10-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)
x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended June 30, 2008
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from           to

Commission File Number 333-138425

MXenergy Holdings Inc.

(Exact Name of Registrant as Specified in Its Charter)

Delaware	20-2930908
(State or Other Jurisdiction of	(I.R.S. Employer Identification No.)
Incorporation or Organization)
595 Summer Street, Suite 300
Stamford, Connecticut	06901
(Address of Principal Executive Offices)	(Zip Code)

(203) 356-1318

(Registrant’s telephone number, including area code)

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

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

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x   No o

Indicate by check mark 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, 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. x

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

Large accelerated filer	o		Accelerated filer o
Non-accelerated filer	x	(Do not check if a smaller reporting company)	Smaller reporting company o

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

Aggregate market value of voting and non-voting common equity held by non-affiliates of the registrant:  Not applicable.  The registrant has no publicly traded equity securities.

As of August 31, 2008, there were 3,604,788 shares of the Registrant’s common stock, par value $0.01 per share, outstanding.

Documents incorporated by reference: None

MXENERGY HOLDINGS INC.

ANNUAL REPORT ON FORM 10-K

FOR THE FISCAL YEAR ENDED JUNE 30, 2008

TABLE OF CONTENTS

Item Number		Page Number
	PART I
1.	Business	4
1A.	Risk Factors	18
1B.	Unresolved Staff Comments	27
2.	Properties	27
3.	Legal Proceedings	27
4.	Submission of Matters to a Vote of Security Holders	27
	PART II
5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	28
6.	Selected Financial Data	29
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	34
7A.	Quantitative and Qualitative Disclosures about Market Risk	56
8.	Financial Statements and Supplementary Data	58
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	104
9A.	Controls and Procedures	104
9B.	Other Information	106
	PART III
10.	Directors, Executive Officers and Corporate Governance	107
11.	Executive Compensation	111
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholders Matters	128
13.	Certain Relationships and Related Transactions, and Director Independence	130
14.	Principal Accountant Fees and Services	132
	PART IV
15.	Exhibits and Financial Statement Schedules	133
	SIGNATURES	134

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Some statements in this Annual Report on Form 10-K, or Annual Report are known as “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 (the “Exchange Act”). Forward-looking statements may relate to, among other things:

·future performance generally;

·our business goals, strategy, plans, objectives and intentions;

·our post-acquisition integration of acquired businesses;

·expectations concerning future operations, revenues, gross profit, profitability, attrition, bad debt, interest rates, liquidity and capital resources; and

·expectations regarding the effectiveness of our hedging practices and the performance of suppliers, pipelines and transmission companies, storage operators, independent system operators, financial hedge providers, banks providing working capital and other counterparties supplying, transporting, and storing physical commodity.

These forward-looking statements include, but are not limited to, statements about our plans, objectives, expectations and intentions and other statements contained in this Annual Report that are not historical facts.  When used in this Annual Report, the words “expects,” “anticipates,” “intends,” “plans,” “believes,” “seeks,” “estimates” and similar expressions are generally intended to identify forward-looking statements. Because these forward-looking statements involve known and unknown risks and uncertainties, there are important factors that could cause actual results, events or developments to differ materially from those expressed or implied by these forward-looking statements, including our plans, objectives, expectations and intentions and other factors as set forth in “Item 1A. Risk Factors” and elsewhere in this Annual Report.  You should not place undue reliance on such forward-looking statements, which are based on the information currently available to us and speak only as of the date on which this Annual Report was filed with the Securities and Exchange Commission (“SEC”).  We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

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PART I.

ITEM 1.  BUSINESS

Definitions

References in this Annual Report on Form 10-K (“Annual Report”) to “Holdings” refer to MXenergy Holdings Inc., a Delaware corporation.  References to “the Company,” “we,” “us,” “our,” or similar terms refer to Holdings together with its consolidated subsidiaries.

References to “MMBtu” refer to a million British thermal units, a standard unit of heating equivalent measure for natural gas. A unit of heat equal to 1,000,000 Btus, or 1 MMBtu, is the thermal equivalent of approximately 1,000 cubic feet of natural gas. One billion cubic feet, or BCF, of gas is slightly less than 1,000,000 MMBtus.

References to “MWhr” refer to a million watt hours or a thousand kilowatt hours, which is the amount of electric energy produced or consumed in a period of time.

References to “RCEs” refer to residential customer equivalents, each of which represents a natural gas customer with a standard consumption of 100 MMBtus per year or an electricity customer with a standard consumption of 10 MWhrs per year. These quantities, which are used for convenience, represent the approximate amount of natural gas or power used by a typical household in some parts of the country.

References to “LDC” refer to a local distribution company, or utility, that provides the distribution infrastructure to supply natural gas and electricity to our customers.  In some cases LDCs also provide billing services and guarantee customer accounts receivable within various markets that we serve.

References to “customers” refer to individual accounts served by us.  An individual or business with multiple accounts will be counted multiple times in our tabulation of customers.  An individual or business may be counted as a single customer despite having multiple meters in a single location.  Prospective customers that have initiated new service from us are not included in our customer portfolio until we have completed all required processing steps, including credit verification and sharing of appropriate information with the respective LDC. Customers that have initiated the process for termination of their service are included in our customer portfolio until the termination has been properly processed and coordinated with the LDC.

Our Company Overview and History

The Company was founded in April 1999, and Holdings was incorporated in the state of Delaware in 2005 as part of a corporate reorganization.  Headquartered in Stamford, Connecticut, we are an independent energy provider of retail natural gas and electric power to residential and commercial customers in deregulated markets in the U.S. and Canada.  We are one of a small number of successful retail energy marketers in the growing deregulated market.  We currently serve natural gas and electricity customers located in 39 market areas across 14 states in the United States (the “U.S.”) and in the provinces of Ontario and British Columbia in Canada.

The following map reflects the states in the U.S. and the Canadian provinces where we have natural gas and electricity customers.

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Our Business Segments and Operations

Our core business is the retail sale of natural gas and electricity to end-use customers in deregulated markets.  Accordingly, our business is classified into two reportable business segments: natural gas and electricity.  Through these business units, natural gas and electricity are generally sold at contracted prices based on usage by customers. We buy natural gas and electricity in the wholesale market in time and location specific, bulk or block quantities at fixed and indexed prices.  We sell at variable or market-based prices that, in most cases, change monthly or at fixed prices for a forward term that generally does not exceed three years.  In the case of variable sales contracts as well as most mid-market commercial sales, we purchase natural gas or electricity at the time of sale.  In the case of fixed price retail customers, we purchase natural gas and electricity in advance of sales.  Costs are marked up with a reasonable profit margin.  For fixed price sales contracts, the cost of commodity and ancillary services is hedged in the forward markets with financial swaps and physical forward contracts that settle monthly.  The natural gas and electricity is then purchased at the time such swaps and forward contracts settle.  We regularly calculate the amount of commodity required to meet our expected customer deliveries and balance this against the quantity hedged or purchased for such customers.  Differences between expected customer deliveries and commodity purchases are managed by adjusting natural gas deliveries from storage and buying any shortfall or selling any excess in the spot market.

The positive difference between the sales price of natural gas or electricity provided to customers and the sum of the wholesale cost of commodity supplies, hedging costs, transmission costs and ancillary services costs results in gross profit.  The natural gas and electricity sold is metered and delivered to customers by the LDCs.  Except in our Georgia natural gas and Texas electricity markets and for certain of our commercial customers, the local utilities generally provide billing and collection services on our behalf for residential and small commercial customers.  During fiscal year 2008, approximately 44% of our total sales of natural gas and electricity was within markets where LDCs guarantee customer accounts receivable.  In the case of our Georgia and Texas retail markets, we bill

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and collect directly from customers the price of delivered commodity plus the charges associated with the local utility’s distribution costs, the latter of which is remitted to such utility.  In these two markets, as well as in the case of the commercial customers that we bill directly, customer accounts receivable are not guaranteed by the utility.  However, credit checks or other evidence of ability to pay is required for our customers, and we have the right to cause the utility to shut-off service in the event of non-payment.  As a result, we have experienced low bad debt levels.

Sales of natural gas and electricity are summarized in the following table.  The sales amounts in the table are intended to provide an indication of operational growth within the segments, and are not necessarily indicative of similar growth in gross profit or net income.  Refer to “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” located elsewhere in this Annual Report for commentary regarding gross profit and other components of net income.

	Fiscal Year Ended June 30,
	2008			2007			2006
	Sales		% of Total	Sales		% of Total	Sales		% of Total
	($ in thousands)
Natural gas	$	669,522	89	$	680,811	97	$	345,629	95
Electricity	82,761		11	23,115		3	16,932		5
Total sales	$	752,283	100	$	703,926	100	$	362,561	100

Natural gas sales decreased approximately 2% for the fiscal year ended June 30, 2008, as compared with the prior fiscal year, due primarily to:

·customer attrition, which was partially offset by new customer growth; and

·warmer-than-normal weather in Georgia, which is our largest natural gas market.

These factors were partially offset by a generally higher selling price per natural gas MMBtus sold.

Growing electricity sales over the past three fiscal years resulted primarily from:

·higher volumes of electricity MWhrs sold resulting from strong organic growth in electricity RCEs, especially during the fiscal year ended June 30, 2008; and

·incremental volume of MWhrs sold resulting from operations acquired from Vantage Power Services, L.P. (“Vantage”) in May 2007.

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Recent Developments and Trends

Customer Growth from Direct Marketing Initiatives

As a result of organic growth and strategic acquisitions, we have benefited from a robust increase in average RCEs, which have grown at a compound annual growth rate (“CAGR”) of 32% since 2002.  The following graph illustrates the growth in our average annual RCE count from 2004 through 2008.

While a portion of our customer growth in recent years is attributable to customers added through acquisitions, the majority of our customers at June 30, 2008 have been added through organic growth.  We have focused on the development of an experienced marketing and sales team, multiple marketing channels, and strong customer care and customer operations teams to support this growth.  Our experienced pricing team also works closely with sales and marketing to quickly react to market changes and to provide products to prospective customers that help manage energy price volatility.

Most of our current customers have been acquired organically through door-to-door, telemarketing, direct mail, event and internet sales channels.  We are currently expanding our marketing channels to include multi-level network marketing.  While customer attrition is a natural part of our business, the marketing and customer care teams have focused efforts on customer retention via superior customer service and win back and loyalty initiatives.

We are focused on growing our customer base while controlling customer acquisition costs.  Our objective has been to maintain customer acquisition costs below 12 months of gross profit resulting in a pay back period of less than one year.

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GasKey Acquisition

On January 22, 2008, we completed the acquisition of substantially all of the retail natural gas assets of PS Energy Group, Inc., primarily including the natural gas customer contracts of their GasKey division (the “GasKey Acquisition”).  Nearly all of the customers served under such contracts are located in Georgia.  We acquired approximately 60,000 RCEs in the Gaskey Acquisition.  Consistent with our experience with previous acquisitions, we expect attrition for this portfolio to be higher than our normal attrition.  The majority of accounts acquired are commercial and industrial customers for which we expect to earn gross profit that is lower than that for our traditional mass-market business.

Pursuant to the terms of the related Asset Purchase Agreement, we purchased the GasKey net assets for a base amount of approximately $4.3 million, plus working capital, plus contingent consideration payable for volumes consumed on customer contracts acquired for a 36-month period subsequent to the acquisition date.  Total operating cash outlay for the GasKey Acquisition was approximately $12.0 million.  The final purchase price was subject to certain adjustments in accordance with the terms and conditions of such Asset Purchase Agreement.  We also assumed certain liabilities related to the GasKey assets.

Regulatory approval for the GasKey Acquisition was received in January 2008.  We recorded the transaction as a purchase business combination as of January 1, 2008.  The total purchase price was paid from our available cash balance.  The assets acquired and related operations represent less than 10% of our consolidated assets and operations.

Operating Platform Enhancements

We have invested substantial resources over the past two fiscal years to build a strong, scalable operating platform, including enhancement of our corporate finance, billing, accounting, customer service, information technology, marketing and supply functions to support past and future business growth.  We have increased our staff headcount and have made other investments to enhance our overall internal control environment, particularly in information technology, customer operations, accounting and financial reporting controls, with the object of becoming compliant with the requirements of the Sarbanes-Oxley Act of 2002 by June 30, 2008.  During this time period, our information technology investment included the integration of one of our legacy information systems onto information systems acquired from Shell Energy Services Company L.L.C. (“SESCo”).

Purchases of Floating Rate Senior Notes due 2011

During the fiscal year ended June 30, 2008, we utilized cash and cash equivalents to acquire $12.0 million aggregate principal amount of our outstanding Floating Rate Senior Notes due 2011 (the “Senior Notes”) from bondholders, in each case, for an amount less than face value.  These transactions resulted in $0.8 million of aggregate gains on the early extinguishment of debt that were recorded as a reduction of interest expense for the fiscal year ended June 30, 2008.  We also recorded as additional interest expense $0.5 million of original issue discount and debt issuance costs for the fiscal year ended June 30, 2008, which represents a pro rata portion of such costs that were deferred at the issuance date of the Senior Notes.

Amendments to and Extension of our Hedge Facility

Although we engage in hedging activities with various counterparties for electricity, our natural gas business utilizes a structured hedge facility as our primary natural gas hedge facility (the “Hedge Facility”).  Under the Hedge Facility, we utilize New York Mercantile Exchange (“NYMEX”) referenced over-the-counter swaps, basis price swaps and options to hedge the risk of variability in the cost of natural gas.  The Hedge Facility was originally entered into on August 1, 2006 and had an initial term of two years with subsequent one-year renewal terms.  In July 2008, the term of the Hedge Facility was extended to the earlier of August 1, 2009 or 30 days prior to expiration of the Revolving Credit Facility. As a result of extension of the Revolving Credit Facility to July 31, 2009 (see below) the Hedge Facility is currently due to expire on July 1, 2009.

The Hedge Facility provides the Company with the ability to enter into NYMEX and basis swaps for a tenor of up to 39 months. The fees incurred under the Hedge Facility include an annual management fee, a volumetric fee based on the tenor of the swap and other fees, which allow the hedge provider to mitigate the potential risks arising from material declines of natural gas market prices based on the Company’s overall hedge position with the provider.

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The Hedge Facility is secured by a first lien on all customer contracts and a second lien on substantially all other assets of the Company.  The Company posted an initial balance of $25.0 million in cash collateral for potential negative mark-to-market changes in the value of the forward hedge position.  The Company has the flexibility to post either cash collateral or issue a letter of credit as margin for the Hedge Facility.  As of June 30, 2008, the Company posted a $25.0 million letter of credit as margin.

The agreement governing the Hedge Facility was amended in March 2008 and July 2008.  These amendments are described in “Liquidity and Capital Resources” under “Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Amendments to and Extension of our Revolving Credit Facility

We utilize a revolving credit facility with a syndicate of banks (the “Revolving Credit Facility”) primarily to post letters of credit required to effectively operate within the markets that we serve.  As of June 30, 2008, MXenergy Inc. and MXenergy Electric Inc., as borrowers under the Revolving Credit Facility, were permitted to borrow up to the lesser of: (1) $280.0 million; or (2) the amount of the then applicable borrowing base.  The expiration date of our Revolving Credit Facility was December 19, 2008, at which time any outstanding principal amounts would have become due.  Borrowings under our Revolving Credit Facility bore interest at a fluctuating rate based upon a base rate or a Eurodollar rate plus an applicable margin.  As of June 30, 2008, the applicable margin for base rate loans was 1.00% per annum and the applicable margin for Eurodollar loans was 2.00% per annum.  As of June 30, 2008, the fees associated with issuing letters of credit under the Revolving Credit Facility were 1.75% per annum.

