corp, originally filed in the Los Angeles Superior Court-West District. Capello’s complaint had alleged a breach of contract regarding investment banker fees being claimed by Capello in connection with the credit facility with Highbridge/Zwirn Special Opportunities Fund, L.P. In exchange for Capello’s agreement to dismiss the lawsuit and release its claims against us, we agreed to: (i) pay Capello $275,000, (ii) issue to Capello warrants dated November 1, 2004, to purchase 400,000 shares of our common stock at an exercise price of $4.50 per share and (iii) issue to Capello an interest free unsecured promissory note in the principal amount of $500,000. We accrued $1.2 million in the third quarter of 2004 in investment banking charges to other assets as deferred financing cost to be amortized over the life of the Highbridge facility.
32
On December 2, 2004, we were sued in the matter of Essential Utilities Corporation v. Gexa Energy Corp., Cause No. 04-12056, in the 191st District Court of Dallas County, Texas. The petition alleges breach of contract, quantum meruit, conversion and unjust enrichment in connection with the alleged nonpayment of consultation fees. The amount of the claim is unknown. This case is in the preliminary stages and we intend to contest this suit vigorously.
On January 31, 2005, a lawsuit styled Griffin/Juban Capital Management, L.L.C. d/b/a GC Realty Services v. Gexa Corporation was filed in the 11th Judicial District Court of Harris County, Texas. This lawsuit claims that we agreed to provide Continental Airlines frequent flyer miles to the plaintiff in turn for doing business with us. The plaintiff has sued us for breach of contract, fraud and negligent misrepresentation. The amount of damages sought in the lawsuit is unknown. This case is in the preliminary stages and we intend to contest this suit vigorously.
On or about February 11, 2005, we were made aware of a potential lawsuit that may be filed by Prenova, Inc. and 24 Hour Fitness USA, Inc. against us and XERS, Inc. d/b/a XCEL Energy, Inc. The proposed complaint claims that we failed to timely provide electrical service to 24 Hour Fitness and, as a result, they incurred substantial damages in the form of significantly higher rates for several months in 2004. The plaintiffs claim damages in the amount of $150,000.00 plus interest and attorneys’ fees. If filed, we intend to contest this suit vigorously.
We are also involved in various receivable collections matters as a plaintiff. We believe that there are no pending matters that will have a significant impact on our financial position or results of operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None.
33
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
Market Information
On August 2, 2004, our common stock began trading on the Nasdaq SmallCap Market under the stock symbol GEXA. Prior to August 2, 2004, our common stock was traded on the OTC:BB market under the symbol GEXC.OB. We believe that our listing on the Nasdaq SmallCap Market has provided us additional visibility and access to incremental investors and enhanced the liquidity of our common stock.
The following information presented in the table below shows the high and low bid prices for the year ended December 31, 2003 and the high and low bid prices (prior to August 2, 2004) or sales prices (beginning August 2, 2004) for the year ended December 31, 2004 for our common stock as reported:
|
|
|
High |
|
Low |
|
||
|
Fiscal Year 2003 |
|
|
|
|
|
||
|
|
|
|
|
|
|
||
|
Quarter Ended March 31, |
|
$ |
1.90 |
|
$ |
0.75 |
|
|
|
|
|
|
|
|
||
|
Quarter Ended June 30, |
|
$ |
1.90 |
|
$ |
1.10 |
|
|
|
|
|
|
|
|
||
|
Quarter Ended September 30, |
|
$ |
2.60 |
|
$ |
1.45 |
|
|
|
|
|
|
|
|
||
|
Quarter Ended December 31, |
|
$ |
9.00 |
|
$ |
2.10 |
|
|
|
|
|
|
|
|
||
|
Fiscal Year 2004 |
|
|
|
|
|
||
|
|
|
|
|
|
|
||
|
Quarter Ended March 31, |
|
$ |
8.50 |
|
$ |
3.30 |
|
|
|
|
|
|
|
|
||
|
Quarter Ended June 30, |
|
$ |
6.60 |
|
$ |
3.15 |
|
|
|
|
|
|
|
|
||
|
Quarter Ended September 30, |
|
$ |
6.60 |
|
$ |
4.30 |
|
|
|
|
|
|
|
|
||
|
Quarter Ended December 31, |
|
$ |
5.24 |
|
$ |
4.05 |
|
Holders of Common Stock
As of March 23, 2005, we had approximately 2,400 holders of record of our common stock.
34
Dividends
We have not paid any dividends on our common stock, and do not intend to pay dividends in the foreseeable future. We intend to retain earnings to finance the development and expansion of our business. Payment of dividends in the future will depend, among other things, on our ability to generate earnings, on our need for capital and on our overall financial condition. The potential for future dividend payments may also be limited by the terms of our credit agreements.
Equity Compensation Plan Information
The information required by this item will be included in a definitive proxy statement, pursuant to Regulation 14A, to be filed not later than 120 days after December 31, 2004. Such information is incorporated herein by reference.
35
ITEM 6. SELECTED FINANCIAL DATA
The selected financial data in the following table sets forth (a) consolidated balance sheet data as of December 31, 2002, 2003 and 2004, and statement of operations data for the fiscal years ended December 31, 2002, 2003 and 2004 derived from our consolidated financial statements audited by Hein & Associates LLP, independent registered public accounting firm and (b) consolidated balance sheet data as of December 31, 2000 and 2001, and statement of operations data for the fiscal years ended December 31, 2000 and 2001 derived from our consolidated financial statements audited by Grassano Accounting, P.A. The information below should be read in conjunction with “Item 8. Financial Statements and Supplementary Data” included elsewhere in this filing.
|
(in thousands except for per share data) |
|
Fiscal 2004 |
|
Fiscal 2003 |
|
Fiscal 2002 |
|
Fiscal 2001 |
|
Fiscal 2000 |
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Statement of Operations Data: |
|
|
|
|
|
|
|
|
|
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Sales |
|
$ |
273,894 |
|
$ |
115,143 |
|
$ |
19,039 |
|
$ |
— |
|
$ |
— |
|
|
Cost of goods sold |
|
238,206 |
|
99,697 |
|
14,589 |
|
— |
|
— |
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Gross profit |
|
35,688 |
|
15,446 |
|
4,450 |
|
— |
|
— |
|
|||||
|
Selling, general and administrative expenses |
|
24,144 |
|
12,662 |
|
3,492 |
|
210 |
|
— |
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Income from operations |
|
11,544 |
|
2,784 |
|
958 |
|
(210 |
) |
— |
|
|||||
|
Interest income (expense), net |
|
(2,078 |
) |
(428 |
) |
13 |
|
(1 |
) |
— |
|
|||||
|
Gain on extinguishment of debt |
|
688 |
|
— |
|
— |
|
— |
|
— |
|
|||||
|
Other financing income (expense) |
|
2,062 |
|
(3,630 |
) |
— |
|
— |
|
— |
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Income (loss) before provision |
|
12,216 |
|
(1,274 |
) |
971 |
|
(211 |
) |
— |
|
|||||
|
Provision for income taxes |
|
4,034 |
|
922 |
|
331 |
|
— |
|
— |
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Net income (loss) |
|
8,182 |
|
(2,196 |
) |
640 |
|
(211 |
) |
— |
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Preferred stock dividend |
|
— |
|
(167 |
) |
(50 |
) |
— |
|
— |
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Net income (loss) available to common shareholders |
|
$ |
8,182 |
|
$ |
(2,363 |
) |
$ |
590 |
|
$ |
(211 |
) |
$ |
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Earnings (loss) per common share |
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Basic |
|
$ |
0.95 |
|
$ |
(0.31 |
) |
$ |
0.08 |
|
$ |
(0.05 |
) |
$ |
— |
|
|
Diluted |
|
0.83 |
|
(0.31 |
) |
0.07 |
|
(0.05 |
) |
— |
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Weighted-average shares outstanding: |
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Basic |
|
8,606 |
|
7,647 |
|
7,328 |
|
4,209 |
|
— |
|
|||||
|
Diluted |
|
9,835 |
|
7,647 |
|
8,402 |
|
4,209 |
|
— |
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Consolidated Balance Sheet Data: |
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Working capital |
|
$ |
12,348 |
|
$ |
7,763 |
|
$ |
2,930 |
|
$ |
364 |
|
$ |
— |
|
|
Total assets |
|
56,255 |
|
38,202 |
|
10,988 |
|
1,081 |
|
— |
|
|||||
|
Shareholders’ equity |
|
16,410 |
|
2,129 |
|
3,347 |
|
759 |
|
— |
|
|||||
36
Recent Sales of Unregistered Securities
During the three months ended December 31, 2004, the Company issued 18,050 shares of common stock for services provided. The services were provided by Continental Airlines for the One Pass ® partner program where the Company provides mileage to customers in exchange for payment by the Company to Continental of cash and Company common stock.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION
Overview
Gexa Corp (d/b/a Gexa Energy), located in Houston, Texas, is a retail electric provider (“REP”). As of December 31, 2004 we currently provide electric power to our residential and commercial customers in the deregulated Texas electricity market. In addition to the states in which we currently operate, we are also licensed to supply retail electricity power by applicable state agencies in Massachusetts and have submitted an application to be a retail provider of electricity in New York and Maine.
In August 2001, the PUCT approved our license to become a REP in Texas. As a REP, we sell electric energy and provide the related billing, customer service, collection and remittance services to residential and under one megawatt commercial customers. We offer our customers the attractive value proposition of lower electricity rates, flexible payment and pricing choices, simple offers with understandable terms and responsive customer service. In general, the Texas regulatory structure permits independent REPs (companies unaffiliated with an incumbent utility in a particular geographic area), such as Gexa, to procure and sell electricity at unregulated prices and pay the local TDSPs a regulated tariff rate for delivering electricity to the customers. We are currently one of the largest independent REPs, not affiliated with a utility, operating in Texas that focuses on customers whose peak demand is under one megawatt (defined by the Texas Public Utility Commission as “price-to-beat” commercial customers), as measured by total megawatt hours sold and by meter count. We have grown to over 104,000 total meters as of December 2004, continuing our pattern of base customer growth of 4-5% per month during 2004.
To date, we have focused our sales efforts on the under one megawatt commercial and the residential multi-family housing (apartment community) segments. We have also begun to deploy several low cost marketing strategies to further penetrate the single-family residential market. Employing several first-to-market, co-marketing partnerships with leading brands (e.g., Continental Airlines OnePass®, American Airlines AAdvantage® frequent flyer programs), we expect to leverage the brand equity of these partners to provide access to new single-family residential customers without incurring large marketing expenditures. As of December 31, 2004, the majority of our customers were located in the Houston and Dallas markets, although a growing number
37
are located in a variety of other metropolitan and rural areas in south and west Texas, such as Corpus Christi and Lubbock.
With respect to energy supply, we utilize an agreement with TXU PM, for the procurement of wholesale energy. We serve as our own “qualified scheduling entity” for open market purchases and sales of electricity. We forecast our energy demand and conduct procurement activities through an experienced team of in-house professionals. The forecast for electricity load requirements is based on our aggregate customer base currently served and anticipated weather conditions, as well as forecasted customer acquisition and attrition. We continuously monitor and update our supply positions based on our retail demand forecasts and market conditions. Our objective is to maintain a balanced supply/demand position to limit commodity risk exposure. We do not currently use derivative instruments and we do not plan to engage in speculative trading of derivative instruments in the future, although we may use derivatives for hedging purposes in the future.
Our business strategy can be summarized as follows:
• establish marketing relationships with multi-family property managers and owners to market our services on-site to residents while also providing power to the commercial meters on-site;
• use our inside direct sales team, as well as a network of independent sales agents, to market our service to commercial customers;
• utilize strong branded partners (e.g., Continental Airlines, American Airlines) to provide access to a potential expanded customer base, particularly single-family residential customers, by providing a strong affinity-based electricity offering with other tangible benefits;
• operate and further develop a cost-effective and efficient billing and customer service infrastructure, utilizing a combination of internal resources and outsourced partners;
• leverage our credit support and energy supply agreement with TXU to provide a cost-effective supply of electricity to meet our customers’ needs; and
• evaluate opportunities to expand our business in the Texas marketplace and other deregulated markets on an opportunistic basis.
We intend to evaluate opportunities to expand our areas of operations in Texas as certain market regions in Texas elect to option-in to deregulation. In addition, there are a
38
number of small REPs within the Texas market, and we intend to monitor the activities of these REPs and to pursue and evaluate opportunities to acquire such REPs to the extent it would provide value to us.
Although our current service regions are all within the Texas market, we will also continue to evaluate expansion opportunities in other deregulated electricity markets that offer growth potential in our core under one megawatt commercial, multi-family and single-family residential segments. Beyond Texas, 17 other states and the District of Columbia are currently open to competition in the U.S. with the majority of these in the Mid-Atlantic and Northeast regions. As of December 31, 2004, we are licensed to supply retail electricity power by applicable state agencies in New York and Massachusetts and have submitted an application to be a retail provider of electricity in Maine.
At December 31, 2004, we had 122 full-time employees and 14 part time employees and independent contractors. Our principal executive offices are located at 20 Greenway Plaza, Suite 600, Houston, Texas 77046, and the telephone number is (713) 470-0400.
Subsequent Events
On March 28, 2005, the Company, and FPL Group, Inc., a Florida corporation (“FPL Group”), announced the execution of an Agreement and Plan of Merger, dated as of March 28, 2005 (the “Merger Agreement”), by and among FRM Holdings, LLC, a Delaware limited liability company (“FRM Holdings”), WPRM Acquisition Subsidiary, Inc., a Texas corporation and a wholly owned subsidiary of Holdings (“Merger Sub”), FPL Group and the Company, pursuant to which, subject to the satisfaction or waiver of the conditions therein, Merger Sub will merge with and into the Company (the “Merger”). As a result of the Merger, the Company will become an indirect wholly owned subsidiary of FPL Group. The Merger is intended to qualify as a tax-free reorganization under Section 368(a) of the Internal Revenue Code of 1986, as amended. Further information regarding the Merger is set forth in Note 19 to the Company’s 2004 financial statements included herein under Item 8. “Financial Statements and Supplementary Data”.
We have also recently undertaken certain changes in our disclosure controls and procedures in connection with a material weakness letter we received from our independent auditors, Hein & Associates, LLP on March 25, 2005. Further information regarding these changes is set forth herein in Item 9A. “Controls and Procedures—Changes to Disclosure Controls and Procedures.”
39
Results of Operations
|
|
|
Fiscal 2004 |
|
Fiscal 2003 |
|
Fiscal 2002 |
|
|||
|
Sales |
|
$ |
273,894 |
|
$ |
115,143 |
|
$ |
19,039 |
|
|
Cost of goods sold |
|
238,206 |
|
99,697 |
|
14,589 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Gross profit |
|
35,688 |
|
15,446 |
|
4,450 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Selling, general & administrative expenses |
|
24,144 |
|
12,662 |
|
3,492 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Income from operations |
|
$ |
11,544 |
|
$ |
2,784 |
|
$ |
958 |
|
Revenues
Operating revenue for the year ended December 31, 2004 was $273.9 million compared with operating revenue of $115.1 million for the year ended December 31, 2003, an increase of 138%. Revenues for 2004 rose as the result of increased consumer confidence in the deregulated markets, increases in prices charged to customers as result of increased electricity cost, and the continued successful execution of our marketing strategy as outlined above. The majority of our revenues come from the flow of electricity to customers. However, we also generate revenues from “pass through of TDSP charges”, a standard base charge to each customer, contract cancellation fees, disconnection fees, and late fees.
In addition, during 2004 our marketing department contracted with multi-family communities to secure their corporately paid meters, and also to gain access to current and future residents through direct marketing at the leasing offices. These sales provided us with a large number of customers at low costs of acquisition. As of December 31, 2004, we have marketing agreements with over 600 apartment communities as compared with approximately 500 at December 31, 2003.
During 2004, we focused on growing our internal sales force and developing stronger business relationships with our large “name brand” accounts. We rely on internal innovation along with strategic alliances and acquisitions to provide innovative products to enhance our competitive position. We have plans to expand our internal sales force during 2005, primarily to focus on our value added service offerings. This expansion will enable us to penetrate new markets and to cost effectively expand our presence throughout Texas.
40
Cost of Goods Sold
Cost of goods sold, which is recognized concurrently with related energy sales, primarily includes the aggregated cost of purchased electric power and fees incurred from TDSP’s. Our cost of goods sold increased to $238.2 million for the year ended December 31, 2004, an increase of $138.5 million, or 139%, from $99.7 million for the year ended December 31, 2003. The significant increase in cost of goods sold is primarily a result of the following:
• increase in cost per retail “kWh” delivered, which occurred primarily as a result of increase natural gas costs which are a significant factor influencing electricity costs; and
• increase in our customer base.
Gross Profits
|
|
|
Year Ended |
|
||||
|
|
|
December 31, 2004 |
|
December 31, 2003 |
|
||
|
|
|
|
|
|
|
||
|
Sales |
|
$ |
273,894 |
|
$ |
115,143 |
|
|
Cost of goods sold |
|
238,206 |
|
99,697 |
|
||
|
|
|
|
|
|
|
||
|
Gross profit |
|
35,688 |
|
15,446 |
|
||
|
|
|
|
|
|
|
||
|
Gross Profit % |
|
13.0 |
% |
13.4 |
% |
||
Gross profit was approximately $35.7 million or 13.0% of sales for the year ended December 31, 2004, compared with approximately $15.4 million or 13.4% of sales for the year ended December 31, 2003.
Our gross profit increased over the prior year by $20.2 million. While larger sales volumes increased our gross profit over the prior year, our gross profit percentage for the year decreased. The major factors that may impact gross profit percentage include:
• Customer mix: Due to competitive market forces, pricing for commercial contracts typically yield lower margins per kwh than pricing for residential contracts. Despite typically lower margins for commercial accounts, we believe the administrative costs (as a percentage of sales) for commercial accounts are significantly lower than for single and multi-family customers, and commercial accounts provide attractive profit opportunities. In general, when commercial accounts increase as a percentage of our portfolio, our overall gross profit per kwh will decrease.
• Cost of electricity supply purchases: The price of natural gas is the primary driver of our electricity supply cost. We attempt to mitigate our exposure to price volatility by matching, as accurately as possible, power purchases to expected demand. For term customers, we generally purchase electricity supply to match the length of the customer’s contract. Single and multi-family customers are on the equivalent of month-to-month contracts, for which we purchase electricity on month-ahead and day-ahead contracts. In an environment of rapidly rising natural gas prices, we are unlikely to raise our month-to-month customers’ prices as quickly as our cost increases. This factor was the main driver for the decrease in our gross profit percentage for the year ended December 31, 2004.