At June 30, 2008, the total availability under the Revolving Credit Facility was $193.9 million, of which $147.9 million was utilized in the form of outstanding letters of credit.  We did not draw any borrowings under our Revolving Credit Facility during the fiscal year ended June 30, 2008, and there were no cash borrowings under the Revolving Credit Facility at June 30, 2008.

On September 30, 2008, the agreement that governs the Revolving Credit Facility was amended and restated to, among other things, reduce the total availability under the Revolving Credit Facility to $255.0 million in the term of the agreement through July 31, 2009.  The agreement governing the Revolving Credit Facility was also amended in December 2007 and March 2008, which amendments are described in greater detail under the caption “Liquidity and Capital Resources” in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Our Core Products and Services

We provide customers with a choice of natural gas and electricity products with alternative price structures that are designed to manage the risks of energy volatility.  The two basic alternative price structures are variable market-based pricing and fixed price forward contracts. Pricing and terms for these products are developed so that at any given time, potential customers can choose the product to meet their household or business needs.   We attempt to be flexible and to respond quickly to market conditions to ensure that our products match consumer interests.  Unlike competitors offering one product choice at a time, we simultaneously provide multiple product offerings.  We also attempt to keep our product offerings simple in order to facilitate marketing to residential and small commercial customers.

We market variations of two basic products:

·Fixed price contracts – Generally with terms of up to three years for natural gas and electricity, fixed rate products provide consumers with price protection against fluctuations in natural gas and electricity prices.  The fixed rate product protects consumers from increases in the unit price of natural gas or electricity.  In marketing this product, we do not promise savings as a consumer could pay more if prices offered by a local utility or other competitor, which are based on variable market conditions, fall during the term of the fixed rate contract.  We offer customers different variations on the fixed rate product.  For example, customers may wish to have fixed rate protection only for the winter months while letting the summer price float with the market.  We have also offered some customers a cap product in which their price floats with the market but cannot exceed a fixed rate cap.

As of June 30, 2008, approximately 51% of our natural gas customer portfolio had fixed rate contracts while the remaining 49% had variable rate contracts.  We have a risk management policy that is intended to reduce our financial exposure related to changes in the price of natural gas and electricity.  Under this policy, we hedge a

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minimum of 100% of the anticipated natural gas commodity purchases required to meet expected customer demand for all accounts served under fixed price contracts.  We also have a natural gas hedging facility that limits our exposure to mark-to-market margin payments.  As of June 30, 2008, contracts with our fixed price natural gas customers have an average remaining life of approximately 12 months.

As of June 30, 2008, approximately 31% of our electricity customer portfolio had fixed rate contracts while the remaining 69% had variable rate contracts.  We hedge 100% of anticipated electricity commodity purchases required to meet expected customer demand for accounts served under fixed rate contracts.

·Variable price contracts – Variable price products generally are priced competitively with the price offered by the region’s incumbent utility or other local competitors (the “price to compare”, or “PTC”).  Our variable rate product is similar to utility variable rate pricing. By using alternative supply arrangements, we are sometimes able to supply customers with the commodity at a price lower than the utility’s tariff pricing due to the utility’s prior period cost recovery charges or fixed term transportation costs.  We do not guarantee to customers that our price will be below the PTC.

We generally do not hedge to protect against price volatility associated with variable rate natural gas contracts because our variable price is set ahead of the month of commodity flow, which ensures a direct correlation between our cost for commodity delivered and the price charged to the customer.

For electricity, our variable prices are set prior to the beginning of the month of commodity flow.  We purchase commodity for delivery based on our expected customer usage for that month.  Any difference between actual consumption and our purchased commodity volume results in pricing risk for the month.

Our Markets and Customers

Geographic Concentrations

RCEs by geographic area are summarized in the following table.

	RCEs at June 30,
	2008			2007
	No.	% of Total		No.	% of Total
Southern U.S (Georgia, Texas, Florida):
Natural gas	241,000			209,000
Electricity	25,000			12,000
	266,000	38	%	221,000	35	%
Northeastern U.S., Mid-Atlantic U.S. and Canada (New York, New Jersey, Connecticut, Massachusetts, Pennsylvania, Maryland, Ontario, British Columbia):
Natural gas	156,000			139,000
Electricity	73,000			31,000
	229,000	29	%	170,000	38	%
Midwestern U.S. (Ohio, Michigan, Indiana, Illinois, Kentucky):
Natural gas	205,000			240,000
Electricity	—			—
	205,000	33	%	240,000	27	%
Total RCEs:
Natural gas	602,000			588,000
Electricity	98,000			43,000
	700,000	100	%	631,000	100	%

Our customer base consists of residential, small and mid-market commercial customers.  We have limited exposure to high concentrations of sales volumes to individual customers.  For the fiscal years ended June 30, 2008 and 2007, our largest customer accounted for approximately 2% of total sales volume.

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Our diversified geographical coverage provides several benefits to us, including flexibility in product offerings and marketing campaigns, broad demographic mix, diversified credit and regulatory exposure.  Our multi-state approach allows us to:

·benefit from a diverse geographic stream of sales;

·mitigate the delivery risk associated with daily balancing gas markets;

·mitigate the risk of a single LDC default;

·mitigate the risk of material impact from a regulatory change in a single jurisdiction;

·mitigate the risk of extreme local weather patterns;

·mitigate the risk of material impact from localized economic downturn;

·optimize inventory management opportunities across a diverse natural gas transportation and storage infrastructure; and

·capitalize on our regional supply and pricing knowledge.

The following significant market activity and trends impacted our operations during the fiscal year ended June 30, 2008:

Southern U.S. markets – Total RCEs in our Georgia natural gas market grew approximately 17% during the fiscal year ended June 30, 2008.  Effective January 1, 2008, our acquisition of the GasKey division of PS Energy Group, Inc. initially added approximately 60,000 RCEs to our natural gas customer portfolio in Georgia.  The impact of the GasKey Acquisition was partially offset by normal attrition within the customer portfolio, which in turn was offset to some extent by new customers.

RCEs in our Texas electricity market increased 125% during the fiscal year ended June 30, 2008.   In May 2007, we acquired the assets of Vantage (the “Vantage Acquisition”) and began to serve approximately 12,000 RCEs in Texas shortly thereafter.  RCEs in Texas grew organically throughout the year, primarily due to the recent success of expanded direct marketing activities.

Northeastern U.S., Mid-Atlantic U.S. and Canadian markets – Total RCEs within these geographic regions grew approximately 34% during the fiscal year ended June 30, 2008.  The main driver of higher RCEs in this region was significant organic electricity customer growth, which was largely due to targeted direct sales marketing activities and a wider range of product offerings to customers, particularly in our Massachusetts, Connecticut and New York electricity market areas.  During April 2007, we obtained our electricity marketer license to sell electricity in the State of Connecticut, and began delivering electricity to customers in Connecticut in July 2007.

Midwestern U.S. markets – Total RCEs in this geographic region decreased approximately 15% during the fiscal year ended June 30, 2008.  Customer attrition within this region outpaced new customer growth, as we focused our marketing efforts in other markets with more favorable pricing opportunities.

We have taken a conservative approach in entering new deregulated electricity markets since we entered our first market in New York in 2004.  There are currently 19 states that are open for direct access sales to end use customers of electricity.  We are evaluating each market to determine which present the best opportunities for entry.  Our intent is to develop this business organically and through acquisitions, as well as by leveraging potential cross-selling opportunities with our natural gas business.  We believe offering both natural gas and electricity to the same customer leverages our existing infrastructure and decreases customer turnover.

For fiscal year 2009 and subsequent years, we will continue to consider expansion of our distribution of natural gas and electricity within our existing markets as well as expansion into new LDC markets by leveraging our customer care and operations platform, our information technology infrastructure and our multi-channel marketing system.   The decision to enter into new LDC markets will continue to be governed by several factors, including:

·compatibility with our existing operating systems and supply base;

·availability of utility billing and guarantees of customer accounts receivable;

·market location and size; and

·the ability to provide value to customers.

We continuously assess conditions in market areas that we currently serve, as well as new markets where we are not currently licensed.  In certain markets, we are monitoring the competitive conditions resulting from the actions of LDCs and local retail marketers.  In addition, we are currently studying pending regulatory or legislative actions that could create favorable conditions for us to enter new markets.  In September 2008, we received our certificate of qualification to conduct business in the State of California.

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Attracting and Retaining Customers

Acquiring New Customers

To acquire new customers, we employ an integrated marketing approach that consists of multiple combinations of direct marketing, traditional and online media, public relations and local event participation. The goal is to have direct marketing efforts, which include outbound telemarketing to both residential and small commercial customers, direct sales (outside sales focusing on small and mid-market commercial customers), and direct mail targeted to high purchase propensity residential and small commercial customers, all of which combined account for the majority of our total tactical marketing mix.

Over the course of the final three quarters of fiscal 2008, we began to experience higher levels of organic customer additions as a result of the re-introduction of the door-to-door marketing channel implemented during the last quarter of fiscal 2007.  In addition, we are introducing a new network marketing channel after entering into an exclusive arrangement with Zurvita Inc.

We continue to market to the mass-market residential and small commercial customers using direct mail, internet, telemarketing and door-to-door programs.  In addition, we market through outside sales agents to mid-market commercial customers. New products, such as the “ENERGY STAR Rebate Program” and “You Save or We Pay Program”, have been recently introduced and other products have been offered from time to time as well.  We have improved our ability to rapidly capitalize on new opportunities created by price changes of utilities and competitors and by changes in the structure of forward markets.

Retaining and Winning Back Customers

To retain existing customers, we rely on a team of highly trained internal and external customer care representatives.  Customers requesting cancellation of service are provided information on the volatility of natural gas rates and encouraged to retain the benefits of long-term rate protection, if appropriate.  If we receive notification from an LDC that a customer has cancelled or switched to another supplier, attempts to communicate are made through both mail and phone, encouraging the customer to reconsider his or her decision, reminding the customer of penalties he or she may incur and, in some cases, offering a new rate plan.

Customer Renewals and Attrition

In-contract customer attrition is defined as: (1) the loss of fixed rate customers before their contract term officially ends; and (2) the loss of variable rate customers, whose contracts generally do not have expiration dates, at any time.  Such attrition usually occurs due to customers moving from their homes or businesses, deteriorated creditworthiness, or customers switching to another choice provider or returning to service from the incumbent utility.  Average annualized in-contract customer attrition was approximately 19.7%, 25.6% and 20.8% for the fiscal years ended June 30, 2008, 2007 and 2006, respectively.  Over that period, we experienced an average annual in-contract customer attrition rate of approximately 22.0%, which we believe is consistent with the industry average.

At the end of each customer contract term, customer contracts in most of our markets are renewed upon notification by the marketers unless the customer indicates otherwise.  During the fiscal year ended June 30, 2008, approximately 88% of our customers that received such notification ultimately continued their relationship with us (excluding the impact of a large municipal aggregation of customers that did not renew its contract with us at the end of its contract term due to regulatory changes in our Ohio market).  During the three year period from July 1, 2005 through June 30, 2008, approximately 89% of our customers that received such notification of contract continued their relationship with us (excluding the impact of the municipal aggregation customers noted above).  At June 30, 2008, we did not supply natural gas to customers under any municipal aggregation arrangements.

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Attrition data is calculated based upon actual customer level data.  For analytical purposes, we assume that one RCE represents a natural gas customer with a standard consumption of 100 MMBtus per year, or an electricity customer with a standard consumption of 10 MWhrs per year.  However, each customer does not actually consume 100 MMBtus of natural gas or 10 MWhrs of electricity.  For example, one of our mid-market commercial customers may consume the equivalent of several hundred or even thousands of RCEs.  Therefore, a decline in RCEs may not be directly correlated with, or attributable to, actual customer attrition.

Acquisitions

In addition to organic growth, we have historically followed a disciplined acquisition strategy, acquiring only businesses that meet certain criteria, including the following:

·the acquired operations must be consistent with our business objectives to build a profitable retail business;

·the customers of the acquired company must have been acquired by such company in a manner consistent with our marketing principles and values and in accordance with applicable laws and regulations;

·the operations of the acquired company can be integrated with existing internal systems and processes;

·the acquired customers are located in markets that facilitate risk management through transparent pricing, liquid instruments, and diversity of credit-worthy suppliers; and

·the acquisition can be comfortably supported by our financing capabilities.

Some of the companies we acquired are located in markets not previously served by us and therefore, provided us with new strategic marketing opportunities.  We intend to continue this strategy when evaluating new acquisition opportunities.  Since 1999, we have completed the following acquisitions:

Date	Company / Business Acquired	Number and Type of RCEs
May 2000	Keyspan Energy	18,000 natural gas
March 2001	Summit Energy	15,000 natural gas
September 2001	Energy.com	5,000 natural gas
February 2003	Nicor Gas	28,000 natural gas
March 2004	Total Gas & Electric, Inc.	90,000 natural gas
		13,000 electricity
November 2005	Castle Power LLC	53,000 natural gas
August 2006	Shell Energy Services Company L.L.C.	315,000 natural gas
May 2007	Vantage Power Services L.P.	12,000 electricity
January 2008	GasKey division of PS Energy Group, Inc.	60,000 natural gas

In October 2008, we received regulatory and bankruptcy court approval and entered into an agreement to purchase liquefied natural gas inventory from an insolvent Georgia-based retail gas company.  In connection therewith, the related portfolio of natural gas customers was transferred to the Company at no cost.  The total purchase price for the inventory was approximately $1.5 million.  The purchase agreement also includes transition fees of approximately $0.5 million, which will be expensed as incurred.  This acquisition is not expected to have a material impact on our financial position or results of operations for the fiscal year ended June 30, 2009.

Market Deregulation and Competition

In markets that are open to competitive choice of retail energy suppliers, our primary competition comes from utility-affiliated retail marketers and small to mid-size independent retail energy companies. Competition is based primarily on product offering, price and customer service.

Increasing our market share depends in part on our ability to convince customers to switch to our service.  The local utilities and their affiliates 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, local utilities have been subject to many years of regulatory oversight and thus have significant 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.  The incumbents’ advantages in many markets are intended to be limited, however, by regulatory structures that, for example, prohibit incumbents from offering non-standard service and pricing structures, minimize the opportunity for the regulated business to subsidize the unregulated business and limit the ability of the utilities to solicit customers that have switched.  In Georgia and Texas, however, the market is fully deregulated where the incumbent utilities no longer use a regulated benchmark price or PTC.

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In many cases, LDCs actively support deregulation and have welcomed the entry of retail energy marketers.  Historically, regulated LDCs did not profit from commodity supplied to customers; rather, their rate of return was based on their hard assets or “rate base.” Accordingly, LDCs charged consumers for commodity on a pass-through basis, and did not hedge their forward energy costs.  By relieving LDCs of the need to engage in risk management, regulations permitting retail competition allows LDCs to focus on their core competency of local distribution, which typically constitutes a significant portion of most customers’ utility bills.  Many LDCs assume customer bad debt exposure since this encourages more market entrants and supports continued deregulation. LDCs may recover the bad debt expense as part of their tariff rates.  The interests of retail energy marketers and most LDCs are thus highly aligned, providing crucial support for continued deregulation, while increasing penetration of the retail energy marketer model.  We have successfully forged strong relationships with many of the LDCs throughout our service territories.

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

Deregulated Natural Gas Industry

The Natural Gas Policy Act of 1978 took the first steps toward deregulating the natural gas market by instituting a scheme for the gradual removal of price ceilings at the wellhead.  In 1985, the Federal Energy Regulatory Commission (“FERC”) issued Order 436, which changed how interstate pipelines were regulated.  Essentially, this order allowed pipelines, on a voluntary basis, to offer transportation services to customers who requested them on a first-come, first-serve basis.  The movement towards allowing pipeline customers a choice in the purchase of their natural gas and transportation arrangements became known as “open access,” and spurred the emergence of natural gas marketers.

While large commercial and industrial consumers have had the option of purchasing the natural gas commodity separately from natural gas suppliers for many years, state regulators and law makers have moved more slowly in implementing choice programs for residential and small-volume commercial customers.

According to the Energy Information Agency (“EIA”), twenty-one states and the District of Columbia have legislation or programs in place that let residential consumers and other small-volume users purchase natural gas from someone other than their traditional utility company.  As of December 31, 2007, there were approximately 91 licensed natural gas marketers serving customers in deregulated states throughout the country.  According to the EIA, nearly 35 million of the approximately 65 million total residential gas customers in the U.S. have access to choice programs, with approximately 4.6 million (or 13% of eligible customers) purchasing from residential marketers. State regulators continue to refine and evaluate existing programs in order to promote a competitive marketplace.  The low penetration rate, coupled with the desire for a competitive marketplace, has created attractive growth opportunities for residential marketers such as us.

An LDC located in the state of New York that currently does not guarantee customer accounts receivable began to guarantee such receivables, on a marketer-by-marketer basis, effective in October 2008.  This action will improve the collectability of customer accounts receivable in this market, thereby making growth in this market more attractive.

Deregulated Electricity Industry

In 1978, Congress passed the Public Utility Regulatory Policies Act which laid the groundwork for deregulation and competition by opening wholesale power markets to non-utility producers of electricity.  In 1996, FERC Orders 888 and 889 required open and equal access to jurisdictional utilities’ transmission lines for all electricity producers, thus facilitating the states’ restructuring of the electric power industry by allowing customers direct access to retail power generation.

As a result of federal and state initiatives, the electric power industry in several states has changed from a structure characterized by highly regulated, vertically integrated local monopolies, which provide their customers with a comprehensive package of electricity services, to a deregulated structure.  The deregulated structure includes independent power producers and unregulated owners of electricity generation, competitive providers like us who supply electricity to end-use customers, and utilities that continue to provide transmission or distribution services as common carriers.  At least 16 states (Connecticut, Delaware, Illinois, Maine, Maryland, Massachusetts, Michigan, New Hampshire, New Jersey, New York, Ohio, Oregon, Pennsylvania, Rhode Island, Texas and Virginia) and the District of Columbia have deregulated electricity.

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Recent legislation in Massachusetts is requiring all electricity LDCs to guarantee the accounts receivable of retail suppliers.  If enacted, this legislation would improve the collectibility of accounts receivable in our existing electricity markets in Massachusetts and make entry into new markets within the state more attractive.

Competition

Since the mid-1980s, more than 250 marketers of natural gas have emerged.  However, most of these companies have confined their activities to wholesale trading and marketing to large industrial and commercial buyers of gas and power.  In 2001, approximately 160 marketers nationwide were actively marketing to retail customers of natural gas.  Today, the number is approximately 91 due to consolidation within the industry.  Moreover, the commitment of many of these marketers is often modest, confined to a limited geographic region, and represented by limited capital, personnel and operational support.

We focus on markets that are less susceptible to competitive pressures on profit margins and that lend themselves to mass market techniques.  At the time our company was formed in 1999, as many as 12 to 15 marketers competed in each of its current market areas.  Today only 5 to 10 competitive marketers sell to retail customers.

Marketers competing for the commercial and residential markets fall into three categories:  utility affiliates, national marketers and niche marketers.  We consider our main competitors in natural gas to be Direct Energy (an affiliate of UK based Centrica), Ontario Energy Savings, (a publicly traded Canadian company also present in Illinois and New York), Gateway Energy Services and Interstate Gas Services.  In electricity, our primary competitors are Gateway Energy Services, Direct Energy and Dominion Retail, in addition to merchant energy companies.

Seasonality of Our Operations

Weather conditions have a significant impact on customer demand and on the price of natural gas and electricity.  Customer demand exposes us to a high degree of seasonality in sales, cost of sales, billing to and cash collections from customers, inventory requirements and cash flows.  In addition, customers who choose to be on budget billing programs and LDC payment terms can cause timing differences between the billing and collection of accounts receivable and the recording of revenues.

We utilize a considerable amount of cash from operations to fund customer accounts receivable, natural gas inventory purchases and other working capital requirements during the months of November through April of each fiscal year.  The majority of natural gas consumption occurs during the months of November through March with collections on accounts receivable peaking in the spring.  In contrast, electricity consumption peaks during the summer months of June through September with collections on accounts receivable peaking in late summer.

Commodity Supply and Pricing Risk Management

Natural Gas Supply

We purchase natural gas supply and manage transportation logistics internally.   We purchase physical supply from over 50 natural gas producers, marketers, and energy trading firms in either a producing region or at delivery point.  We periodically adjust our portfolio of purchase/sales contracts, storage and transportation capacity based upon continual analysis of our forecasted load requirements, and determine whether it will be more economical to utilize natural gas from storage or to purchase from the spot market in relation to transportation costs and availability.

Natural gas is delivered to the LDC city-gate or other specified delivery points where the LDC takes control of the natural gas and delivers it to individual customers’ location of use, utilizing its extensive network of small diameter distribution pipe.  In addition, most LDCs provide ancillary services such as billing, meter reading and balancing services.  Because of this extensive transportation infrastructure and the services provided, LDC costs typically make up a significant portion of the end user’s utility bill.

Electricity Supply

We purchase physical electricity supply from the independent system operator, or ISO, for all our power customers in New York, Connecticut and Massachusetts.  In the Texas market, we purchase physical electricity directly from various counterparties for delivery to the Electric Reliability Council of Texas, referred to herein as ERCOT, based on prices of the regional transmission organization, or RTO.

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Commodity Pricing Risk Management

We have a risk management policy that is intended to reduce our financial exposure to changes in the prices of natural gas and electricity.  Under this policy, the Company hedges all anticipated natural gas and electricity commodity purchases required to meet expected customer demand for all accounts served under fixed price contracts (up to 110% in the winter months with respect to customer demand in certain gas utilities with daily balancing requirements and up to 110% in the summer months with respect to customer on-peak demand in certain electricity utilities).

We have elected not to designate any of the derivative instruments as hedges, in accordance with applicable accounting rules.  Accordingly, any changes in the fair value of these instruments are adjusted through unrealized gains or losses from risk management activities in the consolidated statements of operations.

We utilize both physical and derivative instruments to reduce our exposure to fluctuations in the prices of natural gas and electricity.  Natural gas commodity derivatives used as hedges typically have included swaps and options executed under our Hedge Facility.  Electricity commodity derivatives used as hedges have been executed with a select number of counterparties, including: BP North America, Shell Energy North America and Constellation Energy Commodities Group.  As of June 30, 2008, our hedge positions extend through June 2011.

Under the Hedge Facility, we utilize NYMEX referenced over-the-counter swaps, basis price swaps and options to hedge the risk of variability in the cost of natural gas.  The agreement governing the Hedge Facility was amended in March 2008 and July 2008.  Refer to Note 8 to the consolidated financial statements, included elsewhere in of this Annual Report, for additional information regarding the Hedge Facility.

Refer to “Item 7A.  Quantitative and Qualitative Disclosures About Market Risk”, for additional commentary regarding commodity price risk.

Our Foreign Operations

Our principal foreign operations are located in Canada.  Foreign operations comprised less than 1% of our consolidated total assets at June 30, 2008 and less than 1% of our consolidated sales of natural gas and electricity for the fiscal year ended June 30, 2008.

Our Management Team and Employees

The members of our executive management team have extensive experience in energy risk management and retail marketing as well as in creating, developing and managing businesses and risk on behalf of major international corporations.  The professional backgrounds of our executive management team are described under “Item 10.  Directors, Executive Officers and Corporate Governance.”

As of June 30, 2008  we had approximately 220 full-time equivalent employees in the United States and Canada.  None of our employees is subject to a collective bargaining agreement, and we believe that our relationship with our employees is good.

Our Committed and Knowledgeable Equity Ownership

Our primary stockholders include Denham Commodity Partners Fund LP (“Denham”), Charterhouse Group Inc. (“Charterhouse”) and Greenhill Capital Partners (“GCP”).  These stockholders have made equity investments that have provided us with sufficient financial capital to grow and support our business.  In addition, these stockholders have an in-depth understanding of the energy and financial markets, and provide strength and insight for our activities and strategy.

Denham (formerly known as Sowood Commodity Partners Fund LP and before that, Lathi, LLC, a subsidiary of Harvard Management Company Inc.) and its affiliated funds invest in assets and companies that provide goods and services in commodity markets, primarily in the energy sector.  Denham made an initial investment in us in February 2001.  In addition to its equity investment, Denham provides financing to us through a currently unused subordinated line of credit  that expires in May 2010 and also provides risk management advice and strategic planning.

Charterhouse is a New York-based, middle-market private equity investment firm with a focus on buyouts, build-ups and growth capital financings.  Charterhouse made an initial investment in us in 2004.  Charterhouse invests in the business

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services (including the energy services sub-sector), consumer, and healthcare services sectors.  Established in 1973, Charterhouse has invested in excess of $2 billion in equity capital in various companies, including us.

GCP is an affiliate of Greenhill & Co., Inc. (“Greenhill”), an independent global investment banking firm.  GCP manages several private equity funds which total $1.8 billion in capital, focusing on the energy, financial services and telecommunications industries.  Greenhill was founded in 1996 and provides financial advisory and merchant banking fund management services through its offices in New York, London, Frankfurt and Dallas.

Environmental Matters

We do not have physical custody or control of the natural gas provided to our customers, or any facilities used to transport natural gas.  In addition, title to the natural gas sold to our customers is passed at the same point at which we accept title from our natural gas suppliers.  Therefore, we do not believe we have significant exposure to legal claims or other liabilities associated with environmental concerns.

Where You Can Find More Information

Our filings with the SEC are available to the public over the internet at the SEC’s website at www.sec.gov.  You may also read and copy any document we file at the SEC’s public reference room located at 100 F Street, N.E., Washington, D.C. 20549.  Our filings with the SEC are also available under the SEC Filings section of our website, www.mxholdings.com, as soon as reasonably practicable after we electronically file such reports with the SEC.  The information contained on this internet site is not incorporated by reference in this Annual Report.  You may also request a copy of these filings, at no cost, by writing to us at: MXenergy Holdings Inc., 595 Summer Street, Suite 300, Stamford, Connecticut 06901, Attention: Chief Financial Officer, or by calling us at (203) 356-1318.

The website at www.mxholdings.com contains information concerning Holdings and its subsidiaries.  This website is separate from our consumer website, www.mxenergy.com.  The information contained on our website and those of our subsidiaries is not incorporated by reference in this Annual Report.

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ITEM 1A.   RISK FACTORS

Any of the following risks could have an adverse effect on our business, financial condition or results of operations.  Additional risks or uncertainties not currently known to us may also arise in the future that could have an adverse effect on our business, financial condition or results of operations.

Risks related to our business

Our risk management policies and hedging procedures may not mitigate risk as planned, and we may fail to fully or effectively hedge our commodity supply and price risk exposure against changes in market rates or consumption volumes.

To provide energy to our customers, we purchase the relevant commodity in the wholesale energy markets, which are often highly volatile.  It is our policy to match estimated consumption by our customers by purchasing offsetting volumes of natural gas and electricity.  To reduce our financial exposure related to commodity price fluctuations and changes in consumption volumes, we routinely enter into contracts to hedge our fixed price sale commitments, delivery requirements and inventory of natural gas, as well as fixed price sale commitments and line loss of electricity.

We have contractual obligations to many of our customers to provide full requirements service and as a result, our hedging procedures require constant monitoring and adjustment. Failure to continue to use valid assumptions may lead to inappropriate hedging positions.  In addition, there are a number of factors that are beyond our control, such as risk of loss from counterparties’ nonperformance, volumetric risks related to customer demand and seasonal fluctuations.  Although we try to purchase anticipatory hedges that represent volume we expect to sell to residential and small commercial customers for up to one month of projected marketing, we are exposed to the risk of a shortfall in marketing that could result in our purchases exceeding our supply commitments to those customers.  We cannot fully protect ourselves against these factors and if our risk management policies are inadequate, this may have a detrimental effect on our business.

Actual customer attrition may exceed expected attrition, which could result in a cost to cover for previously purchased fixed price hedges and physical supplies.

Although our fixed price contracts with residential customers generally have terms of up to three years, those customers may terminate their contracts at any time for a termination fee that, in most cases, is relatively modest and does not bear any relation to our costs or lost profit with respect to the remainder of the contract.  Most of our small and mid-market commercial customers cannot terminate their fixed price contracts without triggering a damages provision designed to cover costs related to the termination of those contracts.  For larger commercial customers, we utilize various means to ensure that we recover our costs, including legal remedy if appropriate.   We depend on our hedging strategies to cover the costs related to terminations by residential and small commercial customers.  To hedge effectively against terminations, we must, at the inception of the contracts, attempt to accurately forecast the number of residential and small commercial customers that will terminate their contracts prior to the end of their term.  If we experience a number of cancellations greater than originally forecasted or if we are not able to replace terminating customers with new customers, our financial results may be negatively impacted.

Most of our financial swap agreements are settled against published index prices which could cease to be reliable or could become unavailable.

We hedge our forward natural gas exposures through a combination of physical supply purchase and financial swap agreements.  Financial swap agreements may be settled against monthly NYMEX settlement prices or against index prices published by various industry publications.  NYMEX settlement prices could be affected by supply and demand factors at the Henry Hub delivery point of the contract which are not present elsewhere in the country.  Accordingly, the NYMEX settlement prices may cease to reflect accurately the market price of natural gas.  Likewise, index prices for market areas in which our customers are located, and which are contained in daily and monthly publications, are published based on private polling of industry participants and therefore may be distorted, deliberately or unintentionally, thereby ceasing to be an accurate gauge of market pricing in those areas.

In the event either NYMEX settlement prices or published index prices were to become unavailable or cease to be reliable, we and our counterparties could seek to find a replacement price that would more accurately or reliably reflect the market prices that we are hedging.  However, there is no certainty that such efforts would be successful.

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The accounting method utilized for our hedging activities results in volatility in our quarterly and annual financial results.

We engage in price-risk management activities related to our natural gas and electricity purchases in order to economically hedge our exposure to commodity price risk.  Through the use of financial and physical derivative contracts, we attempt to balance our physical and financial purchases and sales commitments.  In accordance with current accounting guidelines, we have not designated these derivative instruments as hedges for accounting purposes.  Therefore, changes in the fair value of these instruments are recognized immediately in earnings.  As a result of this accounting treatment, changes in the forward prices of natural gas and electricity cause volatility in our quarterly and annual earnings, which we are unable to fully anticipate.

We may not have sufficient liquidity or credit capacity to hedge market risks, to continue to grow our business, or to operate effectively.

Our Hedge Facility expires on July 1, 2009.  Upon expiration, we may not be able to replace the Hedge Facility on terms that will be favorable to us or at all, including terms related to guarantees, letters of credit, or additional cash collateral required to protect counterparties against the risk of our default or insolvency.  Without a sufficient amount of working capital to post as collateral or cash margin, we may not be able to effectively manage price volatility or our market risk strategy, which could negatively affect our liquidity position and financial condition.

Our contractual agreements with certain LDCs require us to maintain restricted cash balances or letters of credit as collateral for the performance risk associated with the future delivery of natural gas.  These collateral requirements may increase as we grow our customer base.  Additionally, we must post letters of credit with our natural gas and electricity supply providers, the aggregate value of which could fluctuate based on the volume or cost of the commodity purchased in any given month.  Significant movements in market prices also can result in fluctuations in the collateral required.  The effectiveness of our operations and future growth depends in part on the amount of cash and letters of credit available to enter into or maintain these contracts.  Such liquidity requirements may be greater than we anticipate or are able to meet.

Despite our efforts to hedge risk and accurately forecast demand, our financial results are susceptible to changing weather conditions and commodity price fluctuations and therefore will fluctuate on a seasonal and quarterly basis.