• Competitive pricing: As a REP operating in the deregulated retail electricity market in Texas, part of our strategy is to offer electricity rates at a discount to the affiliated REPs “price-to-beat” rates. While this strategy has led to significant growth in our customer base, it can cause our margins to decrease during periods of rising supply costs if “price-to-beat” rates are not increased. During the third quarter of 2004, the “price-to-beat” rates did not increase with the supply costs for every market we serve, limiting our ability to raise rates in those markets.
• Weather Impact: We purchase supply based on our customers’ forecasted use, historical use throughout the term of their contracts and normalized temperatures. During 2004, we experienced milder summer weather which resulted in instances of us having to sell excess purchased electricity into the balancing market at prices lower then we paid.
General and Administrative Expenses
Selling, general and administrative expenses as of December 31, 2004 were $24.1 million compared with selling, general and administrative expenses of $12.7 million as of December 31, 2003, an increase of 91%.
|
(In thousands) |
|
|
December 31, 2004 |
|
December 31, 2003 |
|
||
|
Billing fees |
|
$ |
1,891 |
|
$ |
1,432 |
|
|
|
Sales commissions |
|
4,573 |
|
1,925 |
|
|||
|
Bad debt |
|
7,052 |
|
3,912 |
|
|||
|
Salaries and other |
|
10,628 |
|
5,393 |
|
|||
|
|
|
|
|
|
|
|||
|
Total |
|
$ |
24,144 |
|
$ |
12,662 |
|
|
Billing fees are primarily costs paid to third party EDI providers to handle transactions between us, ERCOT and the TDSPs in order to produce customer bills. Billing fees increased to $1.9 million for the year ended December 31, 2004, an increase of $459,000, or 32% from $1.4 million for the year ended December 31, 2003. Billing fees have increased at a slower rate than customer growth due to economies of scale and reduction of rates charged by third party EDI providers.
Sales commissions are fees paid to employees and external contractors for new customer acquisition. Sales commissions increased to $4.6 million for the year ended December 31, 2004, an increase of $2.6 million, or 138%, from $1.9 million for the year ended December 31, 2003. Sales commissions are primarily paid in three ways:
• one-time payment upon collection of the first month’s bill from the customer;
41
• residual ongoing payments as a percentage of the customers’ bill or an amount per “kWh” delivered to the customer;
• payments to Continental and American Airlines based on miles earned by the customer
The increase in sales commissions for 2004 is primarily the result of customer growth, an increase in new commercial customers which have a higher acquisition cost, and additional commissions incurred in 2004 related to the Continental and American Airlines partner programs.
Bad debt expense increased to $7.1 million for the year ended December 31, 2004, an increase of $3.1 million, or 81%, from $3.9 million for the year ended December 31, 2003. Bad debt expense as a percentage of total revenue decreased to 2.6% for the year ended December 31, 2004, from 3.4% for the year ended December 31, 2003. Bad debt expense has improved as a result of the implementation of late fees, improved collection procedures, improved credit check processes and the addition of disconnect rights which were granted by the PUCT during 2004.
Salaries and other increased to $10.6 million for the year ended December 31, 2004, an increase of $5.2 million, or 97% from $5.4 million for the year ended December 31, 2003. The primary increases in salaries and other are as follows:
• salaries of $2.2 million;
• bank fees of $0.8 million;
• professional fees of $0.9 million;
• telephone, rent and other office expenses of $0.6 million
Salaries expense has increased significantly during 2004 as a result of normal staff additions to accommodate growth and, as necessary, to improve our system of internal controls as discussed in Item 9A. Controls and Procedures. The positions added during the year ended December 31, 2004 include Chief Financial Officer, Corporate Controller, Manager of Financial Reporting, Manager of Human Resources, Director of Operations, Manager of Transaction Processing, several customer service representatives, and a significant number of information technology resources related to our relocating the GEMS billing system from Atlanta, Georgia to Houston, Texas. Although salaries expense has significantly increased during 2004, we anticipate that the overall rate of increase will be lower than the overall sales growth rate.
Bank fees primarily related to fees paid for customer lockbox processing and credit card processing fees. Credit card processing fees increased specifically due to the fact that during 2004, we began offering customers the alternative of paying their bill with a credit card on a recurring basis. These costs increased in line with our customer growth. Professional fees increased primarily as a result of legal and accounting fees
42
related to the strengthening of our internal controls. Telephone, rent and other office expenses primarily increased as a result of the relocation of our corporate offices in 2004 and an upgrade of the customer service phone system.
Other financing income (net of expense)
On July 16, 2003, warrants to acquire 550,000 shares of common stock were granted to The Catalyst Fund Ltd. and certain other affiliates in consideration of a term loan. These warrants contained a put feature allowing the holders to exercise the warrants at a $1.00 per share exercise price, and then force us to repurchase them at market value upon the occurrence of certain events. In accordance with SFAS No. 150, the warrants were initially recorded as a discount to debt based on the closing price of our common stock on the date of issuance ($1.90) minus the exercise price, multiplied by the number of warrants, or approximately $0.5 million. At each balance sheet date, any change in the closing price of our common stock must be used to calculate and record financing expense or income amount to reflect the difference on that date between the market price of our stock and the exercise price of the warrants.
On July 8, 2004, 458,333 of these warrants were repurchased and the remaining 91,667 warrants were amended to delete the put option. At July 8, 2004, our stock closed at $4.75 per share. The decrease in the market price from the valuation at December 31, 2003 based on the closing price of $8.50 per share, on December 31, 2003, required us to record a decrease in the value of the puttable warrant obligation of $2.1 million for the year ended December 31, 2004 as other financing income in accordance with SFAS No. 150. An additional $0.7 million in gain on extinguishment of debt was recorded during 2004. We also recorded $0.6 million of write-off of deferred financing cost and $0.3 million of transaction fees to interest expense during fiscal 2004, as a result of the extinguishment of the debt. As a result of the repurchase and amendment of warrants the ongoing income (expense) effect arising from the put option, as described above, will no longer be applicable.
2003
Year Ended December 31, 2003 Compared to Year Ended December 31, 2002
Revenues
Operating revenue increased $96.1 million, or 505%, to $115.1 in 2003, as compared to 2002. Revenue for 2003 rose as the result of increased consumer confidence in the deregulated markets and the continued successful execution of our marketing strategy outlined above. Other revenues in fiscal year 2003 included approximately $670,000 related to fees from early cancellation of contracts and late fees in accordance with our agreements with commercial customers. A portion of these fees was offset by refunds due to customers on sales taxes based on an opinion letter issued by the Texas State Comptroller’s office declaring that certain meters billed to commercial entities for
43
multi-family dwellings should be taxed as residential meters instead of commercial meters.
In addition, in 2003 our marketing department contracted with multi-family communities to secure their corporately paid meters, and also to gain access to current and future residents through direct marketing at the leasing offices. These sales provided us with a large number of customers at low costs of acquisition. As of December 31, 2003, we have marketing agreements with over 500 apartment communities as compared with approximately 350 at December 31, 2002.
In 2003, our in house sales department focused their efforts on expanding our base of small commercial clients providing us a wide range of customers from small businesses to medium-sized office towers. Additionally, an inbound sales department was established to sign up customers who contacted us to request their service be switched. During 2003, we also effectively utilized a large network of independent sales agents who provided us with an opportunity to reach customers without incurring large fixed costs. These independent sales agents have brought us a very broad and diverse group of customers in all our existing markets ranging from multi-family residents to commercial contracts.
Cost of Goods Sold
Costs of goods sold increased $85.1 million, or 583%, to $99.7 million in fiscal year 2003, as compared to fiscal year 2002. Costs of goods sold are composed largely of electricity supply purchases and the energy delivery charges we pay to the TDSPs. Two factors in 2003 have driven the increase of costs of goods sold at a rate greater than operating revenues for the year. First, as we acquired more commercial accounts as a percentage of our overall portfolio, our margins on a weighted average basis compressed. This trend is more pronounced as the customer accounts approach one megawatt in size. These commercial accounts, while still attractive from a profit perspective, do have lower per kWh margins than residential accounts. Second, during the three months ended March 31, 2003, there was an unexpected volatile price swing in the natural gas market which is the primary determinant of electricity prices. This unexpected price increase occurred over a three day period at the end of February 2003. As a result, open market electricity prices increased substantially along with average committed electricity volumes related to our daily customer usage. The result of this unexpected price volatility was a reported net loss for the three months ended March 31, 2003, and a negative impact of approximately $700,000 on the costs of goods sold for 2003.
General and Administrative Expenses
General and administrative expenses increased $9.2 million, or 263%, to $12.7 million in fiscal year 2003, as compared to fiscal year 2002. Since we grew significantly in 2002 and 2003, there were economies of scale achieved as we grew and also further improved our business processes and information systems. The most significant components of general and administrative costs in 2003 were bad debt expense, salaries
44
expense, sales commissions and billing fees. In 2003, bad debt expense was largely attributable to residential services, and was addressed with the assessment of late fee charges in accordance with the terms of customer contracts, collections procedures, and improved credit check processes in the latter part of 2003 leading into 2004. Additionally, in 2004 the PUCT began allowing competitive retailers, including Gexa, to disconnect the services of customers who fail to pay their bills in a timely manner. Together, these factors are expected to greatly improve delinquent receivables collection for all competitive REPs, for whom bad debt exposure has been an important concern.
Salaries for 2003 included severance expenses related to the resignation of the former President, Marcie C. Zlotnik, from her operational and board positions within the Company. In the fourth quarter of 2003, three months severance pay totaling $50,250 was accrued as a severance expense, as was a $718,075 non cash severance expense reflecting a fair valuation of options (using the Black-Scholes model) that were amended and reinstated on the conclusion of Ms. Zlotnik’s employment. Salary expense increased in 2004 not only as a result of normal staff additions to accommodate growth, but also the hiring of new employees in executive and middle management roles, specifically in the accounting function as necessary to improve our accounting systems and controls as discussed below in “Item 9A.- Controls and Procedures.”
Other financing expense
On July 16, 2003, 550,000 warrants were granted to the Catalyst Fund Ltd. in consideration of a term loan. These warrants contained a put feature allowing the holder to exercise the warrants at a $1.00 per share exercise price, and then force us to repurchase them at market value upon the occurrence of certain events. In accordance with SFAS No. 150, the warrants were initially recorded as a discount to debt based on the close price of the Company’s common stock on the date of issuance ($1.90) minus the exercise price, multiplied by the number of warrants, or $495,000. At each balance sheet date, any change in the close price of the common stock must be used to calculate and record an interest expense or income amount to reflect the difference on that date between the market price of our stock and the exercise price of the warrants.
At December 31, 2003, our stock closed at $8.50 per share. This increase in the market price over the initial valuation of $495,000 required us to record an increase in the value of the puttable warrant obligation of $3,630,000 for the year ended December 31, 2003 as other financing expense in accordance with SFAS No. 150.
Liquidity and Capital Resources
In this section, we discuss the principal sources of capital required for us to operate our business. We also identify known trends, demands, commitments, events or uncertainties which may affect our current and future liquidity or capital resources. Our principal sources of liquidity and capital resources are cash from operations, private equity placements, revolving credit lines, and payment terms from suppliers and term loan debt.
45
Working capital (current assets less current liabilities) increased to $12.3 million at December 31, 2004 from $7.8 million at December 31, 2003. The primary components of the increase are:
• increase in current assets of $14.9 million. This increase is primarily a result of an increase in customer accounts receivable, net of the allowance for bad debt, of $13.3 million. This increase is due primarily to customer growth; there has been an increase to 104,000 meters as of December 31, 2004 compared with 62,000 meters as of December 31, 2003.
• increase in current liabilities of $10.3 million. The primary increases are as follows:
• accrued TDSP charges increased by $3.6 million due to customer growth.
• customer deposits increased by $2.7 million due to customer growth.
• taxes Payable, including federal income tax, state franchise tax and sales tax, increased by $3.9 million due to increased profitability.
Our use of capital is primarily driven by working capital needed to operate as a REP. We experience a time delay between purchasing electricity to flow to customers and receiving payments from our customers. This working capital cycle is impacted by seasonality and customer count growth rates. In 2004, our average days sales outstanding was approximately 46 days when considering both the billed and unbilled receivables concurrently.
Seasonality impacts our working capital needs, as the hotter summer months (driven by air conditioning) increase our electricity needs during the second and third quarters, and commensurately reduces those needs in the first and fourth quarters. With respect to customer growth rates, our constant addition of customers drives an increasing need for working capital funding for electricity purchases. Over time, should our growth rate level off, we would anticipate funding working capital from cash reserves on hand. However, given our growth rates, we have continued needs for additional sources of working capital financing to purchase electricity and expand our operations. In addition to working capital, we spend capital for investments in operational infrastructure to serve our customers; however this amount is relatively minor compared to the working capital required for electricity purchases.
Our largest cost in conducting business is the purchase of electricity. Our agreement with TXU PM provides both a source of electricity supply and vendor financing. Pursuant to our agreement with TXU PM, payments to TXU PM for monthly electricity purchases are made on the last business day of the month following delivery.
46
Since our term commercial customer contracts generally have durations of one and two year terms, we endeavor to match term supply purchases to term customers obligations. We purchase electricity from TXU PM and from third parties based on our forecast of customer demand and monthly purchase limits imposed by TXU PM. Additionally, TXU PM reserves the right to review the credit-worthiness of all customers with peak demand of at least one megawatt. We pay a monthly credit fee to TXU PM based on our monthly electricity purchases from TXU PM, as well as small, fixed monthly administrative fees. TXU PM also provides credit guarantees to us to enable us to purchase electricity from third parties, in return for a monthly fee. The agreement has an initial term of five years, expiring in April 2008, and renews thereafter on a year-to-year basis unless either party gives notice of termination.
Purchasing this electricity exposes the wholesale electricity provider to credit risk that may exist due to any payment risk. Accordingly, TXU PM has three sources of security from us to support this agreement. First, TXU PM has a first lien on all of our assets. Second, our customer receipts are managed through a lockbox arrangement controlled by TXU PM. Under the lockbox arrangement, certain cost of goods sold items and TXU PM’s monthly wholesale electricity invoice are paid during each month with us receiving any remaining funds to be used for operating expenses. TXU PM must approve all disbursements from our lockbox. Third, we are required to post a cash collateralized letter of credit in an amount determined by TXU PM pursuant to the agreement between us and TXU PM.
The TXU PM agreement also has a monthly limit for megawatt hours, which has been flexible to enable us to continue to grow and handle the higher seasonal summer volumes. The current monthly limit for megawatt hours is 400,000 per month. Due to our continued growth, we anticipate that we will reach that cap as we approach the summer months of 2005, and will need to increase it to continue our growth. There is no guarantee that TXU PM will increase this limit but we were in this same position as we approached the summer months in 2004 and TXU granted us the increase after discussion between TXU personnel and our management. As of December 31, 2004 we had $3.3 million posted as a fully cash-collateralized letter of credit to TXU PM. Under the current TXU PM agreement, we anticipate needing to post a cash collateralized letter of credit of approximately $8 million for power purchases this summer. We may require additional financing to collateralize and post this letter of credit. These funds add to the working capital requirements of our business and pose liquidity limitations to our growth. Without having an investment grade credit rating, we anticipate that we will continue to either increase our limits with TXU PM or use availability under our credit agreement with Highbridge/Zwirn Opportunities Fund, L.P.
It is our policy to match, as accurately as possible, power purchases to expected customer demand. For power purchases, we use a combination of long term contracts, short term contracts, month-ahead purchases, and day-ahead purchases to match up with forecasted demand of our commercial customers on long term sales contracts, commercial customers on month-to-month contracts, and residential customers (which are all on month-to month contracts). Our sales force determines their pricing quotes to potential customers on our minimum margin targets, ensuring better integrity of our cash
47
flow from continued operations. As of December 31, 2004, we have committed to future power purchase contracts with TXU PM totaling $86.7 million in 2005 and $17.8 million in 2006.
All our future obligations as of December 31, 2004 for the next five years are summarized as follows:
|
(In thousands) |
|
|
Payments due by period |
|
|||||||||||||
|
Contractual Obligations |
|
|
Total |
|
Less than 1 year |
|
1-3 years |
|
3-5 years |
|
More than 5 years |
|
|||||
|
Forward power contracts |
|
$ |
104,486 |
|
$ |
86,698 |
|
$ |
17,788 |
|
$ |
— |
|
$ |
— |
|
|
|
Long-term debt |
|
— |
|
— |
|
— |
|
— |
|
— |
|
||||||
|
Rent |
|
2,330 |
|
383 |
|
766 |
|
766 |
|
415 |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
|
Total |
|
$ |
106,816 |
|
$ |
87,081 |
|
$ |
18,554 |
|
$ |
766 |
|
$ |
415 |
|
|
Demand for electrical power 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 attempt to procure additional electricity to service our customers or to sell surplus electricity in the open market.
We believe our growth will continue in the Texas market for 2005 but not as rapidly as during 2004. We also plan to continue to evaluate opportunities to enter additional markets. We have begun serving commercial customers in Massachusetts and plan to offer service in New York effective May, 2005, subject to regulatory approval. We have also submitted an application to become a REP in Maine as of the date of this report. As we continue to assess new deregulated markets in other states, our growth within the Texas market takes precedence.
The capital demands of our rapid growth and/or severe seasonality will likely impact our cash flow and require us to use availability under our credit arrangements periodically during 2005. We may also continue to raise additional funds from the sale of equity or debt securities or other borrowings.
As of December 31, 2004, we had deposited approximately $5.8 million with JP Morgan Chase Bank to obtain letters of credit allowing us to purchase power on forward contracts from TXU PM, buy and sell power in the daily balancing markets and pay TDSP invoices for metering charges passed through to customers on thirty-five day terms. We believe that we have sufficient liquidity (described below) to support the letters of credit that may be required.
We have several sources of liquidity to provide the increased level of working capital to support our growth in customer load and purchases of power and other services to support that customer growth:
• Cash from Operations: During the twelve months ended December 31, 2004, we generated approximately $2.8 million in cash from operations as
48
compared with $8.3 million during the twelve months ended December 31, 2003. The primary use of cash during the twelve months ended December 31, 2004 was accounts receivable of $13.3. Additionally, the December 2003 TXU invoice for electricity purchases in the amount of $7.8 million was paid in January 2004. However, the December 2004 TXU invoice for electricity purchases was paid in December 2004. Therefore, 13 months of electricity was paid for with 2004 cash flows.
• Highbridge/Zwirn Special Opportunities Fund, L.P. Credit Facility: On July 8, 2004, we entered into the facility with Highbridge/Zwirn Special Opportunities Fund, L.P. The Facility, which matures on July 8, 2007, may be used to provide working capital for our normal routine operations and for providing a cash reserve to collateralize letters of credit that we are required to post. The Facility is secured by a lien on substantially all of our assets, subject to the liens already held on such assets by TXU and/or JP Morgan Chase. For the twelve months ended December 31, 2004, we were in compliance with all financial covenants under the credit agreement. See Footnote 8 to our Financial Statements for the year ended December 31, 2004 herein for a detailed description of the covenants and restrictions under the facility. As of December 31, 2004, we had no amounts outstanding under the facility. We were able to fulfill our letter of credit requirements with TXU by using our cash from operations.