Our overall operating results fluctuate substantially on a seasonal basis, and the pattern of this fluctuation may change depending on: (1) the geographic mix of our customer base; (2) the terms of any contract to which we become a party; (3) weather conditions, which directly influence the demand for electricity and natural gas and affect the prices of energy commodities; and (4) variability in market prices for natural gas and electricity.

Generally, demand for electricity peaks in the summer and demand for natural gas peaks in the winter.  Recent growth in natural gas-fired electric generation has introduced a secondary peak for natural gas in the summer.  Typically, when winters are warmer than expected and summers are cooler than expected, demand for energy is lower, resulting in less electric and gas consumption than forecasted.  Likewise, when winters are colder or summers are warmer than expected, consumption may be greater than we have hedged and greater than we are able to meet with storage or swing supply. Depending on prevailing market prices for electricity and gas, these and other unexpected conditions may reduce our sales or increase our costs and negatively impact our results of operations.  We may experience lower consumption volumes, and therefore, lower sales. We may experience losses from the purchase of additional volumes at higher prices or the sale of excess volumes at prices below our acquisition cost.  Our failure to anticipate changing weather demands or to effectively manage our supply in response to changing demands could negatively impact our financial results.

The impact of rapidly rising or falling commodity prices also varies greatly depending on the period of time that they occur within our fiscal year.  Although operating results for a full fiscal year may not be materially impacted by such trends due to our commodity hedging and contract pricing strategies, they can have material short-term impacts on monthly and quarterly operating results, which may be misleading when considered outside of the context of our annual operating cycle.

Large fluctuations in the market price of natural gas and electricity within short periods of time also may have a negative impact on borrowing base availability under our Revolving Credit Facility, which could limit the availability of credit necessary to operate our business.

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We are subject to direct credit risk for certain customers who may fail to pay their bills as they become due.

We are responsible for the billing and collection functions for all of our customers located in Georgia, Florida and Texas, and for our mid-market commercial customers located in New York, New Jersey and Ohio.  This group of customers represents approximately 56% of our sales of natural gas and electricity.  In these markets, we bear the risk of customers’ failure to pay their utility bills.  With the exception of customers in Georgia and Texas, we have the ability to terminate our agreement with customers in the event of non-payment, but we cannot terminate their electric or gas service.  Even if we terminate service to customers who fail to pay their utility bill, we remain liable to our suppliers of electricity and natural gas for the cost of those commodities.  Furthermore, in the Georgia and Texas markets, we are responsible for billing the distribution charges for the local utility and are at risk for these charges, in addition to the cost of the commodity, in the event customers fail to pay their bills.  Rising energy prices also results in higher risk of customers being unable to pay their bills when due.

The failure of our customers to pay their bills or our failure to maintain adequate billing and collection procedures could adversely affect our results of operations or financial condition.

We are subject to credit, operational and financial risks related to certain LDCs that provide billing services and guarantee the customer receivables for their market.

As of June 30, 2008, approximately 54% of our RCEs were within markets where the LDC guarantees the billing and collection of customer accounts receivable.  We rely on the utilities to perform timely and accurate billing under these agreements. As our business grows, the proportion of customers we serve that are billed by utilities could increase.  The bankruptcy of a utility could result in a default in such utility’s payment obligations to us.

In addition, LDCs that provide billing services and guarantee customer accounts receivable rely on us for accurate and timely communication of contract rates and other information necessary for accurate billing to customers.  The number of territories within which we provide natural gas and electricity supply poses a constant challenge that demands considerable management, personnel and information systems resources.  Each territory requires unique and often varied electronic data interface systems.  Rules that govern the exchange of data may be changed by the LDCs.  In certain instances, we must rely on manual processes and procedures to communicate data information to LDCs for inclusion in customer bills.  Failure to provide accurate data to LDCs on a timely basis could adversely impact our results of operations.

We depend on the accuracy of data in our billing systems.  Inaccurate data could have a negative impact on our results of operations, financial condition, cash flows and reputation with customers and/or regulators.

We depend on the accuracy and timeliness of customer billing, collections and consumption information in our information systems.  We rely on many internal and external sources for this information, including:

·our internal marketing and pricing and customer operations functions;

·LDCs with which we have billing service agreements; and

·various utility companies for volume or meter read information, certain billing rates and billing types (e.g., budget billing) and other fees and expenses.

Inaccurate or untimely information, which may be outside of our direct control, could result in:

·inaccurate and/or untimely bills sent to customers;

·inaccurate accounting and reporting of customer revenues, gross profit and accounts receivable activity;

·customer complaints; and

·increased regulatory scrutiny.

We depend on local transportation and transmission facilities of third parties to supply our customers. Our financial results may be harmed if transportation and transmission availability is limited or unreliable.

We depend on transportation and transmission facilities owned and operated by utilities and other energy companies to deliver the electricity and natural gas we sell to customers.  Under the regulatory structures adopted in most jurisdictions, we are required to enter into agreements with local incumbent utilities for use of the local distribution systems and to establish functional data interfaces necessary to serve our customers.  Any delay in the negotiation of such agreements or inability to enter into reasonable agreements could delay or negatively impact our ability to serve customers in those jurisdictions, which could have an adverse impact on our business, results of operations, and financial condition.

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We also depend on local utilities for maintenance of the infrastructure through which we deliver electricity and natural gas to our customers.  We are limited in our ability to control the level of service the utilities provide to our customers.  Any infrastructure failure that interrupts or impairs delivery of electricity or natural gas to our customers could cause customer dissatisfaction, which could adversely affect our business.

If transportation or transmission is disrupted, or if transportation or transmission capacity is inadequate, our ability to sell and deliver products may be hindered.  Such disruptions could also hinder our providing electricity or natural gas to our customers and adversely impact our financial results.

Regulations in many markets require that meter reading and the billing and collection processes be retained by the local utility.  In those states, we also are required to rely on the local utility to provide us with our customers’ information regarding energy usage.  Our inability to confirm information received from the utilities could negatively impact our reputation with customers and, therefore, our sales and results of operations.

We are subject to competition in each of the markets that we serve.

While there are barriers to entry, we operate only in markets that are open to alternate energy suppliers. Competition is based primarily on product offering, price and customer service.  We generally face competition in those markets from utility-affiliated retail marketers and small to mid-size independent retail energy companies.  Some of these competitors or potential competitors may be larger and better capitalized than we are.

Increasing our market share depends in part on our ability to convince customers to switch to our service. The local utilities have the advantage of long-standing relationships with their customers, longer operating histories, greater financial strength and greater name recognition than we do. In addition, customers may be less familiar with the fixed price product that we offer, and we may not be successful in educating potential customers about the benefits of fixed price energy supply nor of the other products we offer. Convincing customers to switch to a new company for the supply of a critical commodity such as electric power or natural gas is a challenge. If our marketing strategy is not successful, our business, results of operations and financial condition will be adversely affected.

In addition, our marketing efforts may be hindered in a market where our offers are less competitive relative to price offerings of the utilities or other marketers. Utilities historically react more slowly to changing commodity prices, whereas our products generally reflect the prevailing market prices. These factors may result in less effective marketing or higher than anticipated attrition.

We depend on continued state and federal regulation to permit us to operate in deregulated segments of the electric and gas industries.  If competitive restructuring of the electric or gas utility industries are altered, reversed, discontinued or delayed, our business prospects and financial results could be materially adversely affected.

The regulatory environment applicable to the electric and gas LDC distribution systems has undergone substantial change over the past several years as a result of restructuring initiatives at both the state and federal levels.  We have targeted the deregulated segments of the electric and gas markets created by these initiatives.  Regulations may be revised or reinterpreted or new laws and regulations may be adopted or become applicable to us or our operations.  Such changes may have a detrimental impact on our business.

In certain deregulated electricity markets, proposals have been made by governmental agencies and/or other interested parties to re-regulate areas of these markets.  Other proposals to re-regulate may be made and legislated or other attention to the electric and gas restructuring process may delay or reverse the deregulation process or interfere with our ability to do business.   If competitive restructuring of electric and gas markets is altered, reversed, discontinued or delayed, our business prospects and financial results could be negatively impacted.

We may not be able to manage our growth successfully, which could strain our liquidity and other resources and lead to poor customer satisfaction with our services.

We intend to continue to assess new product offerings, apply new technologies for our business development and make investments in

acquisitions of complementary companies.  If we buy a company or business, we may experience difficulty integrating that company’s personnel and operations, or key personnel of the acquired company may decide not to work for us.  Furthermore, if we acquire the residential or small commercial businesses of an incumbent utility or other energy provider in a particular market, the customers of that entity may not be under any obligation to use our services.  If we

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make other types of acquisitions, we may experience difficulty in assimilating the acquired technology or products into our operations or information systems.  These difficulties could disrupt our ongoing business, distract our management and employees, and increase our expenses.

The growth of our operations will depend upon, among other things, our ability to expand our customer base in our markets and to enter new markets in a timely manner at reasonable costs.  We anticipate that our employee base will grow to accommodate our increased customer base.  As we expand our operations, we may encounter difficulties integrating new customers and employees as well as any legacy systems of acquired entities.  We also may experience difficulty managing the growth of a portfolio of customers that is diverse with respect to the types of service offerings, applicable market rules and the infrastructure for product delivery.

Expanding our operations could result in increased liquidity needs to support working capital, for the purchase of natural gas and electricity supply to meet our customers’ needs, for the credit requirements of forward physical supply and for generally higher operating expenses.  Our Revolving Credit Facility and Hedge Facility may not be adequate to meet these higher liquidity requirements.

Expanding our operations also may 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 adversely affected.

Our success depends on key members of our management, the loss of whom could disrupt our business operations.

We depend on the continued employment and performance of key management personnel.  A number of our senior executives have substantial experience in consumer and energy markets that have undergone regulatory restructuring and have extensive risk management and hedging expertise.  We believe their experience is important to our continued success.  If our key executives do not continue in their present roles and are not adequately replaced, our business operations could be adversely affected.  In addition, failure to retain or adequately replace our Chief Executive Officer could give rise to a default under our Revolving Credit Facility.

We rely on a capable, well-trained workforce to operate effectively.  Retention of employees with strong industry or operational knowledge is essential to our ongoing success.

Many of the employee positions within our customer operations, information systems, pricing, marketing, risk management and finance functions require extensive industry, operational or financial experience that may not be easily replaced if an employee were to leave employment with us.  While some employee turnover is expected, unusually high turnover could strain our ability to manage our ongoing operations as well as inhibit organic and acquisition growth.

We are susceptible to downturns in general economic conditions, which could have a material adverse affect on our business, results of operations and financial condition.

The natural gas and electricity industries have historically been affected by general economic downturns, including conditions within the housing market.  Periods of slowed economic activity generally result in decreased natural gas and electricity consumption, and could result in increased customer attrition.  As a consequence, national or regional recessions or downturns in economic activity that impact our industrial, commercial and residential customers could adversely affect our revenues, our collections of billed accounts receivable and our cash flows, and could restrict our future growth in certain markets, any of which could have an adverse effect on our business, results of operations and financial condition.

General economic conditions can also impact the performance of various counterparties to various arrangements, including:

·failure of a supplier to deliver commodity at a specified time for a specified price under existing supply agreements, which could result in penalty assessments against us and/or could result in higher commodity prices from purchasing replacement commodities on the spot market;

·failure of local transportation and transmission facilities to allow their facilities to be utilized in accordance with related agreements, which could result in significant delays in delivery or higher costs associated with located alternate facilities; and

·failure of other contracted entities to deliver goods or services when due or requested.

22

If a counterparty to our hedge positions or lending agreements fails to perform, such failure could have an adverse effect on our business, results of operations and financial condition.

The successes, failures or activities of various LDCs and other retail marketers within the markets that we serve may impact the perception of the Company.

The general perception on the part of customers and regulators of utilities and retail energy marketers in general, and of the Company in particular, is essential for our continued growth and success.  Questionable pricing, billing, collections or customer service practices on the part of any utility or retail marketer can damage the reputation of all market participants, which could result in lower customer renewals and impact our ability to sign-on new customers.  Any utility or retail marketer that defaults on its obligations to its customers, suppliers, lenders, hedge counterparties, or employees can have similar impact on the retail energy industry as a whole and on our operations in particular.

We are subject to regulatory scrutiny in all of our markets.  Failure to follow prescribed regulatory guidelines could result in customer complaints and regulatory sanctions.

We generally must apply to become a retail marketer of natural gas and electricity in the markets that we serve.  Approval by the local regulatory body is subject to our understanding of and compliance with various federal, state and local regulations that govern the activities of retail marketers.  If we fail to comply with all such regulations, we could suffer certain consequences, which may include:

·higher customer complaints and attrition;

·increased regulatory scrutiny and sanctions, up to and including the loss of our license or ability to operate in those markets; and

·damage to our reputation with customers and regulators.

We expend extensive resources to convert, improve and maintain our information systems.  Failure to successfully do so may result in a negative impact on our results of operations, financial condition, cash flow and reputation with our customers and/or regulators.

Our operations rely heavily on the quality of our information systems and the employees that are responsible to manage them.  If any of our system conversion or improvement projects are unsuccessful, or if our processes for managing and maintaining our information systems are inadequate, we could be subjected to:

·inaccurate or untimely financial accounting and reporting information;

·inaccurate or untimely customer billing information;

·customer complaints;

·increased regulatory scrutiny;

·inability to successfully complete future business combinations or other customer acquisitions; and/or

·inaccurate forecasts of expected customer consumption requirements, potentially resulting in misalignment with hedged positions and related impact on gross profit.

Our operations in Houston, Texas and the communities where our customers and employees live along the southeast coast of Texas are vulnerable to hurricanes in the Gulf of Mexico.

Because of its proximity to the Gulf of Mexico, the southeast coast of Texas is vulnerable to hurricanes, which can cause significant damage to property and public infrastructure.  In particular, damage to property and disruption of electrical and other basic utilities for extended periods can have a devastating impact on areas struck by hurricanes, including our leased facilities and the communities where our employees live.  In addition, because we provide electricity to customers along the southeast coast of Texas, extended disruption of electrical service also could have an adverse impact on our results of operations.

We have a business continuity plan that is periodically reviewed and enhanced to ensure that the effects of such disruptions on our operations result in minimal impact on service provided to our customers and on our results of operations.

Our reliance on the electrical power generation and transmission infrastructure within the United States and Canada makes us vulnerable to large scale power blackouts.

The power generation and transmission infrastructure in the United States is very complex.  Maintaining reliability of the infrastructure requires appropriate oversight by regulatory agencies, careful planning and design, trained and skilled

23

operators, sophisticated information technology and communication systems, ongoing monitoring and, where necessary, improvements to various components of the infrastructure.  Despite extensive oversight and development of numerous safeguards, major electric power blackouts are possible, which could disrupt electrical service for extended periods of time to large geographic regions of the United States and Canada.  If such a major blackout were to occur, we may be unable to deliver electricity to our customers in the affected region, which would have an adverse impact on our results of operations.

Risks related to Liquidity, Indebtedness and Capital

We may need to raise additional debt or letter of credit capacity to fund growth or operations, which may not be available to us on favorable terms or at all.

Our business requires substantial capital to fund growth through organic marketing or acquisition, for supporting working capital, for the purchase of natural gas and electricity supply to meet our customers’ needs, and for the credit requirements of forward physical supply.

We may need to incur additional debt or obtain additional letter of credit capacity in order to fund working capital, finance other acquisitions or for other purposes.  We cannot be certain that we will be able to obtain such additional financing on favorable terms or at all.  If we need additional debt or letter of credit capacity and cannot raise it on acceptable terms, our financial condition and business will be adversely affected.

We believe our lines of working capital financing are sufficient to meet our current and anticipated needs, but these lines may be reduced in accordance with the terms of such agreements.  Moreover, in the event our needs change, either because of growth or higher energy costs, additional working capital financing capacity may be necessary and there can be no assurance that such arrangements will be available on terms acceptable to us or at all.

Our business growth over the past two fiscal years has been funded by significant debt obligations, particularly our obligations under the Senior Notes.  Any material adverse financial events or trends could adversely affect our financial health and prevent us from fulfilling our debt obligations.

As of June 30, 2008, we had $162.6 million aggregate principal amount of Senior Notes outstanding (net of discount), which were issued to fund our acquisition of SESCo in August 2006 (the “SESCo Acquisition”).  Our ability to make payments on and to refinance our debt, and to fund planned capital expenditures and expansion efforts and any strategic acquisitions we may make in the future, if any, will depend on our ability to generate cash in the future.  This, to a certain extent, is subject to general economic, financial, competitive and other factors that are beyond our control.

We will require a significant amount of cash to service our debt obligations.  Our ability to generate sufficient cash to service debt depends on the ability of our primary operating subsidiaries to generate adequate cash flow.

Holdings has no material operating activities.  Accordingly, Holdings’ only material source of cash, including cash to service the Senior Notes and other debt obligations, comes from Holdings’ ownership interests in its primary operating subsidiaries.  Available distributions from our operating subsidiaries may depend on factors out of our control, which may include:

·the financial performance of our operating subsidiaries;

·covenants contained in our debt agreements;

·covenants contained in other agreements to which we or our subsidiaries are or may become subject;

·business and tax considerations; and

·applicable laws, including laws regarding the payment of distributions.

There can be no assurance that our business will generate sufficient cash flow from operations in the future, that our currently anticipated growth in net sales and cash flow will be realized or that future borrowings will be available to us in an amount sufficient to enable us to repay indebtedness, including our Senior Notes, which are due in 2011.  We may need to refinance all or a portion of our indebtedness on or before maturity.  There can be no assurance that we will be able to refinance any of our indebtedness on commercially reasonable terms or at all.

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Our interest expense would increase if interest rates increase which would have a negative impact on our financial performance.

We use interest rate swaps to hedge the floating rate interest expense on the Senior Notes.  As of June 30, 2008, the following swap arrangements were outstanding:  (1) a $50.0 million swap that expired on August 1, 2008; (2) a $30.0 million swap that expires on August 2, 2010; and (3) an $80.0 million swap that expires on August 1, 2011.  All swaps are fixed-for-floating and settle against the six-month LIBOR rate.  Since interest rate exposure associated with the Senior Notes is not fully hedged, a 1% change in LIBOR, after taking into account the average outstanding notional amount of our interest rate swap agreements, would result in our interest expense fluctuating approximately $0.4 million per year based on our average monthly debt balance for the fiscal year ended June 30, 2008.  We may not be successful in renewing or obtaining additional hedges on acceptable terms or at all, which could have an adverse effect on our results of operations or our ability to service outstanding indebtedness.

Our substantial debt obligations could adversely affect our financial health and prevent us from fulfilling such obligations, including our obligations under the Senior Notes, and we might have difficulty obtaining more financing.

We have a substantial amount of indebtedness in relation to our equity.  As of June 30, 2008, we had approximately $162.6 million of total outstanding indebtedness under our Senior Notes and $147.9 million in issued letters of credit under our Revolving Credit Facility.  In addition, we had $46.0 million of unused availability under our Revolving Credit Facility and $12.0 million of unused availability under our line of credit with Denham (the “Denham Credit Facility”).  Our substantial debt obligations could have important consequences, which could include:

·making it more difficult for us to satisfy our debt service obligations;

·increasing our vulnerability to general adverse economic and industry conditions;

·requiring us to dedicate a substantial portion of our cash flow from operations to debt service, thereby reducing the availability of our cash flow to fund working capital, capital expenditures, acquisitions and other general corporate purposes;

·limiting our flexibility in planning for, or reacting to, changes in our business and the markets in which we operate;

·placing us at a competitive disadvantage compared to our competitors that have less debt; and

·limiting our ability to borrow additional funds.

Significant increases in energy prices or other adverse industry or financial trends that are outside of our direct control could cause us to draw down on a portion or all of our available credit.  We may require additional indebtedness in the future.  Our ability to obtain new debt may be limited by the agreements governing the Senior Notes and our credit facilities.  If new debt is added to current debt levels, the related risks described above could intensify. If such debt financing is not available when required or is not available on acceptable terms, we may be unable to grow our business, take advantage of business opportunities, respond to competitive pressures or refinance maturing debt, any of which could have a material adverse effect on our operating results and financial condition.

Our funding for future growth may depend upon obtaining new financing, which may be difficult to obtain given prevalent economic conditions and our credit ratings.

In order to accomodate future growth in our natural gas and electricity businesses, we may need additional funding beyond cash provided from current operations and available balances under our current credit facilities.  Our ability to obtain new financing will be constrained by current economic conditions affecting financial markets.  Specifically, the recent credit crisis and other related trends affecting the banking industry have caused significant operating losses and bankruptcies throughout the banking industry.  Many lenders and institutional investors have ceased to provide funding to even the most credit-worthy borrowers.  If the availability of credit is negatively impacted to the extent that we are unable to obtain additional financing, we may be unable to take advantage of opportunities to acquire customer portfolios or operations of other retail energy businesses, to finance our existing operations or to otherwise expand our business as planned.

The agreement pursuant to which Holdings issued preferred stock contains redemption provisions, which are subject to various triggering events and/or dates.  If Holdings is required to redeem the preferred stock, we may have to seek additional debt financing.

On or after the fifth anniversary of the issuance of Holdings’ redeemable convertible preferred stock (the “Preferred Stock”), if the fair market value of our common stock is at a level that would not provide the holders of Preferred Stock an annual

25

rate of return of at least 25%, compounded annually, for the five-year period ending June 30, 2009, such holders may require us to make a redemption election.  If the holders of the Preferred Stock require us to make a redemption election at June 30, 2009, the earliest possible date for such a request, and if we elect to redeem the Preferred Stock, the redemption price would be, at a minimum, approximately $54.6 million at June 30, 2009; and would continue to increase, at a minimum, at a compounded annual rate of 12% thereafter.  This would represent a substantial liquidity event for us, and would require us to seek additional debt financing and/or equity investors for funding of the transaction.

If we elect not to redeem the Preferred Stock, we would be required to grant the holders of Preferred Stock effective control over our Board of Directors, which could have an impact on the future direction of the Company.

We are currently considering options for renewing, extending or replacing the Revolving Credit Facility and the Hedge Facility.  The current credit market environment and our current credit ratings may hamper our ability to negotiate renewals, extensions or replacements for these facilities on terms acceptable to us or at all.

The original expiration date of our Hedge Facility was August 1, 2008.  On July 31, 2008, the agreement governing the Hedge Facility was amended to reflect revisions to certain provisions, including extension of the termination date through August 1, 2009.

The original expiration date of our Revolving Credit Facility was December 19, 2008.  On September 30, 2008, the agreement governing the Revolving Credit Facility was amended and restated to, among other things, extend the termination date through July 31, 2009, at which time any outstanding principal amounts will become due.  Additionally, if the revolving credit facility is not extended or replaced, we will not be able to have letters of credit issued on our behalf after July 31, 2009.

We are currently considering options for negotiating renewal of the Hedge Facility and the Revolving Credit Facility, for further extension of the current facility agreements or for negotiating facilities with new hedge or financing facilitators.  Although we expect that we will be able to renew, extend or replace the existing facilities, if the current lack of available credit continues and/or our credit ratings do not improve, it may hinder our ability to negotiate these agreements.  However, no assurances can be made that we will be able to do so on terms that will be favorable to us relative to the current terms of the facilities or at all.

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ITEM 1B.  UNRESOLVED STAFF COMMENTS

None.

ITEM 2.  PROPERTIES

Our corporate headquarters, which are comprised of executive, finance, marketing, risk management, internal audit and legal functions, are located in Stamford, Connecticut.  During the fiscal year ended June 30, 2007, as a result of the SESCo Acquisition, we moved several of our operational functions, including pricing, information technology, customer operations and data solutions, accounting operations, collections, and certain human resources functions to Houston, Texas, where most of our employees currently work.

We lease all of our properties.  As of June 30, 2008, management believes that all properties are suitable and adequate for the business conducted therein, are being appropriately used and have sufficient capacity for the present intended purposes.

ITEM 3.  LEGAL PROCEEDINGS

From time to time, we are a party to claims and legal proceedings that arise in the ordinary course of business, including investigations of product pricing and billing practices by various governmental or other regulatory agencies. We do not believe that any such proceedings to which we are currently a party will have a material adverse impact on our results of operations or financial position.

ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No matters were submitted to a vote of security holders during the fiscal year ended June 30, 2008.

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PART II.

ITEM 5.  MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER AND ISSUER PURCHASES OF EQUITY SECURITIES

There is no established trading market for our common stock, par value $.01 per share.  As of August 31, 2008, there were 69 holders of record of our common stock.

Dividend Policy and Restrictions

Our Board of Directors, at its discretion, has the authority to declare and pay dividends on our common stock provided there are funds available to do so.  In addition, holders of the Preferred Stock are entitled to participate in any dividend paid on our common stock.

We are restricted in our ability to pay dividends by various provisions of agreements that govern our debt instruments.  We have never declared or paid any cash dividends on our common stock and do not intend to pay any cash dividends on our common stock in the foreseeable future.  We currently intend to retain any future earnings to finance the expansion of our business and for general corporate purposes.

Securities Authorized for Issuance Under Equity Compensation Plans

The table below provides information, as of June 30, 2008, concerning securities authorized for issuance under our equity compensation plans.  Refer to Notes 2 and 17 to the consolidated financial statements, included elsewhere in this Annual Report, for additional information regarding our stock-based compensation plans.

Plan Category	Number of securities to be issued upon exercise of outstanding options (2)	Weighted average exercise price of outstanding options		Number of securities remaining available for future issuance under equity compensation plans (3)
Equity compensation plans approved by security holders (1)	1,079,820	$	27.50	333,112

(1)As of June 30, 2008, all of our equity compensation plans were approved by security holders.

(2)Excludes 41,500 warrants issued to employees that were not issued under any equity compensation plan.  As of June 30, 2008, the weighted average exercise price for these warrants was $22.43.

(3)Excludes securities reflected in the first column.

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ITEM 6.  SELECTED FINANCIAL DATA

Adjusted EBITDA

Management believes that Adjusted EBITDA, a non-U.S. GAAP measure defined below, is a measure commonly used by financial analysts in evaluating operating performance and liquidity of companies, including energy companies. Management also believes that this measure allows a standardized comparison between companies in the energy industry, while minimizing the differences from depreciation policies, financial leverage, hedging strategies and tax strategies.  Accordingly, management believes that Adjusted EBITDA is the most relevant financial measure in assessing our operating performance and liquidity.  Adjusted EBITDA, as used herein, is not necessarily comparable to similarly titled measures of other companies.

EBITDA is defined as net income (loss) before interest expense, income tax expense (benefit), depreciation and amortization.  Adjusted EBITDA is defined by management as net income (loss) before interest expense, income tax expense (benefit), depreciation, amortization, stock compensation expense and unrealized gains (losses) from risk management activities.  Management believes the items excluded from EBITDA to calculate Adjusted EBITDA are not indicative of true operating performance or liquidity of the business and generally reflect non-cash charges.  Therefore, we believe that EBITDA would not provide an accurate reflection of the economic performance of the business since it includes the unrealized gains (losses) from risk management activities without giving effect to the offsetting changes in market value of the underlying customer contracts, which are being economically hedged.  In addition, as the underlying customer contracts are not marked to market, the unrealized gains (losses) from risk management activities do not offer an accurate indication of the ultimate cash impact to the business, as the ultimate cash impact to the business is not determinable until delivery of natural gas under the customer contracts and the associated realized gain (loss) on risk management activity.

Management uses Adjusted EBITDA for a variety of purposes including assessing our performance and liquidity, allocating our resources for operational initiatives (e.g., establishing margins on sales initiatives), allocating our resources for business growth strategies (e.g., considering acquisition opportunities), determining new marketing initiatives, determining market entry and rationalizing our internal resources.  In addition, Adjusted EBITDA is a key variable for estimating our equity value, including various equity instruments (such as common stock, preferred stock, stock options and warrants), and assessing compensation incentives for our employees.  Management also provides financial performance measures to our senior executive team and significant shareholders with an emphasis on Adjusted EBITDA, on a consolidated basis, as the appropriate basis with which to measure the performance and liquidity of our business.  Furthermore, certain financial covenants in our Revolving Credit Facility and our Hedge Facility contain ratios based on EBITDA and the items defined above that are excluded to calculate Adjusted EBITDA, as well as other items.  Accordingly, management and our significant shareholders utilize Adjusted EBITDA as a primary measure when assessing our operating performance and liquidity of our business.

EBITDA and Adjusted EBITDA have limitations as analytical tools in comparison to operating income or other combined income data prepared in accordance with U.S. GAAP.  Some of these limitations are:

·They do not reflect cash outlays for capital expenditures or contractual commitments;

·They do not reflect changes in, or cash requirements for, working capital;

·They do not reflect the interest expense or the cash requirements necessary to service interest or principal payments on indebtedness;

·They do not reflect income tax expense or the cash necessary to pay income taxes;

·Although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and EBITDA and Adjusted EBITDA do not reflect cash requirements for such replacements;

·Adjusted EBITDA does not reflect the impact of earnings or charges resulting from matters we consider not to be indicative of our ongoing operations; and

·Other companies, including other companies in our industry, may calculate these measures differently than as presented in this Annual Report, limiting its usefulness as a comparative measure.

Because of these limitations, EBITDA and Adjusted EBITDA and the related ratios should not be considered as a measure of discretionary cash available to invest in business growth or reduce indebtedness.

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The financial data included in the following table was derived from our audited consolidated financial statements, which are included elsewhere in this Annual Report.  The table includes a reconciliation from net income (loss) prepared on a U.S. GAAP basis to EBITDA and Adjusted EBITDA.  The financial information in the table should be read in conjunction with, and is qualified by reference to, our consolidated financial statements and notes thereto and commentary included in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Selected consolidated operating and balance sheet data is summarized in the following table.

	Fiscal Year Ended June 30,
	2008			2007			2006			2005			2004
	(in thousands)
Selected statement of operations data:
Sales of natural gas and electricity (1)	$	752,283		$	703,926		$	362,561		$	277,196		$	185,659
Cost of goods sold	569,585			602,146			389,526			202,112			109,926
Gross profit (loss)	182,698			101,780			(26,965		)	75,084			75,733
Operating expenses (2)	106,645			91,015			36,618			30,996			22,331
Operating profit (loss)	76,053			10,765			(63,583		)	44,088			53,402
Interest expense, net of interest income	34,105			33,058			3,200			2,858			3,109
Income (loss) before income tax (expense) benefit	41,948			(22,293		)	(66,783		)	41,230			50,293
Income tax (expense) benefit	(17,155		)	8,495			27,001			(18,142		)	(20,117		)
Net income (loss)	24,793			(13,798		)	(39,782		)	23,088			30,176
Items to reconcile net income (loss) to EBITDA :
Add: Interest expense, net of interest income	34,105			33,058			3,200			2,858			3,109
Depreciation and amortization	32,698			27,730			8,504			6,166			6,894
Income tax expense (benefit)	17,155			(8,495		)	(27,001		)	18,142			20,117
EBITDA	108,751			38,495			(55,079		)	50,254			60,296
Items to reconcile EBITDA to Adjusted EBITDA:
Add (less): Stock compensation expense (2)	3,358			4,539			911			2,033			1,894
Unrealized (gains) losses from risk management activities (3)	(67,168		)	17,079			79,897			(16,004		)	(46,360		)
Adjusted EBITDA	$	44,941		$	60,113		$	25,729		$	36,283		$	15,830
Selected balance sheet data (period-end balances):
Total current assets	$	271,973		257,708			$	67,517		$	157,122		$	122,363
Customer acquisition costs, net	41,693			38,954			10,822			7,171			10,439
Total assets	355,752			335,644			97,969			191,592			162,221
Total current liabilities	108,276			91,686			29,894			74,640			60,607
Long-term debt (4)	162,648			185,404			—			21,379			27,221
Redeemable convertible preferred stock (5)	48,779			29,357			29,357			29,357			29,730
Total stockholders’ equity	33,210			25,611			64,750			105,277			79,363

(1)Includes pass-through revenue, primarily representing transportation and distribution charges billed to customers on behalf of certain LDCs, that approximate $63.6 million and $54.5 million for the fiscal years ended June 30, 2008 and 2007, respectively. Also includes fee income charged to customers, such as late payment fees, early termination fees and service shut-off fees that approximate $19.4 million and $17.1 million for the fiscal years ended June 30, 2008 and 2007, respectively.  Pass-through revenue and fee income was not material for fiscal years prior to 2007.