• Equity: During the twelve months ended December 31, 2004, we raised approximately $0.7 million via private placement of 168,754 shares of our common stock of $4.00 per share and approximately $0.2 million through the exercise of warrants to acquire approximately 200,000 shares of common stock by one of our directors. 100,000 shares were exercised at $1.25 per share and the remaining 100,000 were exercised at $1.00 per share. We also completed a private placement equity offering on November 23, 2004 with Oppenheimer & Co. Inc. This private placement raised approximately $4.2 million. These funds were used to support our continued operational expansions.
We believe that cash flow plus the advances from the Facility will provide the required liquidity to address our current growth rate in the Texas market and allow us the flexibility to move into additional markets if we decide to expand our business additionally.
49
Critical Accounting Policies
Following are critical accounting policies adopted by the Company for use in the preparation of key material financial data.
Normal Purchases and Sales Accounting
In fiscal 2004, we used a combination of long term contracts, short term contracts, month-ahead purchases, and day-ahead purchases to match up with forecasted demand of our commercial customers on long term sales contracts, commercial customer on month-to-month contracts, and residential customers (which are all on month-to-month contracts). We apply the normal purchase, normal sale accounting treatment to our forward purchase supply contracts and our customer sales contracts. Accordingly, we record revenue generated from our sales contracts as energy is delivered.
Revenue and Cost Recognition
We record electricity sales under the accrual method and these revenues are recognized upon delivery of electricity to the customer’s meter. Electric services are accrued based upon estimated deliveries to customers as tracked and recorded by ERCOT multiplied by our average billing rate per kilowatt hour (“kWh”) in effect at the time.
In November 2003, we changed our revenue estimation technique to one referred to as the “flow” technique. In the latter half of 2003, we determined that the market was operating at a point of efficiency such that it would be appropriate for us to begin accruing revenue based on ERCOT settlements of power deliveries, and given the limitations of the billings technique, we chose to change to the flow technique. In addition, by the end of the fiscal year 2003, we had sufficient initial settlement and resettlement data from ERCOT to arrive at a reasonable estimate for 2003 revenues assuming that the flow method had been in place since January 1, 2003.
The flow technique of revenue calculation relies upon ERCOT settlement statements to determine the estimated revenue for a given month. Supply delivered to our customers for the month, measured on a daily basis, provides the basis for revenues. ERCOT provides net electricity delivered data in three time frames. Initial daily settlements become available approximately 17 days after the day being settled. Approximately 45 days after the day being settled, a ‘resettlement’ is provided to adjust the initial settlement to the actual supply delivered based on subsequent comparison of prior forecasts to actual meter reads processed. A final resettlement is provided approximately 180 days after power is delivered, marking the last routine settlement adjustment to the power deliveries for that day.
Because flow data for resettlements and final resettlements are not available in sufficient time to be booked to the appropriate period, the effect of such resettlements are booked in the month in which the cost of goods sold (“COGS”) effect of those resettlements is realized. This allows for a proper matching of revenues with COGS.
50
Sales represent the total proceeds from energy sales, including pass through charges from the TDSPs billed to the customer at cost. COGS includes electric power purchased, and pass through charges from the TDSPs in the areas serviced by us. TDSP charges are costs for metering services and maintenance of the electric grid. TDSP charges are established by regulation by the PUCT.
The energy portion of our cost of goods sold is comprised of two components: bilateral wholesale costs and balancing/ancillary costs. These two cost components are incurred and recognized in different manners.
Bilateral wholesale costs are incurred through contractual arrangements with wholesale power suppliers for firm delivery of power at a fixed volume and fixed price. We are invoiced for these wholesale volumes at the end of each calendar month for the volumes purchased for delivery during the month, with payment due 30 days after the end of the month.
Balancing/ancillary costs are based on the customer load and are determined by ERCOT through a multiple step settlement process. Balancing costs/revenues are related to the differential between supply provided by us through its bilateral wholesale supply and the supply required to serve our customer load. We endeavor to minimize the amount of balancing/ancillary costs through our load forecasting and forward purchasing programs.
Unbilled Revenue and Accounts Receivable
At the end of each calendar month, revenue is accrued to unbilled receivables based on the estimated amount of power delivered to customers using the flow technique. Unbilled revenue also includes accruals for estimated TDSP charges and monthly service charges applicable to the estimated electricity usage for the period.
All charges that were physically billed to customers in the calendar month are recorded from the unbilled account to the customer receivables account. Accounts receivables are customer obligations billed at the conclusion of a month’s electricity usage and due within 16 to 30 days of the date of the invoice. Balances past due are subject to a late fee that is assessed on that billing.
The large number of customers and significant volume of transactions create a challenge to manage receivables as well as to estimate the account balances that ultimately will not be paid by the customers (“bad debt write-offs”). We use a variety of tools to estimate and provide an accurate and adequate allowance for doubtful accounts reserve; the allowance for doubtful accounts is expensed each month as a percentage of revenue based on the historical bad debt write-off trends that will result from that month’s gross revenues. As of December 31, 2004, 2003 and 2002, the Company’s bad debt expense was approximately $7.1 million, or 2.6% of sales, $3.9 million, or 3.4% of sales and $679,000, or 3.6% of sales respectively.
51
We follow a consistent process to determine which accounts should be written off and compare the total actual write-offs to the estimated percentage of total revenue accrued and expensed each month. Past due accounts are regularly reviewed based on aging for possible removal from service, in-house or external collections efforts, or write-off. For residential customers and commercial customers with balances less than $700.00, with some minor exceptions, the total balance for all accounts with any portion of their balance over 60 days past due is considered to be uncollectible and is written off, net of security deposits held for these accounts. Delinquent commercial accounts with balances greater than $700.00 are reviewed individually by in-house collections, and payment arrangements, removal from service and possible write-off of all or a portion of the receivable is determined on a case-by-case basis.
We have initiated a variety of actions targeted to reduce the amount of bad debt that we incur. The principal actions are as follows:
• improved policies requiring credit reviews, deposits, and late fees, and
• implementing more aggressive collection efforts including customer disconnections
Accounts Receivable contains billed receivables, unbilled receivables and the allowance for doubtful accounts as follows:
|
(In thousands) |
|
|
December 31, 2004 |
|
December 31, 2003 |
|
||
|
Billed receivables |
|
$ |
20,759 |
|
$ |
13,126 |
|
|
|
Unbilled receivables |
|
17,160 |
|
10,313 |
|
|||
|
Allowance for doubtful accounts |
|
(2,433 |
) |
(1,300 |
) |
|||
|
|
|
|
|
|
|
|||
|
Accounts receivable, net |
|
$ |
35,486 |
|
$ |
22,139 |
|
|
52
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
In fiscal 2004, we used a combination of long term contracts, short term contracts, month-ahead purchases, and day-ahead purchases to match up with forecasted demand of our commercial customers on long term sales contracts, commercial customer on month-to-month contracts, and residential customers (which are all on month-to-month contracts). We apply the normal purchase, normal sale accounting treatment to our forward purchase supply contracts. Accordingly, we record revenue generated from our sales contracts as energy is delivered to our retail customers, and direct energy costs are recorded when the energy under our long-term forward physical delivery contracts is delivered. During fiscal 2004, we did not use financial hedging, or derivative instruments to hedge our commodity risk and we do not plan to engage in uncovered or speculative trading of derivative instrustments in the future, although we may use derivatives for hedging purposes in the future. Additionally, we do not purchase power until we have locked in our respective customers for whom power will be supplied and purchased.
53
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
54
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of Gexa Corp., Houston, Texas:
We have audited the accompanying balance sheets of Gexa Corp. as of December 31, 2004 and 2003, and the related statements of operations, shareholders’ equity and cash flows for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company has determined that it is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Gexa Corp. at December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004 in conformity with U.S. generally accepted accounting principles.
|
/s/ Hein & Associates LLP |
|
|
|
March 25, 2005 |
|
Houston, Texas |
55
Gexa Corp.
(In thousands, except share data)
|
|
|
December 31, 2004 |
|
December 31, 2003 |
|
||
|
Assets |
|
|
|
|
|
||
|
Current Assets: |
|
|
|
|
|
||
|
|
|
|
|
|
|
||
|
Cash and cash equivalents |
|
$ |
8,862 |
|
$ |
10,829 |
|
|
Cash - restricted |
|
6,685 |
|
3,613 |
|
||
|
Accounts receivable, net of allowance for doubtful accounts |
|
35,486 |
|
22,139 |
|
||
|
Deferred tax asset |
|
841 |
|
458 |
|
||
|
Other current assets |
|
319 |
|
270 |
|
||
|
|
|
|
|
|
|
||
|
Total Current Assets |
|
52,193 |
|
37,309 |
|
||
|
|
|
|
|
|
|
||
|
Property and equipment, net |
|
1,195 |
|
374 |
|
||
|
Deferred tax asset |
|
45 |
|
292 |
|
||
|
Other assets |
|
2,822 |
|
227 |
|
||
|
|
|
|
|
|
|
||
|
Total Assets |
|
$ |
56,255 |
|
$ |
38,202 |
|
|
|
|
|
|
|
|
||
|
Liabilities and Shareholders’ Equity |
|
|
|
|
|
||
|
Current Liabilities: |
|
|
|
|
|
||
|
|
|
|
|
|
|
||
|
Current portion of long-term debt |
|
$ |
— |
|
$ |
608 |
|
|
Accrued electricity costs |
|
15,463 |
|
16,555 |
|
||
|
Accrued transimission and distribution costs |
|
8,879 |
|
5,273 |
|
||
|
Accounts payable and other accrued expenses |
|
2,524 |
|
811 |
|
||
|
Sales tax payable |
|
2,877 |
|
1,446 |
|
||
|
Income tax payable |
|
3,983 |
|
1,477 |
|
||
|
Customer deposits |
|
6,119 |
|
3,376 |
|
||
|
|
|
|
|
|
|
||
|
Total Current Liabilities |
|
39,845 |
|
29,546 |
|
||
|
|
|
|
|
|
|
||
|
Long-term debt |
|
— |
|
2,382 |
|
||
|
Puttable warrant obligation (See Note 10) |
|
— |
|
4,125 |
|
||
|
Accrued interest payable - officer |
|
— |
|
20 |
|
||
|
|
|
|
|
|
|
||
|
Total Liabilities |
|
39,845 |
|
36,073 |
|
||
|
Commitments and contingencies (See Notes 9, 10 and 17) |
|
|
|
|
|
||
|
Shareholders’ Equity: |
|
|
|
|
|
||
|
|
|
|
|
|
|
||
|
Common stock, $0.01 par value; 75,000,000 shares authorized; 9,757,222 shares issued and 9,743,375 shares outstanding at December 31, 2004; 8,261,128 shares issued and 8,247,281 shares outstanding at December 31, 2003 |
|
98 |
|
83 |
|
||
|
Additional paid-in capital |
|
13,727 |
|
7,348 |
|
||
|
Unearned stock-based compensation |
|
(295 |
) |
— |
|
||
|
Treasury stock, at cost; 13,847 shares |
|
(15 |
) |
(15 |
) |
||
|
Retained earnings (accumulated deficit) |
|
2,895 |
|
(5,287 |
) |
||
|
Total Shareholders’ Equity |
|
16,410 |
|
2,129 |
|
||
|
|
|
|
|
|
|
||
|
Total Liabilities and Shareholders’ Equity |
|
$ |
56,255 |
|
$ |
38,202 |
|
See accompanying notes to financial statements
56
GEXA CORP.
(In thousands, except per share data)
|
|
|
For the years ended, |
|
|||||||
|
|
|
December 31, 2004 |
|
December 31, 2003 |
|
December 31, 2002 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
|
$ |
273,894 |
|
$ |
115,143 |
|
$ |
19,039 |
|
|
Cost of goods sold |
|
238,206 |
|
99,697 |
|
14,589 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Gross profit |
|
35,688 |
|
15,446 |
|
4,450 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Selling, general and administrative expenses |
|
24,144 |
|
12,662 |
|
3,492 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Income from operations |
|
11,544 |
|
2,784 |
|
958 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Interest income |
|
45 |
|
21 |
|
23 |
|
|||
|
Interest expense |
|
(2,123 |
) |
(449 |
) |
(10 |
) |
|||
|
Gain on extinguishment of debt |
|
688 |
|
— |
|
— |
|
|||
|
Other financing income (expense) |
|
2,062 |
|
(3,630 |
) |
— |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Income (loss) before income taxes |
|
12,216 |
|
(1,274 |
) |
971 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Income tax expense |
|
4,034 |
|
922 |
|
331 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Net income (loss) |
|
8,182 |
|
(2,196 |
) |
640 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Preferred stock dividend |
|
— |
|
(167 |
) |
(50 |
) |
|||
|
|
|
|
|
|
|
|
|
|||
|
Net income (loss) available to common shareholders |
|
$ |
8,182 |
|
$ |
(2,363 |
) |
$ |
590 |
|
|
|
|
|
|
|
|
|
|
|||
|
Weighted average shares outstanding: |
|
|
|
|
|
|
|
|||
|
Basic |
|
8,606 |
|
7,647 |
|
7,328 |
|
|||
|
Diluted |
|
9,835 |
|
7,647 |
|
7,989 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Earnings per share: |
|
|
|
|
|
|
|
|||
|
Basic |
|
$ |
0.95 |
|
$ |
(0.31 |
) |
$ |
0.08 |
|
|
Diluted |
|
$ |
0.83 |
|
$ |
(0.31 |
) |
$ |
0.07 |
|
See accompanying notes to financial statements
57
GEXA CORP.
STATEMENTS OF SHAREHOLDERS’ EQUITY
YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
Additional |
|
|
|
Stock |
|
Unearned |
|
Retained |
|
|
|
||||||||
|
|
|
Preferred Stock |
|
Common Stock |
|
Paid-in |
|
Treasury |
|
Subscription |
|
Stock-based |
|
Earnings |
|
|
|
||||||||||||
|
|
|
Shares |
|
Amount |
|
Shares |
|
Amount |
|
Capital |
|
Stock |
|
Receivable |
|
Compensation |
|
(Defecit) |
|
Total |
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
|
Balance, Dec 31, 2001 |
|
— |
|
$ |
— |
|
6,485 |
|
$ |
65 |
|
$ |
4,058 |
|
$ |
— |
|
$ |
— |
|
$ |
— |
|
$ |
(3,514 |
) |
$ |
609 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
|
Issued common stock for services |
|
— |
|
— |
|
401 |
|
4 |
|
297 |
|
— |
|
— |
|
— |
|
— |
|
301 |
|
||||||||
|
Sale of preferred stock |
|
508 |
|
25 |
|
— |
|
— |
|
900 |
|
— |
|
— |
|
— |
|
— |
|
925 |
|
||||||||
|
Sale of common stock |
|
— |
|
— |
|
685 |
|
7 |
|
789 |
|
— |
|
— |
|
— |
|
— |
|
796 |
|
||||||||
|
Company purchased treasury stock |
|
— |
|
— |
|
— |
|
— |
|
— |
|
(60 |
) |
— |
|
— |
|
— |
|
(60 |
) |
||||||||
|
Sale of treasury stock |
|
— |
|
— |
|
— |
|
— |
|
— |
|
50 |
|
— |
|
— |
|
— |
|
50 |
|
||||||||
|
Warrants issued in financing agreement |
|
— |
|
— |
|
— |
|
— |
|
300 |
|
— |
|
— |
|
— |
|
— |
|
300 |
|
||||||||
|
Warrants cancelled from financing agreement |
|
— |
|
— |
|
— |
|
— |
|
(200 |
) |
— |
|
— |
|
— |
|
— |
|
(200 |
) |
||||||||
|
Common stock dividend to preferred shareholders |
|
— |
|
— |
|
34 |
|
— |
|
50 |
|
— |
|
— |
|
— |
|
(50 |
) |
— |
|
||||||||
|
Stock subscription receivable |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
(14 |
) |
— |
|
— |
|
(14 |
) |
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
|
Net Income |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
640 |
|
640 |
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
|
Balances, December 31, 2002 |
|
508 |
|
|
25 |
|
7,605 |
|
|
76 |
|
|
6,194 |
|
|
(10 |
) |
|
(14 |
) |
|
— |
|
|
(2,924 |
) |
|
3,347 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
|
Issued common stock for services |
|
— |
|
— |
|
33 |
|
— |
|
65 |
|
— |
|
— |
|
— |
|
— |
|
65 |
|
||||||||
|
Sales of common stock |
|
— |
|
— |
|
3 |
|
— |
|
11 |
|
— |
|
— |
|
— |
|
— |
|
11 |
|
||||||||
|
Issued warrants for Loan Agreement |
|
— |
|
— |
|
— |
|
— |
|
123 |
|
— |
|
— |
|
— |
|
— |
|
123 |
|
||||||||
|
Purchased common stock from former employee |
|
— |
|
— |
|
— |
|
— |
|
— |
|
(3 |
) |
— |
|
— |
|
— |
|
(3 |
) |
||||||||
|
Exercise of stock warrants |
|
— |
|
— |
|
29 |
|
— |
|
51 |
|
— |
|
— |
|
— |
|
— |
|
51 |
|
||||||||
|
Stock subscription receivable |
|
— |
|
— |
|
— |
|
— |
|
— |
|
(15 |
) |
14 |
|
— |
|
— |
|
(1 |
) |
||||||||
|
Issued treasury stock for services |
|
— |
|
— |
|
— |
|
— |
|
— |
|
13 |
|
— |
|
— |
|
— |
|
13 |
|
||||||||
|
Issuance of options to former employee |
|
— |
|
— |
|
— |
|
— |
|
718 |
|
— |
|
— |
|
— |
|
— |
|
718 |
|
||||||||
|
Preferred stock conversion to common stock |
|
(508 |
) |
(25 |
) |
588 |
|
7 |
|
19 |
|
— |
|
— |
|
— |
|
— |
|
— |
|
||||||||
|
Common stock dividend to preferred shareholders |
|
— |
|
— |
|
20 |
|
— |
|
167 |
|
— |
|
— |
|
— |
|
(167 |
) |
— |
|
||||||||
|
Common shares extinguished |
|
— |
|
— |
|
(16 |
) |
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
|
Net loss |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
(2,196 |
) |
(2,196 |
) |
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
|
Balances, December 31, 2003 |
|
— |
|
|
— |
|
8,262 |
|
|
83 |
|
|
7,348 |
|
|
(15 |
) |
|
— |
|
|
— |
|
|
(5,287 |
) |
|
2,128 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
|
Issued common stock and warrants for services |
|
— |
|
— |
|
120 |
|
1 |
|
1,451 |
|
— |
|
— |
|
(295 |
) |
— |
|
1,157 |
|
||||||||
|
Stock and warrant offerings, net of issuance costs |
|
— |
|
— |
|
1,176 |
|
12 |
|
4,871 |
|
— |
|
— |
|
— |
|
— |
|
4,883 |
|
||||||||
|
Exercise of warrants |
|
— |
|
— |
|
199 |
|
2 |
|
222 |
|
— |
|
— |
|
— |
|
— |
|
224 |
|
||||||||
|
Fees capitalized in Equity |
|
— |
|
— |
|
— |
|
— |
|
(165 |
) |
— |
|
— |
|
— |
|
— |
|
(165 |
) |
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
|
Net Income |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
8,182 |
|
8,182 |
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
|
Balances, December 31, 2004 |
|
— |
|
$ |
— |
|
9,757 |
|
$ |
98 |
|
$ |
13,727 |
|
$ |
(15 |
) |
$ |
— |
|
$ |
(295 |
) |
$ |
2,895 |
|
$ |
16,410 |
|
See accompanying notes to financial statements
58
Gexa Corp.