(2)Effective July 1, 2006, the Company adopted the provisions of SFAS No. 123R, “Share-Based Payment (revised)”.  Refer to Notes 2 and 17 of our consolidated financial statements included elsewhere in this Annual Report for additional information.

(3)Unrealized gains and losses from risk management activities result from changes in forward natural gas and electricity prices during the respective periods in relation to the contracted forward prices.  These amounts should be fully or substantially offset in future periods, as physical commodity is delivered to customers during the remaining terms of their fixed rate contracts.

(4)The Senior Notes (net of original issue discount) were issued during the fiscal year ended June 30, 2007 primarily to provide financing for the SESCo Acquisition, with the balance being used for working capital needs.

(5)On or after the fifth anniversary of the issuance of the Preferred Stock, if the fair market value of Holdings’ common stock is at a level that would not provide the Preferred Investors with an annual rate of return of at least 25%, compounded annually, for the five-year period ending June 30, 2009, the Preferred Investors may require that the Company make a redemption election.  If the holders of the Preferred Stock require the Company to make a redemption election, and if the Company elects to redeem the Preferred Stock, the redemption amount is payable in cash equal to the greater of: (1) the fair market value of the shares of common stock into which the Preferred Stock may be converted on the date of the redemption election notice; or (2) the original issue price of $21.36 per share, plus any accrual of dividends.  If the Company elects not to redeem the Preferred Stock, it is required to grant the Preferred Investors effective control over Holding’s Board of Directors.  As of June 30, 2008, if the holders of Preferred Stock were to request that the Company make a redemption election, the Company does not have the intent or the ability to redeem the Preferred Stock due to limitations included in the agreements that govern the Revolving Credit Facility, the Hedge Facility and the Senior Notes.  However, since the Preferred Investors would effectively control the Company’s Board of Directors in the event that the Company does not elect to redeem the Preferred Stock, the Company has determined that, in accordance with U.S. GAAP, the Preferred Stock is redeemable at the option of the Preferred Investors and that it is probable that the Preferred Stock will become redeemable at June 30, 2009.  Therefore the carrying value of the Preferred Stock is recorded outside of stockholders’ equity on the consolidated balance sheets and has been adjusted to its redemption value as of June 30, 2008.  Refer to Note 16 of the consolidated financial statements for additional information regarding the Preferred Stock.

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A reconciliation of Adjusted EBITDA to net cash (used in) provided by operating activities is provided in the following table.

	Fiscal Year Ended June 30,
	2008		2007		2006		2005		2004
Adjusted EBITDA	44,941		60,113		25,729		36,283		15,830
Interest expense, net of interest income	(34,105	)	(33,058	)	(3,200	)	(2,858	)	(3,109	)
Income tax (expense) benefit	(17,155	)	8,495		27,001		(18,142	)	(20,117	)
Stock compensation expense	(1,654	)	—		—		—		—
Deferred tax expense (benefit)	18,187		(14,449	)	(32,764	)	6,552		19,730
Unrealized losses on interest rate swaps and amortization of deferred financing fees	10,836		7,906		1,057		349		207
Amortization of customer contracts acquired	(762	)	11,891		(3,276	)	—		—
Change in assets and liabilities, net of effects of acquisition:
Restricted cash	463		(623	)	6,953		2,195		(192	)
Accounts receivable	(30,181	)	3,453		(13,003	)	3,271		1,976
Natural gas inventories	(7,308	)	(1,712	)	(2,685	)	(72	)	(970	)
Income taxes receivable	(7,173	)	5,184		(5,535	)	—		—
Option premiums	1,191		1,835		(1,834	)	—		—
Other assets	609		(993	)	2,645		895		(4,610	)
Accounts payable and accrued liabilities	17,882		31,555		(5,320	)	1,283		2,646
Deferred revenue	(4,352	)	9,384		865		1,538		—
Net cash (used in) provided by operating activities	(8,581	)	88,981		(3,367		31,294		11,391
Net cash used in investing activities	(33,941	)	(132,920	)	(18,825		(8,296	)	(16,154	)
Net cash (used in) provided by financing activities	(22,462	)	174,788		(25,345		24,396		7,718

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Selected Data for Business Segments

Selected financial operating data for our natural gas and electricity business segments is provided in the following table.

Fiscal Year ended June 30,	Natural Gas			Electricity			Total
	(in thousands)
2008:
Sales	$	669,522		$	82,761		$	752,283
Cost of goods sold (1)	(564,219		)	(72,534		)	(636,753		)
Gross profit (1)	$	105,303		$	10,227		115,530
Items to reconcile total segment gross profit to income before income tax expense:
Unrealized gains (losses) from risk management activities							67,168
Operating expenses							(106,645		)
Interest expense, net of interest income							(34,105		)
Income before income tax expense							$	41,948
2007:
Sales	$	680,811		$	23,115		$	703,926
Cost of goods sold (1)	(565,531		)	(19,536		)	(585,067		)
Gross profit (1)	$	115,280		$	3,579		118,859
Items to reconcile total segment gross profit to loss before income tax benefit:
Unrealized gains (losses) from risk management activities							(17,079		)
Operating expenses							(91,015		)
Interest expense, net of interest income							(33,058		)
Loss before income tax benefit							$	(22,293	)
2006:
Sales	$	345,629		$	16,932		$	362,561
Cost of goods sold (1)	(296,607		)	(13,022		)	(309,629		)
Gross profit (1)	$	49,022		$	3,910		52,932
Items to reconcile total segment gross profit to loss before income tax benefit:
Unrealized gains (losses) from risk management activities							(79,897		)
Operating expenses							(36,618		)
Interest expense, net of interest income							(3,200		)
Loss before income tax benefit							$	(66,783	)

(1)Includes realized losses from risk management activities, but excludes unrealized gains (losses) from risk management activities.  As the underlying customer contracts are not marked to market, the unrealized gains (losses) from risk management activities do not offer an accurate indication of the ultimate cash impact to the business, as the ultimate cash impact to the business is not determinable until delivery of natural gas under the customer contracts and the associated gain (loss) on risk management activity is realized.

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Additional selected operating data for our business segments is summarized in the following table.

	Fiscal Year Ended June 30,
	2008		2007		2006		2005		2004
Natural Gas:
RCEs at period end	602,000		588,000		375,000		337,000		350,000
Average RCEs during the period	588,000		595,000		380,000		338,000		288,000
MMBtus sold during the period	54,339,000		57,064,000		35,488,000		32,957,000		25,771,000
Sales per MMBtu during the period	$	12.32	$	11.93	$	9.74	$	8.03	$	7.04
Gross profit per MMBtu during the period (1)	$	1.94	$	2.02	$	1.38	$	1.75	$	1.11
Electricity:
RCEs at period end	98,000		43,000		12,000		11,000		11,000
Average RCEs during the period	68,000		20,000		12,000		12,000		6,000
MWhrs sold during the period	636,000		193,000		120,000		130,000		14,000
Sales per MWhr during the period	$	130.13	$	119.77	$	141.10	$	97.69	$	300.00
Gross profit per MWhr during the period (1)	$	16.08	$	18.54	$	32.58	$	11.54	$		(2)

(1)Includes fee income and realized losses from risk management activities, but excludes unrealized (gains) losses from risk management activities.

(2)Information is not meaningful since it only reflects only two months of electricity sales activity for fiscal year 2004.

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ITEM 7.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Executive Overview

Income before income tax expense was $41.9 million for the fiscal year ended June 30, 2008, an increase of $64.2 million from fiscal 2007.  Lower gross profit from our natural gas business and higher operating expenses were offset by higher unrealized gains from risk management activities and higher gross profit from our electricity business.

The average number of RCEs served for the fiscal year ended June 30, 2008 increased by 7% over the prior year.  The increase is related primarily to organic growth in electricity RCEs during the year, as well as the GasKey Acquisition in January 2008.

Sales of natural gas and electricity for the fiscal year ended June 30, 2008 were $752.3 million, an increase of $48.4 million (7%) compared to the prior fiscal year.  The increase in revenue was principally due to higher MWhr volumes sold and higher selling price per electricity MWhr.  A higher selling price per natural gas MMBtu sold also contributed to the increase in sales.  Contributing to the higher sales were:

·a full year’s impact of operations acquired from SESCo in fiscal 2008 (versus eleven months during the previous fiscal year);

·six months of activity from the GasKey operations, which were acquired in January 2008; and

·strong organic growth within the electricity business.

Increases in revenue noted above were partially offset by warmer-than-normal weather in Georgia, the Company’s largest natural gas market, and by normal customer attrition, which was partially offset by new customer growth.

Gross profit excluding unrealized gains and losses from risk management activities for the fiscal year ended June 30, 2008 totaled $115.5 million, a decrease of $3.3 million (3%) from the prior year.  The decrease is primarily due to:

·lower volumes of natural gas sold during fiscal year 2008; and

·unusually favorable market conditions for variable contract pricing in certain natural gas markets during the winter of fiscal year 2007, which resulted in a gross profit per MMBtu of natural gas sold for that period that exceeded the gross profit per MMBtu sold for the same period in fiscal year 2008.

Operating expenses excluding depreciation and amortization for the fiscal year ended June 30, 2008 were $73.9 million, an increase of $10.7 million (17%) from the prior year, primarily due to:

·higher overall expenses resulting from the Company’s investment in an expanded operational platform to support new or expanded electricity and natural gas markets;

·higher personnel-related and contractual expenses from continued expansion of the Company’s internal audit function and enhancement of the Company’s overall internal controls environment, including costs associated with implementation of the provisions of the Sarbanes-Oxley Act of 2002;

·higher contractual and personnel-related expenses from investment in the Company’s information technology platform, including integration of legacy information systems onto systems acquired from SESCo;

·incremental costs associated with the assessment of potential purchase acquisition opportunities; and

·one additional month of expenses related to operations acquired from SESCo in August 2006.

During fiscal 2008, approximately $3.6 million of expenses were incurred, primarily related to Sarbanes-Oxley compliance and the assessment of acquisitions, which are not expected to recur in future periods.

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Adjusted EBITDA

Management uses Adjusted EBITDA for various management purposes.  Refer to “Item 6. Selected Financial Data” for commentary regarding management’s use of Adjusted EBITDA.  Significant activity affecting Adjusted EBITDA is summarized in the following table.  Refer to “Results of Operations” below for commentary regarding the changes noted in this table.

	Fiscal Year Ended June 30,
	2008			2007			2006			2005			2004
	(in thousands)
Adjusted EBITDA for prior fiscal year	$	60,113		$	25,729		$	36,283		$	15,830		$	8,370
Increases (decreases) in Adjusted EBITDA due to:
Changes in gross profit, excluding unrealized (gains) losses from risk management activities:
Natural gas	(9,977		)	66,258			(8,568		)	29,004			13,773
Electricity	6,648			(331		)	2,420			703			787
Higher operating expenses, excluding depreciation, amortization and stock compensation expense	(11,843		)	(31,543		)	(4,406		)	(9,254		)	(7,100		)
Adjusted EBITDA for current fiscal year	$	44,941		$	60,113		$	25,729		$	36,283		$	15,830

Rising Commodity Prices

Fiscal year 2008 was a period of rising energy prices, particularly during the winter months, which had a direct impact on our business.  Cash generated from operations decreased significantly, due in large part to higher working capital requirements, particularly for purchases of natural gas and electricity for delivery to customers, and a higher allowance for doubtful accounts.  In addition, the rising price environment raised awareness of retail pricing options on the part of our current and potential customers, which resulted in competitive pressure on our fixed and variable prices and contributed to reduced gross profit for both natural gas and electricity.

Acquisition of the GasKey Division of PS Energy Group, Inc.

In January 2008, we completed the acquisition of substantially all of the retail natural gas assets of PS Energy Group, Inc., primarily including the natural gas customer contracts of their GasKey division.  Nearly all of the customers served under such contracts are located in Georgia.  We acquired approximately 60,000 RCEs in the GasKey Acquisition.  Consistent with our experience with previous acquisitions, we expect attrition for this portfolio to be higher than that experienced for customers acquired through organic growth.  The majority of accounts acquired are commercial and industrial customers for which we expect to earn gross profit that is lower than that for our traditional mass-market business.

Pursuant to the terms of the related Asset Purchase Agreement, we purchased the GasKey assets for a base amount of approximately $4.3 million, plus working capital, plus contingent consideration payable for volumes consumed on customer contracts acquired for a 36-month period subsequent to the acquisition date.  The final purchase price is subject to certain adjustments in accordance with the terms and conditions of the Asset Purchase Agreement.  We also assumed certain liabilities related to the GasKey assets, which is typical for this type of transaction.

Regulatory approval for the GasKey Acquisition was received in January 2008.  We recorded the transaction as a purchase business combination as of January 1, 2008.  The initial purchase price of $12.0 million, prior to the adjustments noted above, was paid from our available cash balance.  The assets acquired and related operations represent less than 10% of our consolidated assets and operations, including the acquired assets.

Pursuant to the Asset Purchase Agreement, we assumed the economic benefit and risk associated with the GasKey net assets effective November 1, 2007.  During the period from November 1, 2007 to December 31, 2007, we extended $13.6 million of credit to PS Energy Group, Inc., of which $9.0 million was loaned directly to PS Energy Group, Inc. and $4.6 million represented collateral and guarantees funded by us to fulfill LDC requirements related to the GasKey business.  Also during this period, we recorded cash receipts from accounts receivable, cash payments for natural gas inventory purchases and other operating expenditures related to the assets acquired and liabilities assumed in the GasKey Acquisition.  The $9.0 million loan to PS Energy Group, Inc. was repaid on the closing date.

The allocation of the purchase price for the GasKey Acquisition to various assets acquired and liabilities assumed is summarized in Note 4 to the consolidated financial statements included elsewhere in this Annual Report.

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Balance Sheet Overview

Guaranteed and Non-Guaranteed Accounts Receivable

Accounts receivable, net is summarized in the following table.

	Balances at June 30,
	2008				2007
	(in thousands)
Billed customer accounts receivable:
Guaranteed by LDCs	$		17,085		$		8,721
Non-guaranteed by LDCs	32,966				27,314
	50,051				36,035
Unbilled customer accounts receivable:
Guaranteed by LDCs	9,803				3,487
Non-guaranteed by LDCs	19,905				10,268
	29,708				13,755
Total customer accounts receivable	79,759				49,790
Less: Allowance for doubtful accounts	(5,154			)	(5,259			)
Customer accounts receivable, net	74,605				44,531
Imbalance settlements and other receivables	13,068				3,790
Accounts receivable, net	$	87,673			$	48,321

Billed customer accounts receivable represents uncollected revenues that have been billed directly to customers by the Company or on the Company’s behalf by certain LDCs.  Unbilled customer accounts receivable represents estimated revenues associated with natural gas and electricity consumed but not yet billed to customers under an LDC’s monthly cycle billing method.