(In thousands)
|
|
|
For the years ended, |
|
|||||||
|
|
|
December 31, 2004 |
|
December 31, 2003 |
|
December 31, 2002 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Cash flows from operating activities: |
|
|
|
|
|
|
|
|||
|
Net income (loss) |
|
$ |
8,182 |
|
$ |
(2,196 |
) |
$ |
640 |
|
|
|
|
|
|
|
|
|
|
|||
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |
|
|
|
|
|
|
|
|||
|
Depreciation and amortization |
|
329 |
|
145 |
|
33 |
|
|||
|
Amortization of financing costs |
|
489 |
|
75 |
|
100 |
|
|||
|
Accretion of debt discount |
|
(153 |
) |
61 |
|
— |
|
|||
|
Stock compensation to officers, directors and consultants for services |
|
179 |
|
78 |
|
301 |
|
|||
|
Stock compensation to former officer |
|
— |
|
718 |
|
|
|
|||
|
Gain on extinguishment of debt |
|
(688 |
) |
— |
|
— |
|
|||
|
Change in puttable warrant obligation |
|
(2,062 |
) |
3,630 |
|
— |
|
|||
|
Deferred income tax benefit |
|
(136 |
) |
(554 |
) |
(37 |
) |
|||
|
|
|
|
|
|
|
|
|
|||
|
Changes in operating assets and liabilities: |
|
|
|
|
|
|
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Accounts receivable |
|
(13,347 |
) |
(16,328 |
) |
(6,881 |
) |
|||
|
Other current assets |
|
54 |
|
(196 |
) |
(73 |
) |
|||
|
Other long-term assets |
|
(113 |
) |
(149 |
) |
(53 |
) |
|||
|
Accrued electricity costs |
|
(1,092 |
) |
13,620 |
|
2,935 |
|
|||
|
Accrued TDSP costs |
|
3,606 |
|
3,624 |
|
1,649 |
|
|||
|
Accounts payable and other accrued expenses |
|
938 |
|
692 |
|
(99 |
) |
|||
|
Sales tax payable |
|
1,431 |
|
1,172 |
|
1,344 |
|
|||
|
Income tax payable |
|
2,506 |
|
1,108 |
|
369 |
|
|||
|
Customer deposits |
|
2,743 |
|
2,790 |
|
586 |
|
|||
|
Accrued interest payable |
|
(20 |
) |
8 |
|
8 |
|
|||
|
Net cash provided by operating activities |
|
2,846 |
|
8,297 |
|
822 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|||
|
Restricted cash |
|
(3,072 |
) |
(2,651 |
) |
(962 |
) |
|||
|
Purchases of equipment |
|
(1,656 |
) |
(232 |
) |
(233 |
) |
|||
|
Net cash used in investing activities |
|
(4,728 |
) |
(2,883 |
) |
(1,195 |
) |
|||
|
|
|
|
|
|
|
|
|
|||
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|||
|
Borrowings on credit facility |
|
— |
|
— |
|
500 |
|
|||
|
Repayments on credit facility and puttable warrant obligation |
|
(5,029 |
) |
(500 |
) |
— |
|
|||
|
Borrowings on revolving credit line |
|
6,057 |
|
— |
|
28 |
|
|||
|
Repayments on revolving credit line |
|
(6,057 |
) |
(28 |
) |
— |
|
|||
|
Borrowings on term loan |
|
— |
|
3,650 |
|
— |
|
|||
|
Repayments on term loan |
|
— |
|
(202 |
) |
— |
|
|||
|
Proceeds on sales of preferred stock |
|
— |
|
— |
|
925 |
|
|||
|
Proceeds from the sales of common stock |
|
5,109 |
|
61 |
|
796 |
|
|||
|
Purchase of treasury stock |
|
— |
|
(3 |
) |
(60 |
) |
|||
|
Retirement of treasury stock |
|
— |
|
— |
|
50 |
|
|||
|
Stock subscriptions receivable |
|
— |
|
— |
|
(14 |
) |
|||
|
Payments for stock offering expenses |
|
(165 |
) |
— |
|
— |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Net cash provided by (used in) financing activities |
|
(85 |
) |
2,978 |
|
2,225 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Net change in cash and cash equivalents |
|
(1,967 |
) |
8,392 |
|
1,852 |
|
|||
|
Cash and cash equivalents at beginning of period |
|
10,829 |
|
2,437 |
|
585 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Cash and cash equivalents at end of period |
|
$ |
8,862 |
|
$ |
10,829 |
|
$ |
2,437 |
|
|
|
|
|
|
|
|
|
|
|||
|
Cash paid for interest |
|
$ |
280 |
|
$ |
231 |
|
$ |
1 |
|
|
|
|
|
|
|
|
|
|
|||
|
Cash paid for income taxes |
|
$ |
1,649 |
|
$ |
435 |
|
$ |
— |
|
See accompanying notes to financial statements
59
Supplementary disclosure of non-cash transactions
During the twelve months ended December 31, 2004, certain broker commissions were paid with 7,400 shares of common stock valued at market price on date of issue, averaging $7.17 per share.
During the twelve months ended December 31, 2004, employees of the Company were granted 6,750 shares of common stock, that were valued at an average market price of $5.33 per share, in lieu of compensation.
During the twelve months ended December 31, 2004, the Company issued 21,356 shares of common stock for services provided. The services were provided by Continental Airlines for the One Pass ® partner program where the Company provides mileage to customers in exchange for payment by the Company to Continental of cash and Company common stock. The common stock was issued in separate issues as follows: 3,306 shares issued at a market price of $4.40, 5,232 shares issued at a market price of $4.75, 5,006 shares issued at a market price of $5.00, and 7,812 shares issued at a market price of $4.99.
During the twelve months ended December 31, 2004, the Company issued 275,000 warrants to purchase common stock. These warrants have a five year term and were issued in conjunction with obtaining a revolving credit facility with Highbridge/Zwirn Opportunities Fund, L.P. as follows: 150,000 warrants were issued to HBZ and the remaining 125,000 were issued to a broker who assisted in facilitating the credit facility. The warrants were valued using the Black Scholes valuation method. For information on the Company’s assumptions for Black Scholes, reference Note 8. Long Term Debt, for details on the valuation of these warrants.
During the twelve months ended December 31, 2004, the Company issued 85,000 shares of restricted stock to employees. This stock was issued to officers of the Company. 25,000 shares vest by May 26, 2005, with the remaining 60,000 vesting by October 28, 2005. Based on an issuance price of $4.41 per share on date of issue, the total value of this award is $374,850. The total amount expensed during fiscal 2004 is $79,996 with the remaining $294,854 deferred and recognized over the vesting period of the options.
During the twelve months ended December 31, 2003, the Company issued warrants for the right to purchase up to 631,000 shares of the Company’s common stock at an exercise price of $1.00 per share in connection with a term loan issued on July 16, 2003. Warrants to purchase 550,000 shares of common stock included a put option that requires these warrants to receive liability treatment under SFAS No. 150. These warrants had an initial value of $495,000 which was reflected as a discount to the long-term debt. See Note 10 for a discussion of the valuation of the warrants with put options under SFAS No. 150. The remaining warrants to acquire 81,000 shares of common stock were issued under a portion of the term loan that represented a modification to the Company’s existing loan agreement with another third party bringing that loan under the term loan agreement with the party
60
receiving the warrants to acquire 550,000 shares of common stock. These warrants were fair-valued at $122,733 using the Black-Sholes model and are reflected as a discount to the long-term debt.
On December 31, 2003 19,634 shares of common stock valued at $166,889 were issued to preferred shareholders as a preferred stock dividend. On December 31, 2003 all 508,214 shares of preferred stock in the amount of $924,400 were converted to common stock in accordance with the mandatory conversion provision at December 31, 2003 attached to the preferred shares. The preferred shares were converted to 588,484 shares of common stock.
During the year ended December 31, 2003, sales tax refunds of approximately $1.1 million were made to customers based on an opinion letter issued by the Texas State Comptroller’s office declaring that certain meters billed to commercial entities for multi-family dwellings should be taxed as residential meters instead of commercial meters. Such treatment exempts said meters from state, county and certain special district taxes. These refunds were offset against customer billings, offset against losses related to bad debt losses for customers no longer with the Company where a bad debt loss was incurred, or refunded via check.
During the twelve months ended December 31, 2002, the Company issued stock warrants to a lender as part of the Company’s financing agreement. The warrants for 300,000 shares were valued at $300,000 and were amortized at $8,333 per month to match the three year term of the financing agreement. At December 31, 2002, the financing agreement was terminated and the warrants were cancelled; the unamortized portion of the value at the time of the cancellation, $200,000, was offset against additional paid in capital.
During the twelve months ended December 31, 2002, the Company issued 33,549 shares of common stock, valued at $50,323, as dividend payments to holders of the Company’s preferred stock.
61
Gexa Corp.
Notes to Financial Statements
1. Organization
Gexa Corp. (“the Company”) was incorporated in Texas on February 13, 2001. On August 2, 2001, the Company received its license from the Public Utility Commission of Texas to serve as a retail provider of electricity to residential and commercial customers in deregulated markets within the state of Texas. On January 1, 2002, Gexa began to provide retail electric services in the State of Texas.
2. Basis of Presentation and Significant Accounting Policies
The accompanying financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America.
Reclassifications
The Company has reclassified certain prior fiscal year amounts in the accompanying financial statements in order to be consistent with the current fiscal year presentation. During fiscal 2004, the Company reclassified certain costs associated with sales commissions, marketing programs and transaction processing fees from cost of goods sold to selling, general and administrative expenses in our statements of operations. The reclassified amounts decreased cost of goods sold and increased selling, general and administrative expenses by $6.5 million, $3.4 million and $0.7 million in fiscal 2004, 2003 and 2002, respectively. Such reclassifications had no effect on net income or loss.
Use of estimates
The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and revenues and expenses during the reporting period. Actual results could differ from those estimates. The significant estimates for the Company include:
• estimation of volumes delivered to customers, including the effects of resettlements from ERCOT;
• estimation of rates for determination of revenues;
• bad debt expense; and
• estimation of the fair value of stock options and warrants issued.
62
Normal Purchases and Sales Accounting
In fiscal 2004, the Company used a combination of long term contracts, short term contracts, month-ahead purchases, and day-ahead purchases to match up with forecasted demand of our commercial customers on long term sales contracts, commercial customer on month-to-month contracts, and residential customers (which are all on month-to-month contracts). The Company applied the normal purchase, normal sales accounting treatment to its forward purchase supply contracts and its customer sales contracts. Accordingly, the Company recorded revenue generated from its sales contracts as energy was delivered to its retail customers, and direct energy costs are recorded when the energy under its long-term forward physical delivery contracts was delivered.
Revenue and Cost Recognition
The Company records electricity sales under the accrual method and these revenues are recognized upon delivery of electricity to the customer’s meter. Electric services not billed by month-end are accrued based upon estimated deliveries to customers as tracked and recorded by ERCOT multiplied by the Company’s average billing rate per kilowatt hour (“kWh”) in effect at the time.
In November 2003, the Company changed its revenue estimation technique to one referred to as the “flow” technique. In the latter half of 2003, the Company determined that the market was operating at a point of efficiency such that it would be appropriate for the Company to begin accruing revenue based on ERCOT settlements of power deliveries, and given the limitations of the billings technique, the Company chose to change to the flow technique. In addition, by the end of the fiscal year 2003, the Company had sufficient initial settlement and resettlement data from ERCOT to arrive at a reasonable estimate for 2003 revenues assuming that the flow method had been in place since January 1, 2003.
The flow technique of revenue calculation relies upon ERCOT settlement statements to determine the estimated revenue for a given month. Supply delivered to our customers for the month, measured on a daily basis, provides the basis for revenues. ERCOT provides net electricity delivered data in three time frames. Initial daily settlements become available approximately 17 days after the day being settled. Approximately 45 days after the day being settled, a ‘resettlement’ is provided to adjust the initial settlement to the actual supply delivered based on subsequent comparison of prior forecasts to actual meter reads processed. A final resettlement is provided approximately 180 days after power is delivered, marking the last routine settlement adjustment to the power deliveries for that day.
Because flow data for resettlements and final resettlements are not available in sufficient time to be booked to the appropriate period, the effect of such resettlements are booked in the month in which the cost of goods sold (“COGS”) effect of those resettlements is realized. This allows for a proper matching of revenues with COGS.
63
Sales represent the total proceeds from energy sales, including pass through charges from the Transmission and Distribution Providers (“TDSPs”) billed to the customer at cost. COGS includes electric power purchased, and pass through charges from the TDSPs in the areas serviced by the Company. TDSP charges are costs for metering services and maintenance of the electric grid. TDSP charges are established by regulation by the Public Utility Commission of Texas (“PUCT”).
The energy portion of the Company’s COGS is comprised of two components: bilateral wholesale costs and balancing/ancillary costs. These two cost components are incurred and recognized in different manners.
Bilateral wholesale costs are incurred through contractual arrangements with wholesale power suppliers for firm delivery of power at a fixed volume and fixed price. The Company is invoiced for these wholesale volumes at the end of each calendar month for the volumes purchased for delivery during the month, with payment due 30 days after the end of the month.
Balancing/ancillary costs are based on the customer load and are determined by ERCOT through a multiple step settlement process. Balancing costs/revenues are related to the differential between supply provided by the Company through its bilateral wholesale supply and the supply required to serve the Company’s customer load. The Company endeavors to minimize the amount of balancing/ancillary costs through its load forecasting and forward purchasing programs.
Unbilled Revenue and Accounts Receivable
At the end of each calendar month, revenue is accrued to unbilled receivables based on the estimated amount of power delivered to customers using the flow technique. Unbilled revenue also includes accruals for estimated TDSP charges and monthly service charges applicable to the estimated electricity usage for the period.
All charges that were physically billed to customers in the calendar month are recorded from the unbilled account to the customer receivables account. Accounts receivables are customer obligations billed at the conclusion of a month’s electricity usage and due within 16 to 30 days of the date of the invoice depending on customer payment terms. Balances past due are subject to a late fee that is assessed on that billing.
The large number of customers and significant volume of transactions create a challenge to manage receivables as well as to estimate the account balances that ultimately will not be paid by the customers (“bad debt write-offs”). The Company uses a variety of tools to estimate and provide an accurate and adequate allowance for doubtful accounts reserve; the allowance for doubtful accounts is expensed each month as a percentage of revenue based on the historical bad debt write-off trends that will result from that month’s gross revenues. For the years ended, December 31, 2004, 2003 and 2002, the Company’s bad debt expense was approximately $7.1 million, or 2.6% of sales, $3.9 million, or 3.4% of sales and $679,000, or 3.6% of sales respectively.
64
The Company follows a consistent process to determine which accounts should be written off and compares the total actual write-offs to the estimated percentage of total revenue accrued and expensed each month. Past due accounts are regularly reviewed based on aging for possible removal from service, in-house or external collections efforts, or write-off. For residential customers and commercial customers with a balance under $700.00, with some minor exceptions, the total balance for all accounts with any portion of their balance over 60 days past due is considered to be uncollectible and is written off, net of security deposits held for these accounts. Delinquent commercial accounts with balances greater than $700.00 are reviewed individually by in-house collections, and payment arrangements, removal from service and possible write-off of all or a portion of the receivable is determined on a case-by-case basis.
The Company has initiated a variety of actions targeted to reduce the amount of bad debt incurred by the Company. The principal actions are as follows:
• improved policies requiring credit reviews, deposits, and late fees, and
• implementing more aggressive collection efforts including customer disconnections
Cash and Cash Equivalents
The Company considers all highly liquid short-term investments purchased with a maturity of three months or less at the date of purchase to be cash equivalents.
Restricted Cash
The Company has restricted cash related to customer deposits and certificates of deposit used to secure letters of credit for the purchase of electricity, the payment of TDSP pass through charges, and operations. Customer deposit cash must be held by the Company and may not be directly spent on any operational or other expense. Restricted cash securing letters of credit may not be used for any purpose by the Company unless the underlying obligation being secured is relieved or secured with other collateral. See Note 7, Restricted Cash, Cash Equivalents, and Energy Deposits for more details.
Fair Value of Financial Instruments
The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable, and accounts payable. The carrying amounts of these financial instruments are reflected in the accompanying balance sheets at amounts considered by management to approximate their fair values due to their short-term nature.
Equipment
Equipment is stated at cost. Maintenance, repairs and minor renewals are expensed when incurred. The Company’s fixed assets are classified as furniture,
65
computer hardware, computer software, telephones, and leasehold improvements. The Company considers leasehold improvements to be improvements that can not be removed without substantially damaging or requiring substantial repair to leased asset. The Company depreciates these items over the term of the lease or the service life of the improvement, whichever is shorter. All of these items, except for leasehold improvements, are depreciated on a straight-line basis over a three year period. Depreciation expense for the years ended December 31, 2004, 2003 and 2002 was $265,000, $145,000, and $33,000 respectively.
Income Taxes
The Company accounts for income taxes pursuant to the asset and liability method which requires deferred income tax assets and liabilities to be computed annually for temporary differences between the financial statement and tax bases of assets and liabilities that will result in taxable or deductible amounts in the future based on enacted tax laws and rates applicable to the periods in which the differences are expected to affect taxable income. Valuation allowances will be established when necessary to reduce deferred tax assets to the amount expected to be realized. No allowances have been established through the end of fiscal 2004.
Deferred Financing Costs
The Company defers costs incurred in connection with financings and amortizes the costs over the life of the related debt in accordance with the effective interest method. During fiscal 2004, 2003 and 2002 we incurred financing costs of $2.3 million, $0.8 million and $0.0 million, respectively. The Company expensed $0.5 million, $0.1 million and $0.1 million in fees and other costs related to our financing in 2004, 2003 and 2002 respectively. The Company had $1.9 million in deferred financing costs classified as “Other long-term assets” on December 31, 2004 and $0.1 million on December 31, 2003.
Net Income (loss) per share
The Company presents “basic” net income (loss) per share and “diluted” net income (loss) per share. Basic net income (losses) per share is calculated by dividing net income (loss) available to common shareholders by the weighted average number of shares outstanding during each period. The calculation of diluted net income (loss) available to common shareholders per share is similar to that of basic earnings per share, except that the denominator is increased to include the number of additional common shares that would have been outstanding if all of the potential common share equivalents were exercised. See Note 13, Earnings Per Share for more details.
Comprehensive income
Comprehensive income represents any non-owner changes in equity besides income (loss) and dividends. The Company’s comprehensive income (loss) for the years
66
ended December 31, 2004, 2003 and 2002 was equal to net income (loss) as reported herein.
Stock-based compensation
The Company accounts for stock based compensation to employees using the intrinsic value method. Pro forma information regarding net income (loss) and net income (loss) per share available to common shareholders is required by SFAS No. 148 and has been determined as if the Company had accounted for its stock options under the fair value method as provided therein.
For purposes of pro forma disclosures, the estimated fair value of the options is amortized to expense over the options’ graded vesting period.
In December 2002, the Financial Accounting Standards Board (“FASB”) amended the transition and disclosure requirements of SFAS No. 123 through the issuance of SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure”. SFAS No. 148 amends the existing disclosures to make more frequent and prominent disclosure of stock-based compensation expense beginning with financial statements for fiscal years ending after December 15, 2002. The company has adopted the disclosure provisions of SFAS No. 148.
If the Company had accounted for its stock-based employee and outside director’s compensation under the minimum fair value recognition and measurement principles, the Company’s reported net income amounts would have been adjusted to the pro forma net income amounts presented below:
67
|
(In thousads, except share data) |
|
December 31, |
|
December 31, |
|
December 31, |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Pro Forma impact of fair value method (FAS 148) |
|
|
|
|
|
|
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Reported net income (loss) available to common shareholders |
|
$ |
8,182 |
|
$ |
(2,363 |
) |
$ |
590 |
|
|
Less: Total stock-based compensation expense determined under fair value based method for all awards, net of related tax effects |
|
(640 |
) |
(348 |
) |
(213 |
) |
|||
|
Pro forma net income (loss) available to common shareholders |
|
$ |
7,542 |
|
$ |
(2,711 |
) |
$ |
377 |
|
|
|
|
|
|
|
|
|
|
|||
|
Earnings per common share |
|
|
|
|
|
|
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Basic - as reported |
|
$ |
0.95 |
|
$ |
(0.31 |
) |
$ |
0.08 |
|
|
Diluted - as reported |
|
0.83 |
|
(0.31 |
) |
0.07 |
|
|||
|
Basic - pro forma |
|
0.88 |
|
(0.35 |
) |
0.05 |
|
|||
|
Diluted - pro forma |
|
0.77 |
|
(0.35 |
) |
0.05 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Weighted average Black-Scholes value assumptions |
|
|
|
|
|
|
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Risk free interest rate |
|
3 |
% |
5 |
% |
3 |
% |
|||
|
Expected life |
|
3 yrs |
|
3 yrs |
|
3 yrs |
|
|||
|
Expected volatility |
|
36 - 176 |
% |
193 |
% |
124 |
% |
|||
|
Expected dividend yield |
|
0 |
% |
0 |
% |
0 |
% |
|||
Recent Accounting Standards
In October 2004, the FASB concluded that SFAS No. 123R, “Share-Based Payment”, which would require all companies to measure compensation cost for all share-based payments (including employee stock options) at fair value. SFAS No. 123R is effective for the Company for interim or annual period beginning after June 15, 2005. The Company will adopt SFAS No. 123R on July 1, 2005 and does not believe the adoption will have a material impact on its financial statements.
3. Sales and Cost of Goods Sold
Below are the major components of our sales and cost of goods sold for the last three fiscal years. Electricity includes the power we deliver to customers, while TDSP charges (which are billed to the customer at cost) include metering services and maintenance of the electrical grid. Other revenue is primarily comprised of monthly service charges and late fees. See the table below for details of our revenue and cost of goods sold for the year ended December 31, 2004, 2003, and 2002:
68
|
(In thousands) |
|
|
Major Components of Sales |
|
|||||||
|
|
|
December 31, 2004 |
|
December 31, 2003 |
|
December 31, 2002 |
|
||||
|
|
|
|
|
|
|
|
|
||||
|
Electricity |
|
$ |
203,918 |
|
$ |
86,405 |
|
$ |
13,684 |
|
|
|
TDSP |
|
62,115 |
|
25,973 |
|
5,013 |
|
||||
|
Other |
|
7,861 |
|
2,765 |
|
342 |
|
||||
|
|
|
|
|
|
|
|
|
||||
|
Total sales |
|
$ |
273,894 |
|
$ |
115,143 |
|
$ |
19,039 |
|
|
|
|
|
|
|
|
|
|
|
||||
|
|
|
Major Components of Cost of Goods Sold |
|
||||||||
|
|
|
December 31, 2004 |
|
December 31, 2003 |
|
December 31, 2002 |
|
||||
|
|
|
|
|
|
|
|
|
||||
|
Electricity |
|
$ |
176,091 |
|
$ |
73,724 |
|
$ |
9,576 |
|
|
|
TDSP |
|
62,115 |
|
25,973 |
|
5,013 |
|
||||
|
|
|
|
|
|
|
|
|
||||
|
Total cost of goods sold |
|
$ |
238,206 |
|
$ |
99,697 |
|
$ |
14,589 |
|
|
4. Accounts Receivable, net
Accounts receivable consisted of billed receivables, unbilled receivables and allowance for doubtful accounts as follows:
|
(In thousands) |
|
|
December 31, 2004 |
|
December 31, 2003 |
|
||
|
|
|
|
|
|
|
|||
|
Billed receivables |
|
$ |
20,759 |
|
$ |
13,126 |
|
|
|
Unbilled receivables |
|
17,160 |
|
10,313 |
|
|||
|
Allowance for doubtful accounts |
|
(2,433 |
) |
(1,300 |
) |
|||
|
|
|
|
|
|
|
|||
|
Accounts receivable, net |
|
$ |
35,486 |
|
$ |
22,139 |
|
|
The following table sets forth the activity in the Company’s allowance for doubtful accounts for the years ended:
|
(In thousands) |
|
|
December 31, 2004 |
|
December 31, 2003 |
|
December 31, 2002 |
|
|||
|
|
|
|
|
|
|
|
|
||||
|
Balance, beginning of year |
|
$ |
1,300 |
|
$ |
326 |
|
$ |
— |
|
|
|
Provisions charged to operations |
|
7,052 |
|
3,900 |
|
679 |
|
||||
|
Write-offs (net of recoveries) |
|
(5,918 |
) |
(2,926 |
) |
(353 |
) |
||||
|
|
|
|
|
|
|
|
|
||||
|
Balance, end of year |
|
$ |
2,434 |
|
$ |
1,300 |
|
$ |
326 |
|
|
69
5. Equipment
Equipment, net by asset class consisted of the following:
|
(In thousands) |
|
|
Estimated Life |
|
December 31, 2004 |
|
December 31, 2003 |
|
||
|
|
|
|
|
|
|
|
|
|||
|
Computers and printers |
|
3 years |
|
$ |
696 |
|
134 |
|
||
|
Furniture and fixtures |
|
3 years |
|
159 |
|
137 |
|
|||
|
Telephone system |
|
3 years |
|
400 |
|
114 |
|
|||
|
Software and programs |
|
3 years |
|
277 |
|
167 |
|
|||
|
Leasehold improvements |
|
3 years |
|
107 |
|
— |
|
|||
|
Less: accumulated depreciation |
|
|
|
(444 |
) |
(178 |
) |
|||
|
|
|
|
|
|
|
|
|
|||
|
Equipment, net |
|
|
|
$ |
1,195 |
|
$ |
374 |
|
|
6. Other Long-Term Assets
Other long-term assets consisted of the following:
|
(In thousands) |
|
|
December 31, 2004 |
|
December 31, 2003 |
|
||
|
|
|
|
|
|
|
|||
|
Capitalized software, net |
|
$ |
471 |
|
$ |
— |
|
|
|
Deposits |
|
345 |
|
104 |
|
|||
|
Capital lease |
|
97 |
|
— |
|
|||
|
Deferred financing costs |
|
1,909 |
|
123 |
|
|||
|
|
|
|
|
|
|
|||
|
Total other long-term assets, net |
|
$ |
2,822 |
|
$ |
227 |
|
|
7. Restricted Cash, Cash Equivalents and Energy Deposits
The Company has cash, cash equivalents and deposits related to outstanding letters of credit or cash deposited as collateral to secure performance under energy purchase contracts as follows:
70
|
(In thousands) |
|
December 31, 2004 |
|
December 31, 2003 |
|
||
|
|
|
|
|
|
|
||
|
Short-term investments pledged as collateral for letters of credit in connection with agreements for the purchase of electric power |
|
$ |
5,767 |
|
$ |
2,509 |
|
|
|
|
|
|
|
|
||
|
Cash and cash equivalents not pledged to letters of credit |
|
918 |
|
1,104 |
|
||
|
|
|
|
|
|
|
||
|
Total restricted cash and cash equivalents |
|
6,685 |
|
3,613 |
|
||
|
|
|
|
|
|
|
||
|
Energy deposits pledged as collateral in connection with agreements for the purchase of electric power |
|
304 |
|
103 |
|
||
|
|
|
|
|
|
|
||
|
Total restricted cash, cash equivalents and energy deposits |
|
$ |
6,989 |
|
$ |
3,716 |
|
At December 31, 2004, the Company had outstanding $5.8 million in letters of credit which were 100% collateralized with restricted cash. $1.2 million of these letters of credit secure the Company’s credit to participate in the ERCOT balancing market allowing the Company to buy and sell power on the balancing markets each day to ensure electricity supplies match customer demand. A letter of credit with JP Morgan Chase Bank in the amount of approximately $0.7 million, secured by cash, is available for use by the Company. A letter of credit in the amount of $3.3 million secures the Company’s credit to purchase power from TXU Portfolio Management (“TXU PM”) and pay for the power in the month following purchase. The remaining letters of credit totaling approximately $0.6 million are with the TDSPs in the regions in which the Company provides power to customers, and secure the Company’s outstanding pass-through charge invoices charged to customers and later paid to the TDSPs for their meter reading services and other grid maintenance charges.
8. Long-Term Debt
During the twelve months ended December 31, 2004, the Company entered into the (“Facility”) with Highbridge/Zwirn Special Opportunities Fund, L.P. The Facility, which matures on July 8, 2007, may be used to provide working capital for the Company’s normal routine operations and for providing a cash reserve to collateralize letters of credit that the Company is required to post. The Facility is collateralized by a lien on substantially all of the Company’s assets, subject to the liens already held on such assets by TXU PM and/or JP MorganChase.
Advances under the Facility bear interest at the rate of 14% per annum and the Company is permitted to prepay advances outstanding under the Facility at any time without penalty upon proper notice to the lenders thereunder. If at any time the Company has unrestricted cash or cash equivalents in excess of $1.2 million, the Company is required to make a prepayment on the advances then outstanding under the Facility in an amount equal to the amount of such cash or cash equivalents being held by the Company on the fifteenth and/or the last day of any month during the term of the Facility in excess
71
of $1.2 million, within one business day of such occurrence. In addition, the Company has agreed to pay to Highbridge/Zwirn Special Opportunities Fund, L.P., for the account of each lender under the Facility, an annual fee in the amount of $150,000 and a commitment fee, which accrues at 2% per annum on the average daily unused amount of the line during the term of the Facility.
The Facility contains the following covenants:
• the Company may not permit the leverage ratio (as defined in the Facility), as of the last day of each fiscal quarter, to be greater than 1.5;
• the Company may not permit the fixed charge coverage ratio (as defined in the Facility) as of the last day of each fiscal quarter to be lower than 1.3 for each quarter following September 30, 2004;
• the Company may not permit the interest coverage ratio (as defined in the Facility) as of the last day of each fiscal quarter to be lower than (i) 6.0 for the quarter ended December 31, 2004 and (ii) 4.7 for each of the quarters thereafter;
• the Company may not permit trailing twelve months EBITDA (as defined in the Facility) as of the last day of each fiscal quarter to be less than (i) $11.0 million for each of the quarters between October 1, 2004 and June 30, 2005 and (iii) $12.0 million for each of the quarters thereafter;
• the Company may not permit the current ratio (as defined in the Facility) as of the last day of any fiscal quarter to be lower than 1.1;
• the Company may not permit the amount of general and administrative costs (as defined in the Facility), which does not include bad debt or sales expenses, for any fiscal quarter to be greater than 6% of the Company’s sales; and
• the Company may not make any capital expenditures in the aggregate in an amount greater than the capital budget approved by the administrative agent under the Facility.
The Facility also contains other restrictions with respect to: the incurrence of debt and liens; the making of restricted payments, investments, loans and advances; entering into leases or sale and leasebacks; the sale or discount of receivables; the merger of the Company; the sale of its properties; entering into transactions with affiliates or into material agreements; and entering into negative pledge agreements, certain dividend restrictions and certain swap agreements. As of December 31, 2004, the Company was in compliance with all debt covenants.
72
In connection with the closing of the Facility, the Company issued to Highbridge/Zwirn Special Opportunities Fund, L.P. warrants to acquire 150,000 shares of Company common stock for an exercise price of $4.00 per share. The warrants are currently exercisable, expire on July 9, 2009 and contain anti-dilution protection for the holder of the warrants. Specifically, if the Company issues additional shares of common stock or other securities that are convertible into shares of the Company’s common stock, and the consideration for the shares are less than $4.00 per share, the exercise price for the warrants immediately preceding such issuance will be reduced according to the formula specified in the warrants. These warrants were fair valued using the Black Scholes model to determine the call warrant value of these warrants and were recorded as deferred financing costs and amortized over the life of the Facility. The assumptions used to value these warrants are presented below:
|
Input Variables |
|
|
|
|
|
|
|
|
|
|
||
|
Stock price (at market) |
|
$ |
4.75 |
|
|
|
Exercise price |
|
4.00 |
|
||
|
Term (in yrs) |
|
3.0 |
|
||
|
Volatility |
|
36 |
% |
||
|
Annual rate of quarterly dividends |
|
0 |
|
||
|
Discount rate - bond equivalent yield |
|
3 |
% |
||
These warrants were valued at approximately $250,000.
The Company also granted the holder of the warrants certain demand and piggyback registration rights pursuant to the terms of the warrants. After July 8, 2005, the holder of the warrants may, on one occasion, request that the Company register the sale of all or part of the Company’s common stock underlying the warrants under the Securities Act of 1933, as amended (the “Securities Act”). With respect to the piggyback registration rights, the Company must promptly notify the holder of the warrants of any proposed filing of certain registration statements under the Securities Act relating to underwritten offerings before such filing is to be made. The Company must also cause the holder’s securities to be included in the registration statement unless the Company’s underwritten offering becomes too large (as determined by the underwriter) to accommodate the securities of the holder, in which case the accounts of all persons with shares to be included in the offering may be reduced pro rata.
In connection with the closing of the Credit Facility, the Company paid a broker $200,000 in cash and issued to the broker warrants to acquire 125,000 shares of Company common stock for an exercise price of $4.00 per share as commission. The holder of the warrants was also granted “piggyback” registration rights similar to the “piggyback” registration rights discussed in the prior paragraph. The broker fees have been recorded as deferred financing costs and will be amortized over the life of the Facility. These warrants were fair valued using the Black Scholes model. The assumptions used to value these warrants are presented below:
73
|
Input Variables |
|
|
|
|
|
|
|
|
|
|
||
|
Stock price (at market) |
|
$ |
5.02 |
|
|
|
Exercise price |
|
4.00 |
|
||
|
Term (in yrs) |
|
3.0 |
|
||
|
Volatility |
|
36 |
% |
||
|
Annual rate of quarterly dividends |
|
0 |
|
||
|
Discount rate - bond equivalent yield |
|
3 |
% |
||
These warrants were valued at approximately $230,000.
In connection with the closing of the Facility and pursuant to a Termination Agreement, the Company repaid The Catalyst Fund, Ltd. (“Catalyst”) approximately $2.5 million, which represented all amounts outstanding under a Loan Agreement with Catalyst. The Company also repaid JTS Enterprises approximately $0.5 million and repaid Neil Leibman, the Company’s Chairman and CEO approximately $125,000 for outstanding loans. The Termination Agreement also terminated the loan documents executed in connection with the Catalyst loan, including a Security Agreement, Consulting Agreement and Registration Rights Agreement.
In addition, the Company purchased from Catalyst for approximately $1.6 million, warrants to acquire 458,333 shares of the Company’s common stock that were granted to Catalyst in connection with the Loan Agreement in order to eliminate the put option contained in such warrants in favor of the holder of such warrants. The Company also amended 91,667 warrants to delete the put option feature. See footnote 10 — Put Warrant Obligation.
Catalyst was granted a “look back” right with respect to the exercise price of the warrants to acquire 458,333 shares of the Company’s common stock as follows. In the event the Company consummates within one year, the disposition, by way of a sale, business combination, merger or other transaction by a corporation or other business entity, of all or part of the Company’s outstanding capital stock or all or substantially all of the Company’s assets (each such transaction being herein called a “Transaction”), and the price per share of the Company’s common stock actually received by the Company’s shareholders or the Company pursuant to the terms of the Transaction is greater than $4.00, then, upon the consummation of the Transaction, the Company is required to pay Catalyst an amount equal to the product of (a) 458,333 and (b) the difference between (i) the price per share of the Company’s common stock actually received by the Company’s shareholders or the Company pursuant to the terms of the Transaction and (ii) $4.00.
As of December 31, 2004 the Company had available a credit line of $15,000,000 with the Highbridge/Zwirn Opportunities Fund, L.P. with no outstanding borrowings against this line.