The Company’s credit risk is limited as certain LDCs guarantee billed and unbilled customer accounts receivable or amounts due for delivered gas and electricity.  In cases where receivables are guaranteed by the LDC, we are exposed only to the credit risk of the LDC, rather than that of our actual customers.  As of June 30, 2008 and 2007, all of our of billed and unbilled customer accounts receivable in guaranteed markets was with LDCs who have received investment grade credit ratings.  We periodically review payment history, credit ratings and financial information for LDCs to ensure that we identify and respond to any deteriorating trends.

In the market areas where the LDC does not guarantee customer accounts receivable, the Company maintains an allowance for doubtful accounts that is based upon the credit risk of its customers, historical trends and other information.  Refer to Note 7 of the consolidated financial statements included elsewhere in this Annual Report for additional analysis of the Company’s allowance for doubtful accounts.  Bad debt expense associated with non-guaranteed accounts receivable was less than 1% for each of the fiscal years ended June 30, 2008, 2007 and 2006.

Imbalance settlements represent differences between the natural gas delivered to LDCs for consumption by our customers and actual usage by our customers.  Such imbalances are expected to be settled with cash from LDCs within the fiscal year following the balance sheet date.  Imbalance settlements will fluctuate from period to period depending on the market price for natural gas, weather patterns and other factors that affect customer consumption, and the timing of cash remittances from LDCs.  These receivables are due from LDCs with investment grade credit ratings.

The Company operates in 39 market areas located in 14 U.S. states and 2 Canadian provinces.  The Company’s diversified geographic coverage mitigates the credit exposure which could result from concentrations in a single LDC territory, or a single regulatory jurisdiction, from extreme local weather patterns or from an economic downturn in any single geographic region.

In addition, the Company has limited exposure to risk associated with high concentrations of sales volumes with individual customers.  For the fiscal years ended June 30, 2008 and 2007, the Company’s largest customer accounted for approximately 2% of total sales volume.

Refer to “Item 7A.  Quantitative and Qualitative Disclosures About Market Risk” for additional commentary regarding our approach for management of credit risk associated with customer accounts receivable.

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Customer Acquisition Costs, net

We acquire customers organically through direct marketing initiatives, through bulk acquisitions of customers and through business combinations.  During the fiscal year ended June 30, 2008, we recorded approximately $26.2 million of customer acquisition costs on the consolidated balance sheet, including $6.6 million added from the GasKey Acquisition, which are being amortized over their projected benefit period.  Capitalized customer acquisition costs grew significantly during fiscal 2008, as compared with previous fiscal years, as we shifted our marketing focus and resources during the year towards direct sales and marketing activities.  Much of the cost associated with these marketing channels were deferred as customer acquisition costs.

Long-Term Debt

As of June 30, 2008, we had $162.6 million of aggregate principal amount of Senior Notes outstanding, net of unamortized discount of $2.6 million.  During the fiscal year ended June 30, 2008, we acquired $12.8 million aggregate principal amount of outstanding Senior Notes from existing noteholders, resulting in a reduction of the Senior Notes on our consolidated balance sheet.  Refer to Note 15 of the consolidated financial statements included elsewhere in this Annual Report for additional information regarding the Senior Notes.

At June 30, 2007, we had $11.0 million of principal outstanding under the Denham Credit Facility.  In January 2008, the entire outstanding principal balance of the Denham Credit Facility was repaid.  Refer to Note 18 of the consolidated financial statements included elsewhere in this Annual Report for additional information regarding the Denham Credit Facility.

There was no long-term or revolving debt issued or drawn during the fiscal year ended June 30, 2008.

Redeemable Convertible Preferred Stock

Holdings is authorized to issue 5,000,000 shares of Series A convertible preferred stock.  On June 30, 2004, MXenergy Inc. entered into a purchase agreement (the “Preferred Stock Purchase Agreement”) with affiliates of Charterhouse Group Inc. and Greenhill Capital Partners LLC (collectively, the “Preferred Investors”) to issue 1,451,310 shares of Preferred Stock at a purchase price of $21.36 per share.  In 2005, as part of a corporate reorganization, MXenergy Inc. merged with and into a subsidiary of Holdings to become a wholly owned

subsidiary of Holdings and stockholders of MXenergy Inc. became stockholders of Holdings.  Total related offering expenses of approximately $1.6 million were deducted from the carrying value of the Preferred Stock, which resulted in a net carrying value of approximately $29.4 million at June 30, 2007.

On or after the fifth anniversary of the issuance of the Preferred Stock, if the fair market value of our common stock is at a level that would not provide the Preferred Investors with an annual rate of return of at least 25%, compounded annually, for the five-year period ending June 30, 2009, the Preferred Investors may require that we make a redemption election.  If the holders of the Preferred Stock require us to make a redemption election, and if we elect to redeem the Preferred Stock, the redemption amount is payable in cash equal to the greater of: (1) the fair market value of the shares of common stock into which the Preferred Stock may be converted on the date of the redemption election notice; or (2) the original issue price of $21.36 per share, plus any accrual of dividends.  If we elect not to redeem the Preferred Stock, we are required to grant the Preferred Investors effective control over Holding’s Board of Directors.  As of June 30, 2008, if the holders of Preferred Stock were to request that we make a redemption election, we do not have the intent or the ability to redeem the Preferred Stock due to limitations included in the agreements that govern the Revolving Credit Facility, the Hedge Facility and the Senior Notes.  However, since the Preferred Investors would effectively control our Board of Directors in the event that we do not elect to redeem the Preferred Stock, we have determined that, in accordance with U.S. GAAP, the Preferred Stock is redeemable at the option of the Preferred Investors and that it is probable that the Preferred Stock will become redeemable at June 30, 2009.  Therefore the carrying value of the Preferred Stock is recorded outside of stockholders’ equity on the consolidated balance sheets and has been adjusted to its estimated redemption value of $48.8 million as of June 30, 2008.  Refer to Note 16 of the consolidated financial statements for additional information regarding the Preferred Stock.

Results of Operations

Fiscal Year Ended June 30, 2008 Compared with Fiscal Year Ended June 30, 2007

Gross Profit by Business Segment

Gross profit by business segment is summarized in the following table.  For purposes of this analysis, gross profit includes fee income and realized losses from risk management activities, but excludes unrealized gains (losses) from risk management activities.  As the underlying customer contracts are not marked to market, the unrealized gains (losses) from risk management activities do not offer an accurate indication of the ultimate cash impact to the business, as the ultimate cash impact to the business is not determinable until delivery of natural gas under the customer contracts and the associated gain (loss) on risk management activity is realized.

	Fiscal Year Ended June 30,				2008 versus 2007 Increase (Decrease)
Business Segment	2008		2007		Amount			%
	($ in thousands)
Natural gas	$	105,303	$	115,280	$	(9,977	)	(9	)
Electricity	10,227		3,579		6,648			186
Total gross profit	$	115,530	$	118,859	$	(3,329	)	(3	)

Natural Gas Gross Profit

Average natural gas RCEs decreased 7% for fiscal 2008, which was the primary driver for 5% lower volume of natural gas MMBtus sold during fiscal 2008, as compared with the prior fiscal year.  Natural gas gross profit per MMBtu sold decreased 4% for the fiscal year ended June 30, 2008, as compared with the prior fiscal year.  Several factors contributed to the overall decrease in natural gas gross profit and gross profit per MMBtu sold.

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Volume Impact

The volume of natural gas MMBtus sold was 5% lower for the fiscal year ended June 30, 2008, as compared with the prior fiscal year.  In addition to lower average natural gas RCEs, higher than normal temperatures in Georgia, our largest natural gas market, also contributed to lower volumes of natural gas sold.  The reduction in gross profit associated with lower volumes of natural gas sold was approximately $4.8 million for the fiscal year ended June 30, 2008.

Variable Rate Plan Pricing Impact on Gross Profit

During fiscal year 2007, particularly during the three months ended March 31, 2007, we were able to acquire natural gas at market prices that were generally lower than the weighted average cost of gas of competing utilities within various natural gas markets where: (1) we have variable priced customers; (2) the local utility is a competitor; and (3) we do not own natural gas storage inventory.  In these markets, we were able to set variable rate prices at the higher end of the competitive range and still price below those offered by most local utilities, thus allowing us to realize higher gross profit on variable rate products than those realized for the three months ended March 31, 2008.  In contrast, natural gas prices increased significantly during the three months ended March 31, 2008, which prevented us from realizing comparable gross profit for variable rate products offered in these same markets.

Impact of SESCo Acquisition

Our results for fiscal year ended June 30, 2008 include a full twelve months of natural gas gross profit related to former SESCo operations, while our results for fiscal year 2007 include only eleven months of this activity.

Weighted Average Cost of Gas

Our application of weighted average cost accounting to the valuation of natural gas inventory assumes that all purchases of natural gas are initially capitalized as natural gas inventories in the consolidated balance sheet.  The resulting weighted average cost per MMBtu is then utilized to calculate the cost of natural gas subsequently sold.  As a result, when the price per MMBtu of natural gas purchased during a period is less than the weighted average cost per MMBtu of storage inventory at the beginning of the period, the weighted average cost per unit of storage inventory will be lower at the end of the period than at the beginning of the period.  The reduction in inventory value per MMBtu deferred in the balance sheet between the beginning and end of an operating period is reflected as an increase in cost of natural gas sold in the consolidated statement of operations for the period.

Conversely, for operating periods during which natural gas prices per MMBtu are greater during a period than the weighted average cost of storage inventory at the beginning of that period, the weighted average cost per unit of storage inventory will be higher at the end of the period than at the beginning of the period, resulting in lower cost of natural gas inventory sold for that period.

The impacts described above on the weighted average cost of gas are more pronounced in periods where we inject storage gas and have an increase in storage volume from the beginning to the end of the period.  March 31 represents the end of the annual storage inventory cycle.  As such, any weighted average cost of gas impact reflected through December 31 of each fiscal year is assumed to be realized through operations during the quarter ended March 31, as our storage inventory reaches its low point for the year and we prepare to begin the next injection cycle in April.

The effect on the weighted average cost of gas reflected through June 30, 2007 that benefited our results for the fiscal year ended June 30, 2008 exceeded the benefit for the comparable period in the prior year by approximately $2.6 million.

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Realized Losses from Risk Management Activities Related to Natural Gas Inventories Not Yet Sold

As we do not perform hedge accounting, realized gains (losses) from risk management activities includes net losses related to the settlement of risk management activities associated with natural gas inventories.  Offsetting net increases in gross profit should be realized in future periods as these inventories are sold.

During the fiscal year ended June 30, 2008, we recorded approximately $4.8 million of realized gains related to settlement of risk management activities associated with natural gas inventories, as compared to realized losses of $1.1 million for the prior fiscal year, resulting in a net $5.9 million positive comparative impact on natural gas gross profit.

Fee Income

Our gross profit includes fee income charged to customers primarily in Georgia and Texas, including monthly service fees, late payment fees and shut-off/reconnect service fees.  Fee income was $2.3 million higher for the fiscal year ended June 30, 2008, as compared with the prior fiscal year.  Higher fee income resulted primarily from growth in the number of electricity customers, the GasKey Acquisition in January 2008, and the inclusion of an additional month of SESCo operations.

Electricity Gross Profit

Electricity gross profit, excluding unrealized losses from risk management activities, increased $6.7 million (188%) during the fiscal year ended June 30, 2008, as compared with the prior fiscal year.  Average electricity RCEs grew approximately 240% to approximately 68,000 for fiscal 2008, resulting in significantly higher volume of MWhrs sold.

The Vantage Acquisition during the final three months of fiscal 2007 added approximately 12,000 electricity RCEs and established a presence for us in Texas.  The main driver for higher electricity RCEs during fiscal 2008 was significant organic growth in our Texas, Massachusetts, Connecticut and New York market areas, which was largely due to targeted direct sales marketing activities and a wider range of products offered to customers.

Electricity gross profit per MWhr sold decreased 13% for the fiscal year ended June 30, 2008, as compared with the prior fiscal year.  As noted above, we have experienced significant growth in our Texas markets, where our average gross profit is generally lower due to the fact that our customers in this market are predominantly commercial and industrial accounts.  Introductory rates offered to new customers in our Northeastern U.S. markets, where we also experienced growth, also contributed to lower overall gross profit per MWhr sold.

In September 2008, Hurricane Ike caused extensive damage to the infrastructure for generating and delivering electricity to residential and commercial end-users along the eastern coast of Texas, which resulted in extended disruption of electricity service for Houston, Texas and the surrounding area.  We are currently assessing the impact of this disruption of service on our financial results for the three months ended September 30, 2008.

Operating Expenses

Operating expenses are summarized in the following table.

	Fiscal Year Ended June 30,				2008 versus 2007 Increase (Decrease)
	2008		2007		Amount		%
	($ in thousands)
General and administrative expenses	$	62,271	$	54,516	$	7,755	14
Advertising and marketing expenses	4,546		4,044		502		12
Reserves and discounts	7,130		4,725		2,405		51
Depreciation and amortization	32,698		27,730		4,968		18
Total operating expenses	$	106,645	$	91,015	$	15,630	17

General and Administrative Expenses

As a result of the SESCo Acquisition, we implemented a restructuring plan to move certain of our operations to Houston, Texas, beginning in the three months ended September 30, 2006.  During the fiscal year ended June 30, 2007, we incurred $1.2 million of charges (primarily severance, retention bonuses and reimbursement of relocation costs) related to this plan.  Also during fiscal 2007, we paid $0.8 million of bonuses to senior executives in recognition of their work on the SESCo Acquisition.

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In March 2008, the Compensation Committee of our Board of Directors approved the issuance of 19,000 total shares of common stock to two of our senior executives.  Total compensation expense related to issuance of these shares was approximately $1.7 million, which included the fair value of the common stock issued and additional compensation to offset the taxable nature of the shares to the employees.

Excluding the impact of the restructuring charges, bonuses and compensation expense from issuance of shares described above, general and administrative expenses increased $8.1 million (15%) for the fiscal year ended June 30, 2008 as compared with the prior fiscal year.  Throughout fiscal 2008, we continued various initiatives to enhance our corporate finance, billing, accounting operations, customer service, information technology, marketing and supply functions in support of business growth experienced during fiscal 2007.  In addition, we increased our staff headcount and incurred other costs to enhance our overall internal control environment, including our information technology and financial reporting controls.  The impacts of these initiatives include:

·Higher staffing levels, salaries, employee benefits, recruiting fees, professional fees and other general expenses related to expanding our customer billing, collections and customer services functions;

·Higher staffing levels, salaries, employee benefits and recruiting fees related to enhancing our overall internal controls environment for various corporate accounting and reporting functions;

·Higher professional fees related to supporting our development of a formalized internal audit function and our ongoing development of an internal controls environment that complies with the Sarbanes-Oxley Act of 2002; and

·Higher information technology expenses related to business growth and process improvement initiatives.  The principal objectives of these initiatives include the integration of legacy operations of the Company onto the customer relationship management system that served SESCo and the implementation of internal controls as described above.

In addition, we incurred an additional month of expenses during the fiscal year ended June 30, 2008, as compared to the prior fiscal year, related to the SESCo operations, which were acquired effective August 1, 2006.

Advertising and Marketing Expenses

During the three months ended September 30, 2007, we incurred significant expenses related to a multi-media campaign designed to support our direct sales activities in the Georgia market subsequent to the SESCo Acquisition.  Multi-media marketing expenditures slowed significantly during the nine months subsequent to September 30, 2007 after the Georgia campaign was completed.