74
Long-term debt as of December 31, 2004 and 2003 consisted of the following:
|
(In thousands) |
|
December 31, |
|
December 31, |
|
||
|
|
|
|
|
|
|
||
|
Term loan payable to the Catalyst Fund Ltd., less a discount of $446,384, at 12.5% interest, collateralized by a second lien on all Company assets, payable in quarterly principal installments of $166,667 from January 1, 2004 until April 1, 2008. As of December 31, 2004, this loan has been repaid. |
|
$ |
— |
|
$ |
2,833 |
|
|
|
|
|
|
|
|
||
|
Term loan payable to JTS Enterprises Inc., less a discount of $110,679, at 12.5% interest, collateralized by a lien on all Company assets subordinate to the term loan with The Catalyst Fund Ltd., payable in quarterly principal installments of $36,111 from January 1, 2004 until April 1, 2008. As of December 31, 2004, this loan has been repaid. |
|
— |
|
614 |
|
||
|
|
|
|
|
|
|
||
|
Note payable to officer, unsecured, accruing interest at 6%, principal and accrued interest payable in full on or before May 1, 2006. As of December 31, 2004, this loan has been repaid. |
|
— |
|
100 |
|
||
|
|
|
|
|
|
|
||
|
Total Debt |
|
— |
|
3,547 |
|
||
|
|
|
|
|
|
|
||
|
Less: discount for warrants |
|
— |
|
(557) |
|
||
|
|
|
|
|
|
|
||
|
Debt, net of discount |
|
— |
|
2,990 |
|
||
|
|
|
|
|
|
|
||
|
Less: current portion |
|
— |
|
(608) |
|
||
|
|
|
|
|
|
|
||
|
Long-term debt, net of discount and current portion |
|
$ |
— |
|
$ |
2,382 |
|
9. Commitments and Contingencies
Purchase Commitments
The Company acquires the forecasted balance of its electricity load needs for resale through advance contract purchases. As of December 31, 2004, the Company had purchase commitments for the future delivery of electricity in the amount of $86.7 million for 2005, and $17.8 for 2006. The Company has no commitments for purchases of electricity beyond December 31, 2006.
|
(In thousands) |
|
Payments due by period |
|
||||||||||||||
|
Contractual Obligations |
|
Total |
|
Less than 1 year |
|
1-3 years |
|
3-5 years |
|
More than 5 years |
|
||||||
|
Forward power contracts |
|
$ |
104,486 |
|
$ |
86,698 |
|
$ |
17,788 |
|
$ |
— |
|
$ |
— |
|
|
|
Long-term debt |
|
— |
|
— |
|
— |
|
— |
|
— |
|
||||||
|
Rent |
|
2,330 |
|
383 |
|
766 |
|
766 |
|
415 |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
|
Total |
|
$ |
106,816 |
|
$ |
87,081 |
|
$ |
18,554 |
|
$ |
766 |
|
$ |
415 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
75
Operating Leases
At December 31, 2004, the Company’s lease commitments included a rental contract through April 2007 for its old corporate offices, and a rental contract through January 2011 on the Company’s new corporate offices. Lease expense for the Company was approximately $423,000, $186,000 and $72,000 for the years ended 2004, 2003 and 2002 respectively.
Long-Term Sales Contracts
The Company serves three categories of customers: commercial customers on long-term contracts, commercial customers on month to month contracts, and residential customers on month-to-month contracts. The Company strives to add long-term purchase commitments to match its long-term sales.
10. Puttable Warrant Obligation
SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity, was issued in May 2003 and requires issuers to classify as liabilities (or assets under certain circumstances) free standing financial instruments which, at inception, require or may require an issuer to settle an obligation by transferring assets. SFAS No. 150 was effective for financial instruments entered into or modified after May 31, 2003 and was otherwise effective at the beginning of the first interim period beginning after June 15, 2003.
SFAS No. 150 required warrants issued under a term loan agreement with The Catalyst Fund Ltd. (“Catalyst”) and certain other warrants held by affiliates to be classified as a liability. In January of 2005, the holders of the warrants could have exercised their rights to force the Company to repurchase the 550,000 common shares at the current market price on the common stock, less the warrant exercise price of $1.00. The put feature could have been accelerated by a change of control or a capital offering in excess of $10 million; therefore, the Company could have been forced to purchase up to 550,000 shares of its own common stock at the market price (less the $1 warrant exercise price) on the day the put option is exercised.
On July 8, 2004, 458,333 of these warrants were repurchased and the remaining 91,667 warrants were amended to delete the put option. At July 8, 2004, our stock closed at $4.75 per share. The decrease in the market price from the valuation at December 31, 2003 based on the close price of $8.50 per share, on December 31, 2003, required us to record a decrease in the value of the puttable warrant obligation of $2.1 million for the year ended December 31, 2004 as other financing income in accordance with SFAS No. 150. An additional $0.7 million in gain on extinguishment of debt was recorded during 2004. We also recorded $0.6 million of write-off of deferred financing cost and $0.3 million of transaction fees to interest expense during fiscal 2004, as a result of the extinguishment of the debt. As a result of the repurchase and amendment of warrants the
76
ongoing income (expense) effect arising from the put option, as described above, will no longer be applicable.
General Contingency
The Company has established reserves that it believes to be adequate based on current evaluation and its experience in these types of claim situations. Nevertheless, an unexpected outcome in any such case could have a material adverse impact on the Company’s results of operations in the period it occurs. Moreover, future adverse developments in such cases could require material changes in the recorded reserve amounts.
11. Related Party Transactions
During the twelve months ended December 31, 2004, the Company completed a private placement with Perry Capital, Zimmer Lucas Partners, LLC, Corsair Capital Management and other accredited investors. This private placement also included the Company’s Chairman, CEO, and President, Neil M. Leibman, selling 750,000 shares of Common Stock. Oppenheimer & Co. Inc. acted as the placement agent for the transaction. See Note 14, Shareholder’s Equity for more details on this private placement.
During the twelve months ended December 31, 2004, the Company repaid Neil Leibman, Chairman and CEO, approximately $125,000 for outstanding loans. Additionally, in connection with repaying and terminating the Catalyst loan, a Consulting Agreement executed in connection with the Catalyst loan was also terminated during this period. Neil Leibman, Chairman, President and CEO, and non-employee directors Bobby Orr, Don Aron and Stuart Gaylor received the amounts due to them under the Consulting Agreement, which were one-time cash payments equal to approximately $9,000, $9,000, $18,000, and $9,000 respectively.
12. Adjustment of Prior Periods
As described in Item 7, Management’s Discussion and Analysis, subsequent to December 31, 2003, the Company determined that its revenues reported in reports on Form 10-QSB for the three months and year to date ended June 30, 2003 and September 30, 2003 (which were based on the “billings” technique for estimating volumes delivered to customers) did not reflect the consideration of all information available at the time to calculate a reasonable estimate of the Company’s revenues in accordance with GAAP as discussed below.
Until November of 2002, the Company was not a Qualified Scheduling Entity (“QSE”), and therefore did not receive ERCOT supply and delivery volume information with which to estimate electricity volumes delivered to its customers. The only data available to the Company to estimate deliveries to customers and therefore to estimate revenues were the billings sent to customers. The use of actual billings was the most appropriate and conservative technique for the following reasons:
77
• estimating revenue based on billings did not include in the revenue estimation lost or severely late transactions (which were at high risk for bad debt classification and in some instances were unbillable to customers due to their age),
• the newness of the market created many technical difficulties with transactional flow and also created concerns regarding accuracy and timeliness of information from ERCOT, and
• since the Company was not a QSE, the Company did not have access to daily ERCOT settlement data (provided to all QSEs) until November 2002, and also did not have access to final resettlement data from ERCOT showing final power deliveries for a given month until late 2003 (final resettlements are delivered approximately 6-7 months after the month end).
The billings technique was designed to estimate revenue based on a 30-day period of billing that most closely approximated the flow month to which the revenue was being accrued. The Company assessed meter read cycles, billing dates and the time lag of converting meter reads to customer billings in attempting to determine the billing dates appropriate for estimating monthly revenue. Typically, the 30-day billing period included electricity deliveries that were made on days in the current and subsequent months as meter readings typically cover a thirty day-period, and occur throughout the month based on meter reading cycles performed by the transmission and distribution service provider.
2003
During 2003, the Company’s management used a variety of information to help ensure the accuracy of the estimated revenues, including daily estimates of power flow, knowledge of weather patterns, knowledge of inaccuracies of billing information and/or supply information, and expected power supply resettlements.
After the preparation of the third quarter 2003 financial statements, the Company’s management began to more fully recognize the limitations of the billings technique, particularly as indicated by the volatility of the quarterly and monthly margin analysis.
In recognition of these limitations, in November 2003, the Company changed its revenue estimation technique to the “flow” technique. In the latter half of 2003, the Company determined that the market was operating at a point of efficiency that made it possible for the Company to begin accruing revenue based on ERCOT settlements of power deliveries, and given the limitations of the billings technique noted above, the Company chose to change to the flow technique. In addition, by the end of 2003, the Company had sufficient initial settlement and resettlement data from ERCOT to arrive at a reasonable estimate for 2003 revenues assuming that the flow method had been in place since January 1, 2003.
78
As described above, the billings technique includes delivered volumes from future months in the month for which volumes are being estimated. In periods of relatively low growth, this characteristic should not have a material effect on the accuracy of the estimation. However, in periods of strong customer growth and utilization, such as occurred during the second half of 2003, including the billings from a future period may overestimate the revenue for the period being reported.
Additionally, the Company conducted an exhaustive review of the application of the billings technique for January-October 2003, which revealed that during the second and third quarters, the estimated energy revenue appears to be overstated when compared to other methods and information available. This overestimation appears to be the result of much higher power usage of customers in subsequent periods, which were included in the reported period. This resulted in higher reported revenue for the second and third quarters than what should have been accrued.
Pursuant to applicable accounting guidance, reporting the correction of an error in previously issued financial statements should be reported as a prior period adjustment. The nature of the error in previously issued financial statements and the effect of its correction on income before extraordinary item, net income, and the related per share amount should be disclosed in the period in which the error was discovered and corrected. Since the error was discovered and corrected during the preparation of the 2003 10-KSB, the corrections for the second and third quarter of 2003 are disclosed in the 2003 10-KSB.
These adjustments resulted in a redistribution of revenues across the second, third, and fourth quarters of 2003. Cash flow for the second, third, and fourth quarters of 2003 was not affected by these changes.
Information regarding the adjustments is provided below as it relates to changes in the Statement of Operations, specifically for adjusted sales, income from operations, net income available to common shareholders and net income (loss) per share for the three months and year-to-date periods ending June 30, 2003 and September 30, 2003.
79
|
(In thousands, except per share amounts) |
|
|
|
|
|
||
|
Three months ended June 30, 2003 |
|
As Reported |
|
As Adjusted |
|
||
|
|
|
|
|
|
|
||
|
Sales |
|
$ |
23,516 |
|
$ |
21,448 |
|
|
|
|
|
|
|
|
||
|
Income (loss) from operations |
|
1,583 |
|
(31 |
) |
||
|
|
|
|
|
|
|
||
|
Net Income (loss) available to common shareholders |
|
937 |
|
(80 |
) |
||
|
|
|
|
|
|
|
||
|
Basic net income (loss) per share |
|
0.12 |
|
(0.01 |
) |
||
|
|
|
|
|
|
|
||
|
Diluted net income (loss) per share |
|
$ |
0.11 |
|
$ |
(0.01 |
) |
|
|
|
|
|
|
|
||
|
Six months ended June 30, 2003 |
|
As
Reported |
|
As Adjusted |
|
||
|
|
|
|
|
|
|
||
|
Sales |
|
$ |
36,436 |
|
$ |
34,368 |
|
|
|
|
|
|
|
|
||
|
Income (loss) from operations |
|
1,197 |
|
(417 |
) |
||
|
|
|
|
|
|
|
||
|
Net Income (loss) available to common shareholders |
|
678 |
|
(340 |
) |
||
|
|
|
|
|
|
|
||
|
Basic net income (loss) per share |
|
0.09 |
|
(0.04 |
) |
||
|
|
|
|
|
|
|
||
|
Diluted net income (loss) per share |
|
$ |
0.09 |
|
$ |
(0.04 |
) |
|
|
|
|
|
|
|
||
|
Three months ended September 30, 2003 |
|
As
Reported |
|
As Adjusted |
|
||
|
|
|
|
|
|
|
||
|
Sales |
|
$ |
41,690 |
|
$ |
39,644 |
|
|
|
|
|
|
|
|
||
|
Income from operations |
|
3,664 |
|
2,046 |
|
||
|
|
|
|
|
|
|
||
|
Net Income available to common shareholders |
|
2,027 |
|
1,006 |
|
||
|
|
|
|
|
|
|
||
|
Basic net income per share |
|
0.27 |
|
0.13 |
|
||
|
|
|
|
|
|
|
||
|
Diluted net income per share |
|
$ |
0.25 |
|
$ |
0.13 |
|
|
|
|
|
|
|
|
||
|
Nine months ended September 30, 2003 |
|
As
Reported |
|
As Adjusted |
|
||
|
|
|
|
|
|
|
||
|
Sales |
|
$ |
78,127 |
|
$ |
74,012 |
|
|
|
|
|
|
|
|
||
|
Income from operations |
|
4,861 |
|
1,629 |
|
||
|
|
|
|
|
|
|
||
|
Net Income available to common shareholders |
|
2,769 |
|
732 |
|
||
|
|
|
|
|
|
|
||
|
Basic net income per share |
|
0.36 |
|
0.10 |
|
||
|
|
|
|
|
|
|
||
|
Diluted net income per share |
|
$ |
0.36 |
|
$ |
0.10 |
|
80
13. Earnings Per Share
Basic earnings per share is computed based on weighted average shares outstanding and excludes dilutive securities. Diluted earnings per share are computed including the impacts of all potentially dilutive securities. The following table sets forth the computation of basic and diluted earnings per share for the years ended December 31, 2004, 2003 and 2002:
|
(In thousands) |
|
December 31, 2004 |
|
December 31, 2003 |
|
December 31, 2002 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Numerator: |
|
|
|
|
|
|
|
|||
|
Net Income (loss) |
|
$ |
8,182 |
|
$ |
(2,196) |
|
$ |
640 |
|
|
Preferred stock dividend |
|
— |
|
(167) |
|
(50) |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Net Income (loss) available to common stockholders |
|
$ |
8,182 |
|
$ |
(2,363) |
|
$ |
590 |
|
|
|
|
|
|
|
|
|
|
|||
|
Denominator: |
|
|
|
|
|
|
|
|||
|
Basic weighted average shares outstanding |
|
8,606 |
|
7,647 |
|
7,328 |
|
|||
|
Effect of dilutive securities: |
|
|
|
|
|
|
|
|||
|
Stock options issued to employees and directors |
|
1,054 |
|
— |
|
187 |
|
|||
|
Warrants issued for services |
|
175 |
|
— |
|
— |
|
|||
|
Assumed conversion of convertible preferred stock |
|
— |
|
— |
|
474 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Adjusted weighted average shares outstanding |
|
9,835 |
|
7,647 |
|
7,989 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Basic earnings (loss) per share |
|
$ |
0.95 |
|
$ |
(0.31) |
|
$ |
0.08 |
|
|
Diluted earnings (loss) per share |
|
0.83 |
|
(0.31) |
|
0.07 |
|
|||
For the twelve months ended December 31, 2004, there were no common share equivalents that would have been anti-dilutive and therefore not used in the computation of diluted weighted average shares.
For the twelve months ended December 31, 2003, there were 754,378 common share equivalents that would have been anti-dilutive and are therefore not used in the computation of diluted weighted average shares.
For the twelve months ended December 31, 2002, there were 685 common share equivalents that would have been anti-dilutive and are therefore not used in the computation of diluted weighted average shares.
14. Shareholder’s Equity
Stock Options & Stock Warrants
During the twelve months ended, 2004, the Company, in connection with the closing of the Highbridge/Zwirn Credit Facility, issued warrants to purchase 125,000
81
shares of Company common stock as a commission to Prospect Street Ventures Ltd. for an exercise price of $4.00 per share. In addition, the Company, also in connection with the closing of the Highbridge/Zwirn Credit Facility, issued to Highbridge/Zwirn Special Opportunities Fund, L.P. warrants to purchase 150,000 shares of Company common stock for an exercise price of $4.00.
During the twelve months ended December 31, 2004, the Company entered into a Severance Agreement with James Burke, the Company’s former President and Chief Operating Officer. As part of his exit from the Company, if there is a “change of control” as defined in his severance agreement on or before December 31, 2005, options for Mr. Burke to purchase an additional 116,667 shares of common stock will vest. If the change in control does not occur on or before December 31, 2005, the 116,667 option shares of the Company’s common stock will not vest and will thus be cancelled.
During the twelve months ended December 31, 2004, the Board of Directors, subject to shareholder approval, adopted the 2004 Incentive Plan, which provides for the issuance of up to 1.5 million shares of common stock pursuant to incentive awards under the plan. During the twelve months ended December 31, 2004, 930,000 options were issued to officers and employees and 100,000 options were issued to non-employee directors under the 2004 Incentive Plan. These options were issued with exercise prices ranging from $4.50 to $5.51. See the stock option table below for detailed weighted average share information.
During the twelve months ended December 31, 2004, the Company negotiated an agreement to settle a lawsuit with Capello Capital Corp. The settlement involves in part the issuance of 400,000 warrants with an exercise price of $4.50 to Capello Capital Corp.
The assumptions used to value these warrants are presented below :
|
Input Variables |
|
|
|
|
|
|
|
|
|
|
||
|
Stock price (at market) |
|
$ |
4.05 |
|
|
|
Exercise price |
|
4.50 |
|
||
|
Term (in yrs) |
|
3.0 |
|
||
|
Volatility |
|
36 |
% |
||
|
Annual rate of quarterly dividends |
|
0 |
|
||
|
Discount rate - bond equivalent yield |
|
3 |
% |
||
These 400,000 warrants were valued at approximately $390,000.
During the twelve months ended December 31, 2004, the Company completed a private placement with Perry Capital, Zimmer Lucas Partners, LLC, Corsair Capital Management and other accredited investors of 175,000 equity units at $43.00 per Unit for aggregate gross proceeds of $7,525,000. Each unit sold in the Private Placement
82
consisted of 10 shares of the Company’s common stock, $0.1 par value and three 5-year warrants to purchase 1 share of the Company’s common stock. In total, the Company sold 1,000,000 shares of common stock and 525,000 warrants, and Neil M. Leibman, the Company’s Chairman and CEO sold 750,000 shares of common stock. Oppenheimer & Co. Inc. acted as the placement agent for the transaction. These warrants were issued to the accredited investors mentioned above and to Oppenheimer & Co. Inc. These warrants were fair valued using the Black Scholes model. The assumptions used to value these warrants, are presented below:
The assumptions used to value these warrants are presented below:
|
Input Variables |
|
|
|
|
|
|
|
|
|
|
||
|
Stock price (at market) |
|
$ |
4.25 |
|
|
|
Exercise price |
|
5.59 |
|
||
|
Term (in yrs) |
|
3 |
|
||
|
Volatility |
|
36 |
% |
||
|
Annual rate of quarterly dividends |
|
0 |
|
||
|
Discount rate - bond equivalent yield |
|
3 |
% |
||
These 525,000 warrants were valued at approximately $400,000.
83
Stock option activity for the years ended December 31, 2002, 2003, and 2004 is set forth below:
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Per Share |
|
||||||
|
|
|
Number of |
|
Option Price Range Per |
|
Exercise Price |
|
Grant Date Fair Value |
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Options oustanding at December 31, 2001 |
|
600,000 |
|
$ |
1.50 |
|
- |
|
$ |
1.50 |
|
$ |
1.50 |
|
$ |
1.38 |
|
|
Granted |
|
250,000 |
|
2.00 |
|
- |
|
2.00 |
|
2.00 |
|
1.70 |
|
||||
|
Exercised |
|
— |
|
— |
|
|
|
— |
|
— |
|
— |
|
||||
|
Canceled |
|
— |
|
— |
|
|
|
— |
|
— |
|
— |
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Options oustanding at December 31, 2002 |
|
850,000 |
|
1.50 |
|
- |
|
2.00 |
|
1.65 |
|
1.47 |
|
||||
|
Granted |
|
1,000,000 |
|
1.00 |
|
- |
|
2.25 |
|
1.89 |
|
1.80 |
|
||||
|
Exercised |
|
— |
|
— |
|
|
|
— |
|
— |
|
— |
|
||||
|
Canceled |
|
(300,000 |
) |
1.50 |
|
- |
|
1.50 |
|
1.50 |
|
1.38 |
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Options oustanding at December 31, 2003 |
|
1,550,000 |
|
1.00 |
|
|
|
2.25 |
|
1.83 |
|
1.70 |
|
||||
|
Granted |
|
1,030,000 |
|
4.35 |
|
- |
|
5.51 |
|
4.67 |
|
1.39 |
|
||||
|
Exercised |
|
— |
|
— |
|
|
|
— |
|
— |
|
— |
|
||||
|
Canceled |
|
(100,000 |
) |
4.35 |
|
- |
|
4.35 |
|
4.35 |
|
1.39 |
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Options oustanding at December 31, 2004 |
|
2,480,000 |
|
1.00 |
|
- |
|
5.51 |
|
2.91 |
|
1.59 |
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Exercisable at December 31, 2002 |
|
600,000 |
|
|
|
|
|
|
|
|
|
|
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Exercisable at December 31, 2003 |
|
942,000 |
|
|
|
|
|
|
|
|
|
|
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Exercisable at December 31, 2004 |
|
1,466,800 |
|
|
|
|
|
|
|
|
|
|
|
||||
The weighted average characteristics of stock options outstanding as of December 31, 2004 were as follows:
|
Range of Exercise Prices |
|
Number of Shares |
|
Average Remaining |
|
Shares |
|
Weighted Average |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ 1.00 - $1.50 |
|
650,000 |
|
1.4 |
|
650,000 |
|
$ |
1.50 |
|
|
$ 2.00 - $2.25 |
|
900,000 |
|
2.7 |
|
775,050 |
|
$ |
2.10 |
|
|
$ 4.56 - $5.51 |
|
930,000 |
|
10.0 |
|
41,750 |
|
$ |
4.70 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ 1.00 - $5.51 |
|
2,480,000 |
|
5.09 |
|
1,466,800 |
|
$ |
2.91 |
|
The fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted average assumptions used for options issued in 2002 and 2003: risk-free interest rate of 3.0% for 2003 and 3% for 2004; expected lives of three years, assumed volatility of 124% for 2003 and 36-176% for 2004; and no expected dividends.
84
Stock warrant activity is set forth below:
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Per Share |
|
|||||||
|
|
|
Number of |
|
Warrant Price Range Per |
|
Exercise |
|
Grant Date Fair |
|
|||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Warrants oustanding at December 31, 2001 |
|
$ |
— |
|
$ |
— |
|
|
|
$ |
— |
|
$ |
— |
|
$ |
— |
|
|
Granted |
|
100,000 |
|
1.25 |
|
- |
|
1.25 |
|
1.25 |
|
2.29 |
|
|||||
|
Exercised |
|
— |
|
— |
|
|
|
— |
|
— |
|
— |
|
|||||
|
Canceled |
|
— |
|
— |
|
|
|
— |
|
— |
|
— |
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Warrants oustanding at December 31, 2002 |
|
100,000 |
|
1.25 |
|
- |
|
1.25 |
|
1.25 |
|
2.29 |
|
|||||
|
Granted |
|
931,000 |
|
1.00 |
|
- |
|
1.00 |
|
1.00 |
|
1.60 |
|
|||||
|
Exercised |
|
— |
|
— |
|
|
|
— |
|
— |
|
— |
|
|||||
|
Canceled |
|
(300,000 |
) |
1.00 |
|
- |
|
1.00 |
|
1.00 |
|
1.51 |
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Warrants oustanding at December 31, 2003 |
|
731,000 |
|
1.00 |
|
- |
|
1.25 |
|
1.03 |
|
1.73 |
|
|||||
|
Granted |
|
1,359,250 |
|
4.00 |
|
- |
|
6.02 |
|
5.00 |
|
1.01 |
|
|||||
|
Exercised |
|
(199,334 |
) |
1.00 |
|
- |
|
1.25 |
|
1.13 |
|
1.97 |
|
|||||
|
Canceled |
|
— |
|
— |
|
|
|
— |
|
— |
|
— |
|
|||||
|
Repurchased |
|
(458,333 |
) |
1.00 |
|
- |
|
1.00 |
|
1.00 |
|
1.64 |
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Warrants oustanding at December 31, 2004 |
|
1,432,583 |
|
1.00 |
|
- |
|
6.02 |
|
4.79 |
|
1.04 |
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Exercisable at December 31, 2002 |
|
100,000 |
|
|
|
|
|
|
|
|
|
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Exercisable at December 31, 2003 |
|
731,000 |
|
|
|
|
|
|
|
|
|
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Exercisable at December 31, 2004 |
|
1,432,583 |
|
|
|
|
|
|
|
|
|
|
|
|||||
The weighted average characteristics of stock warrants outstanding as of December 31, 2004 were as follows:
|
Range of Exercise Prices |
|
Number of Shares |
|
Average Remaining |
|
Shares |
|
Weighted Average |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ 1.00 - $1.25 |
|
73,333 |
|
0.6 |
|
73,333 |
|
$ |
1.00 |
|
|
$ 4.00 - $6.02 |
|
1,359,250 |
|
4.8 |
|
1,359,250 |
|
$ |
5.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,432,583 |
|
4.6 |
|
1,432,583 |
|
$ |
4.80 |
|
85
15. Income Taxes
The provision for income taxes consisted of the following for the years presented below:
|
(In thousands) |
|
|
December 31, 2004 |
|
December 31, 2003 |
|
December 31, 2002 |
|
|||
|
|
|
|
|
|
|
|
|
||||
|
Current: |
|
|
|
|
|
|
|
||||
|
Federal |
|
$ |
3,649 |
|
$ |
1,357 |
|
$ |
368 |
|
|
|
State |
|
521 |
|
119 |
|
— |
|
||||
|
Deferred benefit |
|
(136 |
) |
(554 |
) |
(37 |
) |
||||
|
|
|
|
|
|
|
|
|
||||
|
Total income tax expense |
|
$ |
4,034 |
|
$ |
922 |
|
$ |
331 |
|
|
The deferred tax asset at December 31, 2004 and 2003 respectively was comprised of the following:
|
|
|
2004 |
|
2003 |
|
|||||||||
|
(In thousands) |
|
|
Current |
|
Non Current |
|
Current |
|
Non Current |
|
||||
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Allowance for bad debts |
|
$ |
827 |
|
$ |
— |
|
$ |
442 |
|
$ |
— |
|
|
|
Unamortized billings |
|
21 |
|
21 |
|
16 |
|
— |
|
|||||
|
Restricted stock grant |
|
(10 |
) |
— |
|
— |
|
— |
|
|||||
|
Capitalized labor |
|
— |
|
(44 |
) |
— |
|
48 |
|
|||||
|
Capitalized software |
|
— |
|
(11 |
) |
— |
|
— |
|
|||||
|
Former officers options |
|
— |
|
244 |
|
— |
|
244 |
|
|||||
|
Related party interest |
|
3 |
|
— |
|
— |
|
— |
|
|||||
|
Investment in partnership |
|
— |
|
5 |
|
— |
|
— |
|
|||||
|
Depreciation |
|
— |
|
(170 |
) |
— |
|
— |
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Total deferred tax assets |
|
$ |
841 |
|
$ |
45 |
|
$ |
458 |
|
$ |
292 |
|
|
86
The differences between income taxes computed for federal taxes at 34% from the provision for income taxes for the years ended, December 31, 2004, 2003, and 2002 are as follows:
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Earnings (loss) before income taxes |
|
$ |
12,216 |
|
$ |
(1,274 |
) |
$ |
971 |
|
|
|
|
|
|
|
|
|
|
|||
|
Federal statutory rate |
|
34 |
% |
34 |
% |
34 |
% |
|||
|
|
|
|
|
|
|
|
|
|||
|
Income tax expense (benefit) at statutory rate |
|
$ |
4,153 |
|
$ |
(433 |
) |
$ |
330 |
|
|
|
|
|
|
|
|
|
|
|||
|
Net addition (reduction) in taxes resulting from: |
|
|
|
|
|
|
|
|||
|
|
|
|
|
|
|
|
|
|||
|
State income taxes, net of federal income tax benefit |
|
$ |
344 |
|
$ |
78 |
|
$ |
— |
|
|
Other financing expense (income) |
|
(701 |
) |
1,342 |
|
— |
|
|||
|
Penalties and interest |
|
311 |
|
— |
|
— |
|
|||
|
Other, net |
|
(73 |
) |
(65 |
) |
1 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Total |
|
$ |
(119 |
) |
$ |
1,355 |
|
$ |
1 |
|
|
|
|
|
|
|
|
|
|
|||
|
Income tax expense |
|
$ |
4,034 |
|
$ |
922 |
|
$ |
331 |
|
16. Employee Benefits
The Company offers a preferred provider health plan to all full-time employees after the first month of full time service. The Company pays for 75% of the employee’s coverage, with the employee responsible for the remaining 25% plus any expenses for added family members. The Company also offers dental insurance at employee expense and a defined contribution plan, both of which become available after one month of full time service. The defined contribution plan is available to all employees. At this time, the Company is not offering matching contributions pursuant to the defined contribution plan.
17. Legal Proceedings
During 2003, we were sued in the matter of Kyle Holland vs. Gexa Corp. et al. in the United States District Court, Western District of Texas. Mr. Holland alleged damages in connection with his acquisition of our common stock. The complaint seeks unspecified damages. On March 15, 2005, this case was dismissed without prejudice for failure to state a claim. While this lawsuit could be refiled at a later date, we believe the lawsuit has no merit and will vigorously defend any such refiled action.
On July 15, 2004, a class action lawsuit Frederick T. Pappey, et al. vs. Gexa Corp., Neil Leibman, Marcie Zlotnik and Sarah Veach, Civil Action No. H-04-2869, was filed in the United States District Court for the Southern District of Texas, Houston District. The complaint alleges, among other things, that our publicly filed reports and public statements contained false and misleading information, which resulted in damages to the plaintiff and members of the proposed class when they purchased our securities. Specifically, the complaint alleges that we overstated revenue during the second and third quarters of 2003 by $2.07 million and $2.05 million, respectively, by utilizing an improper accounting
87
method for calculating sales of electric power. The complaint alleges that our conduct and the conduct of the other defendants violated Sections 10(b) and 10b-5 and that the individual defendants violated Section 20(a) of the Securities Exchange Act of 1934. The complaint seeks unspecified damages. On December 20, 2004, the lawsuit was dismissed without prejudice. While this lawsuit could be refiled at a later date, we believe the lawsuit has no merit and will vigorously defend any such refiled action.
On November 30, 2004, we entered into a settlement with Capello Capital Corp. (“Capello”) relating to the matter of Capello Capital Corp. vs. Gexa Corp, originally filed in the Los Angeles Superior Court-West District. Capello’s complaint had alleged a breach of contract regarding investment banker fees being claimed by Capello in connection with the credit facility with Highbridge/Zwirn Special Opportunities Fund, L.P. In exchange for Capello’s agreement to dismiss the lawsuit and release its claims against us, we agreed to: (i) pay Capello $275,000, (ii) issue to Capello warrants dated November 1, 2004, to purchase 400,000 shares of our common stock at an exercise price of $4.50 per share and (iii) issue to Capello an interest free unsecured promissory note in the principal amount of $500,000. We accrued $1.2 million in the third quarter of 2004 in investment banking charges to other assets as deferred financing cost to be amortized over the life of the Highbridge facility.
On December 2, 2004, we were sued in the matter of Essential Utilities Corporation v. Gexa Energy Corp., Cause No. 04-12056, in the 191st District Court of Dallas County, Texas. The petition alleges breach of contract, quantum meruit, conversion and unjust enrichment in connection with the alleged nonpayment of consultation fees. The amount of the claim is unknown. This case is in the preliminary stages and we intend to contest this suit vigorously.
On January 31, 2005, a lawsuit styled Griffin/Juban Capital Management, L.L.C. d/b/a GC Realty Services v. Gexa Corporation was filed in the 11th Judicial District Court of Harris County, Texas. This lawsuit claims that we agreed to provide Continental Airlines frequent flyer miles to the plaintiff in turn for doing business with us. The plaintiff has sued us for breach of contract, fraud and negligent misrepresentation. The amount of damages sought in the lawsuit is unknown. This case is in the preliminary stages and we intend to contest this suit vigorously.
On or about February 11, 2005, we were made aware of a potential lawsuit that may be filed by Prenova, Inc. and 24 Hour Fitness USA, Inc. against us and XERS, Inc. d/b/a XCEL Energy, Inc. The proposed complaint claims that we failed to timely provide electrical service to 24 Hour Fitness and, as a result, they incurred substantial damages in the form of significantly higher rates for several months in 2004. The plaintiffs claim damages in the amount of $150,000.00 plus interest and attorneys’ fees. If filed, we intend to contest this suit vigorously.
We are also involved in various receivable collections matters as a plaintiff. We believe that there are no pending matters that will have a significant impact on our financial position or results of operations.
88
18. Concentration of Credit Risk
For the fiscal years ended December 31, 2004 and 2003, the Company has a credit support agreement with TXU that allows the Company to purchase power from TXU or other third party suppliers.
As of December 31, 2004, the Company has secured numerous large commercial customers: however none is of sufficient size to have a significant negative impact on our cash flow or ability to continue operations in the event of default, refusal to pay, or undue delay in payment. For the years ended December 31, 2004 and 2003, no single customer accounted for more than 3% of revenues. All of the Company’s customers were located in Texas for the years ended December 31, 2004, 2003, and 2002.
19. Subsequent Events (unaudited)
Merger
On March 28, 2005 the Company and FPL Group, Inc., a Florida corporation (“FPL Group”), announced the execution of an Agreement and Plan of Merger, dated as of March 28, 2005 (the “Merger Agreement”), by and among FRM Holdings, LLC, a Delaware limited liability company (“FRM Holdings”), WPRM Acquisition Subsidiary, Inc., a Texas corporation and a wholly owned subsidiary of Holdings (“Merger Sub”), FPL Group and the Company, pursuant to which, subject to the satisfaction or waiver of the conditions therein, Merger Sub will merge with and into the Company (the “Merger”). As a result of the Merger, the Company will become an indirect wholly owned subsidiary of FPL Group. The Merger is intended to qualify as a tax-free reorganization under Section 368(a) of the Internal Revenue Code of 1986, as amended.
At the effective time of the Merger (the “Effective Time”), each share of Company common stock issued and outstanding immediately prior to the Effective Time (other than treasury shares) will be cancelled and automatically convert into the right to receive $6.88, payable in shares of validly issued, fully paid and non-assessable shares of FPL Group common stock, based on an exchange ratio equal to the quotient (rounded to four decimal points) obtained by dividing $6.88 by the average of the daily closing sale prices of FPL Group common stock for the 10 consecutive trading days ending on the third business day (including such third business day) immediately prior to the closing date. In addition, at the Effective Time, each option and warrant to purchase shares of Company common stock outstanding immediately prior to the Effective Time will be assumed by FPL Group and converted into the right to purchase shares of FPL Group common stock with corresponding adjustments to the exercise price based upon the foregoing exchange ratio, but otherwise will remain unchanged except that vesting of the options will be accelerated at the Effective Time.
Simultaneously with the execution of the Merger Agreement, certain directors and officers of the Company holding approximately 36% of the outstanding Company common stock, including its Chairman and CEO, entered into a Voting Agreement with FPL Group, pursuant to which, they agreed to vote their shares of Company common stock in favor of the Merger, the Merger Agreement and the transactions contemplated thereby. In the event that such directors and officers fail to so vote, the Voting Agreement provides for the grant proxies to FPL Group to vote and otherwise act with respect to such shares of Company common stock at any meeting of shareholders or consent in lieu of any such meeting or otherwise, on the Merger, the Merger Agreement and the transactions contemplated thereby.
The Company has made customary representations and warranties and covenants in the Merger Agreement, including among others (i) to conduct its businesses in the ordinary course between the execution of the Merger Agreement and the consummation of the Merger, (ii) to cause a meeting of the Company’s shareholders to be held to consider the adoption of the Merger Agreement, (iii) subject to certain exceptions, for the Company’s board of directors to recommend that the Company’s shareholders adopt and approve the Merger Agreement, and (iv) subject to certain exceptions, not to (A) solicit proposals relating to alternative business combination transactions or (B) enter into discussions concerning or provide information in connection with alternative business combination transactions.
Consummation of the Merger is subject to customary conditions, including, among others, (i) approval of the Company’s shareholders, (ii) expiration or termination of the applicable Hart-Scott-Rodino Act waiting period, (iii) approval by the Commission of Texas (the “PUCT”) of an amendment application regarding the change of ownership of the Company with respect to its retail electric provider license and, if required by the PUCT, of an application for recertification, (iv) absence of any order or injunction prohibiting the consummation of the Merger, (v) the Company having $13.5 million of Working Capital (as defined in the Merger Agreement) as of month end not ending more than 60 days prior to closing, (vi) subject to certain exceptions, the accuracy of representations and warranties with respect to the Company’s or FPL Group’s business, as applicable, and (vii) receipt of customary tax opinions. The Merger Agreement contains certain termination rights and provides that, upon the termination of the Merger Agreement under specified circumstances, the Company will be required to pay FPL Group a termination fee of $3.25 million.
89
The foregoing description of the Merger Agreement does not purport to be complete and is qualified in its entirety by reference to the full text of the Merger Agreement, included as Exhibit 2.2 in this 10-K and incorporated herein by reference.
The Company also amended the Amended and Restated Employment Agreement, dated as of October 28, 2004, between the Company and Neil M. Leibman, the Company’s Chairman and CEO (the “Employment Agreement”), to exclude the consummation of the Merger and the other transactions contemplated by the Merger Agreement from certain payments he would otherwise be entitled to receive in the event of a change in control transaction. The foregoing description of the amendment to the Employment Agreement does not purport to be complete and is qualified in its entirety by reference to the full text of the amendment to the Employment Agreement, included as Exhibit 10.20 to this 10-K and incorporated herein by reference.
At the Effective Time, Mr. Leibman will be employed by the Company as its President, and will be compensated pursuant to a new Employment Agreement with the Company, and the Employment Agreement, as amended by the amendment to the Employment Agreement, will automatically be terminated.
Controls and Procedures
We have also recently undertaken certain changes in our disclosure controls and procedures in connection with a material weakness letter we received from our independent auditors, Hein & Associates, LLP on March 25, 2005. Further information regarding these changes is set forth herein in Item 9A. “Controls and Procedures — Changes to Disclosure Controls and Procedures.”
20. Consolidated Quarterly Data (Unaudited)
|
|
|
Fiscal 2004 |
|
|||||||||||||
|
|
|
First |
|
Second |
|
Third |
|
Fourth |
|
Total |
|
|||||
|
(In thousands, except per share data) |
|
Quarter |
|
Quarter |
|
Quarter |
|
Quarter |
|
Year |
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Sales |
|
$ |
50,513 |
|
$ |
62,025 |
|
$ |
86,781 |
|
$ |
74,575 |
|
$ |
273,894 |
|
|
Gross profit |
|
7,365 |
|
8,073 |
|
10,196 |
|
10,054 |
|
35,688 |
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Net earnings from operations |
|
2,664 |
|
2,409 |
|
2,794 |
|
3,677 |
|
11,544 |
|
|||||
|
Net earnings |
|
$ |
3,492 |
|
$ |
1,659 |
|
$ |
1,057 |
|
$ |
1,974 |
|
$ |
8,182 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Net earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Basic |
|
$ |
0.42 |
|
$ |
0.20 |
|
$ |
0.12 |
|
$ |
0.22 |
|
$ |
0.95 |
|
|
Diluted |
|
$ |
0.37 |
|
$ |
0.17 |
|
$ |
0.11 |
|
$ |
0.19 |
|
$ |
0.83 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
|
|
Fiscal 2003 |
|
|||||||||||||
|
|
|
First |
|
Second |
|
Third |
|
Fourth |
|
Total |
|
|||||
|
(In thousands, except per share data) |
|
Quarter |
|
Quarter |
|
Quarter |
|
Quarter |
|
Year |
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Sales |
|
$ |
12,920 |
|
$ |
21,448 |
|
$ |
39,644 |
|
$ |
41,131 |
|
$ |
115,143 |
|
|
Gross profit |
|
1,272 |
|
2,584 |
|
5,706 |
|
5,884 |
|
15,446 |
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Net earnings (loss) from operations |
|
(386 |
) |
(31 |
) |
2,046 |
|
1,155 |
|
2,784 |
|
|||||
|
Net earnings (loss) available to common shareholders |
|
$ |
(301 |
) |
$ |
(80 |
) |
$ |
1,007 |
|
$ |
(2,989 |
) |
$ |
(2,363 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Basic |
|
$ |
(.04 |
) |
$ |
(.01 |
) |
$ |
0.13 |
|
$ |
(0.39 |
) |
$ |
(0.31 |
) |
|
Diluted |
|
$ |
(.04 |
) |
$ |
(.01 |
) |
$ |
0.13 |
|
$ |
(0.39 |
) |
$ |
(0.31 |
) |
90
REPORT OF INDEPENDENT REGISTERED
PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders
Gexa Corp.
Houston, Texas
We have audited in accordance with auditing standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of Gexa Corp. included in this Form 10-K and have issued our report thereon dated March 25, 2005. Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The financial statement schedule listed below (Schedule II — Valuation and Qualifying Accounts) is the responsibility of the Company’s management and is presented for the purpose of complying with the Securities and Exchange Commission’s rules and is not part of the basic financial statements. The financial statement schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, is fairly stated in all material respects with the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
|
/s/ HEIN & ASSOCIATES LLP |
|
HEIN & ASSOCIATES LLP |
|
|
|
Houston, Texas |
|
March 25, 2005 |
Gexa Corp.
Schedule II - Reserves
For the Three Years Ended December 31, 2004
(In Thousands)
|
Description |
|
Balance at |
|
Charged to |
|
Deductions |
|
Balance at |
|
||||
|
|
|
|
|
|
|
|
|
|
|
||||
|
For The Year Ended December 31, 2004: |
|
|
|
|
|
|
|
|
|
||||
|
Accumulated provisions: |
|
|
|
|
|
|
|
|
|
||||
|
Allowance for doubtful accounts |
|
$ |
1,300 |
|
$ |
7,052 |
|
$ |
(5,919 |
) |
$ |
2,433 |
|
|
Reserves for severance |
|
50 |
|
54 |
|
(104 |
) |
— |
|
||||
|
For The Year Ended December 31, 2003: |
|
|
|
|
|
|
|
|
|
||||
|
Accumulated provisions: |
|
|
|
|
|
|
|
|
|
||||
|
Allowance for doubtful accounts |
|
326 |
|
3,900 |
|
(2,926 |
) |
1,300 |
|
||||
|
Reserves for severance |
|
— |
|
50 |
|
— |
|
50 |
|
||||
|
For The Year Ended December 31, 2002: |
|
|
|
|
|
|
|
|
|
||||
|
Accumulated provisions: |
|
|
|
|
|
|
|
|
|
||||
|
Allowance for doubtful accounts |
|
— |
|
679 |
|
(353 |
) |
326 |
|
||||
|
Reserves for severance |
|
— |
|
— |
|
— |
|
— |
|
||||
91
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
As of the end of the period covered by this report, we carried out an evaluation, under the supervision and the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 of the Securities and Exchange Act of 1934, as amended (the "Exchange Act"). Based on this evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures were not effective, for the reasons discussed below, in timely accumulations and communicating to our management of the information required to be disclosed by us in the reports that we file or submit under the Exchange Act.
During both the audit of our fiscal year end 2004 and 2003, our independent auditors, Hein & Associates LLP (“Hein”), issued material weakness letters noting significant deficiencies in our internal controls. The letters related to different matters.
On March 25, 2005, Hein issued a material weakness letter related to the audit of our fiscal year end 2004 identifying a deficiency in our internal controls. The deficiency identified by Hein was that we did not adequately provide information to Hein regarding a control deficiency over input of rates into our billing system and a resulting reserve accrual. In addition, Hein indicated that the Company failed to fully investigate and quantify the extent of the error caused by such control deficiency. The deficiency arose in connection with our determination of the size of our reserve for customer credits to be issued relating to errors in inputting rates on our billing system.
92
In response to the initial inquiries of Hein related to this matter, the Audit Committee of our Board of Directors, with the assistance of external counsel, conducted a review of this matter through discussions with the outside auditor, review of the applicable documents and interviews and discussions with our management. On March 25, 2005, the Audit Committee recommended an action plan related to this material weakness, which was implemented immediately, which included the following action items:
• In 2004, we created a Disclosure and Materiality Committee that includes our CEO, CFO, COO and those staff people responsible for SEC reporting and monitoring of new or amended regulations, including the employee responsible for investor relations. The committee shall be responsible for the determination that disclosure of all material information has been made in each applicable proposed public filing or furnishing of information by us pursuant to the Securities Act and the Exchange Act and that all disclosures are made on a timely basis. Our outside accountants and counsel will be invited to participate in any meeting of this committee and the timing of those meetings will be set to ensure their attendance.
• Any reserves suggested by our management for inclusion in our financial statements must be disclosed to and approved by the Audit Committee and disclosed to our outside auditors, in each case with sufficient detail to enable an understanding of the reasons for the reserve. Upon establishment of any such reserve, our management shall, in subsequent financial periods, perform the applicable investigation to confirm the need and size of such reserve, as applicable, and report those findings to the Audit Committee and outside auditors on a timely basis.
The audit committee’s report further concluded that the control deficiency related to input of rates into our billing system was corrected by the Company as of the third quarter of 2004 and, as of December 31, 2004, probably did not result in a material error to the Company’s financial statements.
93
In addition, during the audit of our fiscal year 2003, Hein issued a material weakness letter relating to our internal controls and procedures. The material weakness identified by Hein was discovered in connection with a review by Hein of the our proposed changes to our revenue calculation method. Management began the process of reviewing our revenue calculation method in November 2003. The identified deficiencies were the following:
• inadequate U.S. GAAP, financial reporting and public company expertise and experience within our accounting department; and
• inadequate quality control over the financial reporting process, including inadequate review of facts, circumstances and events impacting estimates and judgments requiring accounting recognition or disclosure.
Hein also indicated at that time that our new method for calculating our revenues required additional review and testing. Previously, we estimated revenues based on billings (the “billing” method), but the availability of accurate and timely electricity supply delivery data for the entire 2003 fiscal year allowed us to estimate revenues based on measuring electricity as delivered to our customers (the “flow” method). In the fourth quarter of 2003 and first quarter of 2004, we conducted additional testing and review of the controls and the source data being used to calculate revenues as well as the flow method of revenue calculation. Based on that review, we adopted the flow method for determining its revenues in fiscal year 2003 and thereafter.
In response to this prior material weakness letter, the Audit Committee of our Board of Directors, with the assistance of independent counsel, began an investigation of the issues raised by our auditors, including our revenue calculation methods, which process was completed in the second quarter of 2004. The Audit Committee recommended, and the Board of Directors reviewed and adopted, an action plan during the second quarter of 2004. The action plan was fully implemented as of September 30, 2004, through the following actions:
|
|
the institution of new document control procedures, including an updated disaster and recovery plan; |
|
|
|
|
|
|
• |
|
David K. Holeman’s election as Vice President and Chief Financial Officer on June 2, 2004; |
|
|
|
|
|
• |
|
the hiring of a Controller and a Manager of Financial Reporting, each with experience in SEC reporting and accounting, and a Human Resources Manager; |
|
|
|
|
|
• |
|
the creation of interim policies and procedures for the issuance of press releases and the preparation of SEC reports; |
94
• the establishment of an internal Disclosure Review Committee to review and coordinate SEC reports and prepared an interim policy regarding the notification of senior management and the Board of material developments;
• the completion of a training program for all relevant personnel regarding SEC reporting, Sarbanes-Oxley Act compliance, and related issues; and
• the selection of a provider for Sarbanes-Oxley Act Section 404 related services and to assist us in a review and assessment of our accounting policies and procedures.
We will continue to evaluate the effectiveness of internal controls and procedures on an ongoing basis. It should be noted that in designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired controlled objectives, and management necessarily was required to apply its judgment in evaluating the cost benefit relationship of possible controls and procedures.
Based on the evaluation described above and the implementation of the action plans described above, our CEO and CFO have concluded, as of March 25, 2005, that our disclosure controls and procedures are effective at reaching that level of reasonable assurance.
95
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this item will be included in a definitive proxy statement, pursuant to Regulation 14A, to be filed not later than 120 days after December 31, 2004. Such information is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item will be included in a definitive proxy statement, pursuant to Regulation 14A, to be filed not later than 120 days after December 31, 2004. Such information is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS, MANAGEMENT AND RELATED SHAREHOLDER MATTERS
The information required by this item will be included in a definitive proxy statement, pursuant to Regulation 14A, to be filed not later than 120 days after December 31, 2004. Such information is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this item will be included in a definitive proxy statement, pursuant to Regulation 14A, to be filed not later than 120 days after December 31, 2004. Such information is incorporated herein by reference.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required by this item will be included in a definitive proxy statement, pursuant to Regulation 14A, to be filed not later than 120 days after December 31, 2004. Such information is incorporated herein by reference.
96
|
Exhibit No. |
|
Description |
|
Filed Herewith or Incorporated By Reference from: |
|
|
|
|
|
|
|
2.1 |
|
Amended and Restated Agreement dated as of October 21, 2003, among the Company, Gexa Gold Corp., Robert D. McDougal, Justin Rice, Gary Rice, and Neil M. Leibman |
|
Exhibit 2.1 to Form 8-K/A, filed on December 9, 2003 |
|
|
|
|
|
|
|
*2.2 |
|
Agreement and Plan of Merger dated as of March 28, 2005, among FRM Holdings, LLC, WPRM Acquisition Subsidiary, Inc. FPL Group, Inc. and Gexa Corp. |
|
Exhibit 2.1 to Form 8-K, filed on March 28, 2005 |
|
|
|
|
|
|
|
2.3 |
|
Voting Agreement |
|
Exhibit 2.2 to Form 8-K filed on March 28, 2005 |
|
|
|
|
|
|
|
3.1 |
|
Articles of Incorporation of the Company. |
|
Exhibit 3.1 to Form 8-K/A, filed on June 21, 2001 |
|
|
|
|
|
|
|
3.2 |
|
Bylaws of the Company. |
|
Exhibit 3.2 to Form 8-K/A, filed on June 21, 2001 |
|
|
|
|
|
|
|
10.1 |
|
Credit Agreement dated July 8, 2004 among Gexa Corp., Highbridge/Zwirn Special Opportunities Fund, L.P., and the Lenders Party Hereto |
|
Exhibit 10.1 to Form 8-K, filed on July 19, 2004 |
|
|
|
|
|
|
|
10.2 |
|
Warrant Agreement by and between Gexa Corp. and Highbridge/Zwirn Special Opportunities Fund, L.P., dated as of July 8, 2004 |
|
Exhibit 4.1 to Form 8-K, filed on July 19, 2004 |
|
|
|
|
|
|
|
10.3 |
|
Form of Warrant for the Purchase of Shares of Common Stock of Gexa Corp. in favor of Neil M. Leibman, Robert C. Orr, Don Aron and Gaylor Investment Trust Partnership |
|
Exhibit 4.2 to Form 8-K, filed on July 19, 2004 |
|
|
|
|
|
|
|
10.4 |
|
Termination Agreement dated July 7, 2004 by and among Gexa Corp., The Catalyst Fund, Ltd., Southwest/Catalyst Capital, Ltd., Catalyst/Hall Growth Capital, LP, Neil M. Leibman, Robert C. Orr, Don Aron, and Gaylor Investment Trust Partnership |
|
Exhibit 10.2 to Form 8-K, filed on July 19, 2004 |
|
|
|
|
|
|
|
10.5 |
|
Lease Agreement dated April 12, 2004, between Entergy Enterprises, Inc. and the Company |
|
Exhibit 10.7 to Form 10-KSB, filed on May 18, 2004 |
|
|
|
|
|
|
|
10.6 |
|
Sublease by and between Entergy Enterprises, Inc. and Gexa Corp. |
|
Exhibit 10.1 to Form 10-Q, filed on August 11, 2004 |
|
|
|
|
|
|
|
**10.7 |
|
Energy Marketing Support Agreement dated April 8, 2003 between the Company and TXU Portfolio Management LP, as amended |
|
Exhibit 10.8 to Form 10-KSB, filed on May 18, 2004 |
|
|
|
|
|
|
|
10.8 |
|
Amended and Restated Employment Agreement dated effective as of October 28, 2004, between Neil M. Leibman and the Company |
|
Exhibit 10.2 to Form 8-K, filed on November 3, 2004 |
|
|
|
|
|
|
|
10.9 |
|
Employment Agreement by and between David K. Holeman and the Company, dated effective as of May 26, 2004 |
|
Exhibit 10.2 to Form 10-Q, filed on August 11, 2004 |
|
|
|
|
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10.10 |
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First Amendment to Employment Agreement by and between David K. Holeman and the Company, dated effective as of October 28, 2004 |
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Exhibit 10.3 to Form 8-K, filed on November 3, 2004 |
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10.11 |
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Employment Agreement by and between Rod Danielson and the Company, dated effective as of October 28, 2004 |
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Exhibit 10.4 to Form 8-K, filed on November 3, 2004 |
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10.12 |
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Employment Agreement by and between David Atiqi and the Company, dated effective as of October 28, 2004 |
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Exhibit 10.5 to Form 8-K, filed on November 3, 2004 |
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10.13 |
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Termination Agreement by and between James Burke and the Company, dated October 1, 2004 |
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Exhibit 10.1 to Form 8-K, filed on November 3, 2004 |
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10.14 |
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Amended and Restated 2004 Incentive Plan, dated effective as of May 27, 2004 |
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Exhibit 10.7 to Form 8-K, filed on November 3, 2004 |
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10.15 |
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Gexa Corp. 2002 Non Employee Director Stock Option Plan |
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Exhibit 4.1 to Form S-8, Registration No. 333 116722, filed on June 22, 2004 |
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10.16 |
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Form of Securities Purchase Agreement dated as of November 23, 2004 by and among Gexa Corp., the Selling Shareholder and the Investor in connection with the Private Placement |
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Exhibit 10.1 to Form 8-K, filed on November 24, 2004 |
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10.17 |
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Warrant Agreement by and between Gexa Corp. and Cappello Capital Corp., dated as of November 1, 2004 |
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Exhibit 4.1 to Form 8-K, filed on December 6, 2004 |
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10.18 |
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Promissory Note between Gexa Corp. and Cappello Capital Corp. dated November 29, 2004 |
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Exhibit 10.1 to Form 8-K, filed on December 6, 2004 |
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10.19 |
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Form of Indemnification Agreement between the Company and each of its directors and certain officers |
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Exhibit 10.1 to Form 8-K, filed on January 31, 2005 |
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10.20 |
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Amendment to Amended and Restated Employment Agreement dated as of March 28, 2005, between Gexa Corp. and Neil M. Leibman |
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Exhibit 10.1 to Form 8-K, filed on March 28, 2005 |
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21.1 |
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Subsidiaries of Registrant |
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Filed herewith |
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23.1 |
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Consent of Hein & Associates LLP |
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Filed herewith |
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31.1 |
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Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Exchange Act pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
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Filed herewith |
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31.2 |
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Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Exchange Act pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
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Filed herewith |
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32.1 |
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Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
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Filed herewith |
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32.2 |
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Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
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Filed herewith |
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* |
Schedules and similar attachments to the Agreement and Plan of Merger have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The Registrant will furnish supplementally a copy of any omitted schedule or similar attachment to the Securities and Exchange Commission upon request. |
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** |
The Company has omitted certain portions of this agreement in reliance on Rule 24b-2 under the Securities Exchange Act of 1934, as amended. |
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Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on March 31, 2005.
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GEXA CORP. |
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By: |
/s/ Neil M. Leibman |
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Neil M. Leibman |
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Chairman
of the Board and |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
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Signatures |
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Title |
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Date |
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/s/ Neil M. Leibman |
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Chairman and Chief Executive Officer |
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March 31, 2005 |
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Neil M. Leibman |
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(principal executive officer) |
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/s/ David K. Holeman |
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Chief Financial Officer |
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March 31, 2005 |
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David K. Holeman |
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(principal accounting officer) |
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/s/ Stuart C. Gaylor |
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Director |
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March 31, 2005 |
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Stuart C. Gaylor |
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/s/ Don S. Aron |
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Director |
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March 31, 2005 |
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Don S. Aron |
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Director |
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March 31, 2005 |
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Dan C. Fogarty |
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/s/ Robert C. Orr, Jr. |
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Director |
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March 31, 2005 |
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Robert C. Orr, Jr. |
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/s/ Tom D. O’Leary |
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Director |
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March 31, 2005 |
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Tom D. O’Leary |
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100