Marketing expenses were lower for the final nine months of fiscal 2008 as a result of higher deferrals of customer acquisition costs, as compared with the prior fiscal year.  During fiscal 2008, we shifted our marketing focus and resources towards direct sales and marketing activities.  Much of the cost associated with these marketing channels are deferred as customer acquisition costs on our

consolidated balance sheet and amortized over a three-year estimated benefit period, which resulted in lower marketing expenses and partially offset higher multi-media advertising expenses during the first three months of the current fiscal year.

Reserves and Discounts

Reserves and discounts include the provision for doubtful accounts ($5.1 million and $3.0 million for the fiscal years ended June 30, 2008 and 2007, respectively) and contractual revenue-based discounts to certain LDCs ($2.1 million and $1.7 million for the fiscal years ended June 30, 2008 and 2007, respectively).

Higher provision for doubtful accounts for the fiscal year ended June 30, 2008 was partially due to higher total sales recorded for the period, and partially due to a higher concentration of revenues and receivables in the Georgia natural gas markets and Texas electricity markets for which we perform the billing function.  In relation to sales revenue, our provision and allowance for doubtful accounts are higher in these markets due to historical levels of bad debts that are generally higher than that for other markets that we serve.  The provision for doubtful accounts was less than 1% of sales of natural gas and electricity for each of the fiscal years ended June 30, 2008 and 2007.

As of June 30, 2008, we have not experienced a material change in the collectability of customer accounts receivable as a result of weak economic conditions in any of the markets that we serve.  We will continue to assess the adequacy of our allowance for doubtful accounts in light of current economic conditions and their impact on the ability of our customers and counterparties to remit balances to us when due.

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Depreciation and Amortization

Depreciation and amortization expense includes depreciation of fixed assets and amortization of customer acquisition costs.  Expenses for the fiscal year ended June 30, 2008 include an additional month of depreciation and amortization expense associated with fixed assets and customer acquisition costs from the SESCo Acquisition, which was completed on August 1, 2006.  Higher balances of customer acquisition costs have also resulted in higher amortization expense.

Interest Expense, net

Interest expense, net increased $1.1 million (3%) for the fiscal year ended June 30, 2008, as compared with the prior fiscal year.

Interest expense associated with the Senior Notes increased $4.0 million in fiscal 2008.  The Senior Notes were issued in connection with the SESCo Acquisition, which was completed in August 2006.  We incurred a full twelve months of interest expense related to the Senior Notes during the fiscal year ended June 30, 2008, as compared with eleven months of interest expense incurred during fiscal 2007, which resulted in approximately $1.9 million of additional interest expense for fiscal year 2008.

We utilize interest rate swap agreements to manage exposure to interest rate fluctuations on the Senior Notes.  Mark-to-market adjustments and interest expense associated with these swap arrangements are recorded as adjustments to interest expense, net.  Changes in the market value and higher interest expense related to interest rate swaps resulted in an overall increase of $3.8 million to interest expense, net for the fiscal year ended June 30, 2008, as compared with the prior fiscal year.

Excluding the impacts noted above of the mark-to-market adjustments and interest on the interest rate swaps and the additional month of interest during the fiscal year ended June 30, 2008, interest expense related to the Senior Notes decreased approximately $1.7 million during the fiscal year ended June 30, 2008, as compared with the prior fiscal year.  The weighted-average interest rate on the Senior Notes decreased to 11.9462% for fiscal 2008 from 12.9650% for the prior fiscal year.  Lower average debt balances resulting from our purchases of Senior Notes during fiscal 2008 and 2007 also resulted in generally lower interest expense on the Senior Notes for fiscal 2008.

During August 2006, we utilized a bridge loan from two investment banks to finance the SESCo Acquisition.  The bridge loan was repaid with proceeds from the sale of $190.0 million aggregate principal amount of the Senior Notes.  Fees and interest of $0.8 million associated with the bridge loan were charged to interest expense during the fiscal year ended June 30, 2007.  There was no comparable expense recorded during the fiscal year ended June 30, 2008.

We pay various fees to our hedge provider related to forward-hedged commodity volumes under the Hedge Facility.  These fees are deferred in other current assets on the consolidated balance sheets, and amortized to interest expense over the period of the hedged transactions.  Total interest expense associated with these fees were approximately $1.0 million and $2.8 million for the fiscal years ended June 30, 2008 and 2007, respectively.  Lower fees during fiscal year 2008 were primarily due to a lower volume of fixed hedge positions.

Income Tax (Expense) Benefit

Income tax (expense) benefit increased to an expense of $17.2 million for the fiscal year ended June 30, 2008 from a benefit of $8.5 million for fiscal year 2007, due to:

·the change to income before income tax expense of $42.0 million for the fiscal year ended June 30, 2008 from a loss before income tax benefit  of $22.3 million for fiscal year 2007; and

·a higher effective tax rate for fiscal year 2008, due mainly to changes in the mix and amounts of permanent differences, which was partially offset by a lower state statutory tax rate.

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Fiscal Year Ended June 30, 2007 Compared with Fiscal Year Ended June 30, 2006

During the fiscal year ended June 30, 2007, we benefited from a period of rapidly falling natural gas prices during the winter of 2007.  Utilities generally react much slower than us to changes in market commodity prices.  Prices offered by utilities during the quarter ended March 31, 2007 were much higher than the spot price of natural gas during those months.  We were able to price our variable price product below the price offered by utilities and purchase the physical natural gas at a lower prevailing spot price, substantially increasing our gross profit per MMBtu sold related to these contracts during the quarter, which contributed heavily to higher overall gross margins for the fiscal year ended June 30, 2007.

The average number of RCEs served for the fiscal year ended June 30, 2007 increased by 57% over the prior year.  The increase is related primarily to the acquisition of 315,000 RCEs from SESCo in August 2006 and, to a lesser extent, organic growth in electricity RCEs and to the Vantage Acquisition in May 2007.

Sales of natural gas and electricity for the fiscal year ended June 30, 2007 was $703.9 million, up $341.4 million (94%) compared to the prior year.  The increase in revenue was principally due to the SESCo acquisition and, to a lesser extent, to a higher number of electricity customers acquired through increased marketing activities.  The average selling price per MMBtu in fiscal 2007 increased over the prior year by $2.19, largely due to the higher price for natural gas when fixed price customers were added or renewed during the year, and to fee income realized from certain customers acquired from SESCo.  The SESCo Acquisition also resulted in higher volumes of MMBtus of natural gas sold during fiscal 2007.  However, the overall usage per customer decreased from the prior fiscal year as a result of warmer than normal weather experienced in the Midwestern and Northeastern U.S. during the six months ended March 31, 2007, which is the Company’s peak winter season for natural gas.

Gross profit (excluding unrealized gains and losses from risk management activities) for the fiscal year ended June 30, 2007 totaled $118.9 million, up $66.0 million (125%) from the prior year.  The increase is primarily due to the impact of the customers acquired from SESCo.

Operating expenses are summarized in the following table.

	Fiscal Year Ended June 30,				2007 versus 2006 Increase (Decrease)
	2007		2006		Amount		%
	($ in thousands)
General and administrative expenses	$	54,516	$	22,623	$	31,893	141
Advertising and marketing expenses	4,044		2,096		1,948		93
Reserves and discounts	4,725		3,395		1,330		39
Depreciation and amortization	27,730		8,504		19,226		226
Total operating expenses	$	91,015	$	36,618	$	54,397	149

Higher operating expenses during fiscal 2007, as compared with the prior fiscal year, primarily resulted from higher overall costs associated with the customers and operations acquired from SESCo.  Incremental SESCo-related costs included $1.2 million in rationalization expenses to transition operations to Houston, Texas and $0.8 million of bonuses paid to senior management in connection with the acquisition.  In addition, personnel-related expenses were higher as we increased staffing levels and incurred incremental contracted expenses to:

·improve our overall internal control environment, including the segregation of duties within various operational and accounting areas;

·hire a “Big four” accounting firm to become our internal audit service provider; and

·prepare, review and audit registration statements and periodic reports required to be filed with the SEC for fiscal year 2007, which was our first year as an SEC registrant.

During fiscal 2007, approximately $4.3 million of expenses were incurred, primarily related to the SESCo Acquisition and to assessment of other purchase acquisition opportunities, which are not expected to recur in future periods.

Reserves and discounts include the provision for doubtful accounts ($3.0 million and $1.6 million for the fiscal years ended June 30, 2007 and 2006, respectively) and contractual revenue-based discounts to certain LDCs ($1.7 million and $1.8 million for the fiscal years ended June 30, 2007 and 2006, respectively).  Higher provision for doubtful accounts was primarily due to higher revenues and customer accounts receivable balances resulting from the SESCo Acquisition.

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For the year ended June 30, 2007, we recorded an $8.5 million income tax benefit compared to $27.0 million in the prior year. The decrease from the prior year is primarily attributable to the decrease in pre-tax losses between the periods, of which all significant changes were previously discussed.

Liquidity and Capital Resources

Our principal sources of liquidity for funding our ongoing operations are cash collected from sales of natural gas and electricity to customers and borrowings under our Revolving Credit Facility.  Our primary liquidity requirements arise from obligations incurred in connection with customer acquisition costs, the funding of our overall seasonal working capital needs, including purchases of natural gas inventories, collateral requirements and ongoing debt service obligations.  Because we sell natural gas and electricity, we are subject to material variations in short-term indebtedness under our Revolving Credit Facility on a seasonal basis, due to the timing and price of commodity purchases to meet customer demands.

Cash Flow

During the fiscal year ended June 30, 2008, our cash and cash equivalents decreased $65.0 million to a balance of $72.0 million at the end of the period.  Approximately $8.6 million of cash was used for operating activities during the period, which reflects a $97.6 million change from the $89.0 million provided by operations for fiscal year 2007.  Of this overall decrease in cash from operating activities, $58.0 million was used to fund higher accounts receivable, net and natural gas inventory, primarily due to the following:

·Our average price paid for natural gas inventory was $3.64 (48%) per MMBtu higher for the fourth quarter of fiscal year 2008, as compared with the same period of prior fiscal year;

·Electricity RCEs increased approximately 55,000 (128%) during fiscal year 2008 to 98,000 at June 30, 2008 due to significant organic growth in the northeastern U.S. and in the State of Texas;

·Natural gas RCEs increased 14,000 (2%) during fiscal year 2008 to 602,000 at June 30, 2008.  As a result of the GasKey Acquisition, we are now serving more commercial and industrial customers, which have a higher usage of natural gas in the summer months than our typical residential and small commercial customers.  Higher usage related to these customers has contributed to an increase in customer accounts receivable and natural gas inventory balances at June 30, 2008, as compared with June 30, 2007; and

·During the fiscal year ended June 30, 2007, we received approximately $12 million of incremental cash related to customers acquired from SESCo that had contract terms above market rates.  No comparable incremental cash was received during fiscal year 2008. 

The remaining $39.6 million decrease in cash from operating activities was primarily due to lower operating profit, excluding unrealized gains or losses from risk management activities and non-cash expenses such as depreciation, amortization and stock compensation expense.

We also used cash for the following material investing and financing activities during the fiscal year ended June 30, 2008:

·$12.4 million was paid to PS Energy Group, Inc. related to the GasKey Acquisition;

·$19.6 million was used for investment in customer acquisition costs;

·$12.0 million was used to acquire outstanding Senior Notes from existing bondholders; and

·$11.0 million was used to repay all outstanding borrowings under the Denham Credit Facility.

Revolving Credit Facility

We utilize our Revolving Credit Facility primarily to post letters of credit required to effectively operate within the markets that we serve.  As of June 30, 2008, MXenergy Inc. and MXenergy Electric Inc., as borrowers under our Revolving Credit Facility, were permitted to borrow or utilize letters of credit up to the lesser of: (1) $280.0 million; and (2) the amount of the then applicable borrowing base, which represents the aggregate of specific advance rates against cash, customer accounts receivable, natural gas inventory and imbalance receivables.  The expiration date of our Revolving Credit Facility was December 19, 2008, at which time any outstanding principal amounts would have become due.  Borrowings under our Revolving Credit Facility bore interest at a fluctuating rate based upon a base rate or a Eurodollar rate plus an applicable margin.  As of June 30, 2008, the applicable margin for base rate loans was 1.00% per annum and the applicable margin for Eurodollar loans was 2.00% per annum.  As of June 30, 2008, the fees associated with issuing letters of credit under the Revolving Credit Facility were 1.75% per annum.

At June 30, 2008, the total available borrowing base under our Revolving Credit Facility was $193.9 million, of which $147.9 million was utilized in the form of outstanding letters of credit.  We did not draw any borrowings under our Revolving Credit Facility during the fiscal year ended June 30, 2008, and there were no cash borrowings outstanding under our Revolving Credit Facility at June 30, 2008.

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On September 30, 2008, the agreement that governs the Revolving Credit Facility was amended and restated. The amended and restated agreement includes the following amendments to the previous agreement:

· The maturity date of the Revolving Credit Facility was extended through July 31, 2009.

· The maximum amount that the Company is permitted to borrow was reduced to $255.0 million. The amendment allows for new lenders to be added to the Revolving Credit Facility subsequent to closing, which could increase the maximum amount available for the Company to borrow to $280.0 million.

· The Company paid an upfront amendment closing fee of 0.75% of the aggregate commitment under the Revolving Credit Facility, which will be amortized to interest expense from October 2008 through July 2009.

· The margins for base rate loans were increased by 1.00%.

· The fee associated with issuing letters of credit was increased to 2.75% per annum. Various other fees under the facility were also increased.

· The Company is required to borrow any available balance under the Denham Credit Facility no later than November 7, 2008.

· The Company may not acquire customer portfolios or operations of other companies in excess of $100,000 without explicit approval by lenders holding a majority of the commitments under the Revolving Credit Facility.

· The maximum Average Leverage Ratio (average debt for the 12 months preceding a reporting period, divided by adjusted EBITDA for the same period) for the period from February 1, 2009 through the expiration date was lowered to 3.75 from 4.00.

In December 2007, the agreement governing our Revolving Credit Facility was amended as follows:

· To allow us to utilize up to $12.0 million of operating cash to acquire outstanding Senior Notes for a price equal to or less than 100% of their face value (see “Senior Notes” below for additional information); and

· To amend a debt covenant to allow (1) a reduction of the minimum consolidated working capital requirement from $145.0 million to $138.5 million; and (2) dollar-for-dollar adjustments to minimum consolidated working capital for: (a) use of up to $12.0 million of cash to acquire Senior Notes; (b) repayment of any principal balances outstanding under the Denham Credit Facility using cash; and (c) cash provided from any subsequent principal draws under the Denham Credit Facility.

In May 2008, the agreement governing the Revolving Credit Facility was further amended, effective March 1, 2008, as follows:

· We are required to maintain an average leverage ratio (e.g., average debt for the 12 months preceding a reporting period, divided by adjusted EBITDA for the same 12-month period) that is not allowed to exceed specified amounts for various time periods that extend through the agreement termination date, as defined in the agreement. The maximum ratios allowed under the agreement were increased for the period March 1, 2008 through the termination date of the Revolving Credit Facility as a result of the amendment.

· We are required to maintain minimum interest coverage ratios (e.g., adjusted EBITDA for the 12 months preceding a reporting period, divided by cash interest expense for that same 12-month period) for various time periods that extend through the agreement termination date, as defined in the agreement. The minimum ratios required under the Revolving Credit Facility were decreased for the period March 1, 2008 through August 31, 2008 as a result of the amendment.

The Revolving Credit Facility contains customary covenants that restrict certain of our activities including, among others, limitation on capital expenditures, disposal of property and equipment, additional indebtedness, issuance of capital stock and dividend payments.  Financial covenants under the Revolving Credit Facility include, among others, minimum tangible net worth, minimum working capital and interest coverage, each as defined in the agreement that governs the Revolving Credit Facility.  The Revolving Credit Facility also contains customary events of default.  We were in compliance with all covenants associated with our debt agreements as of June 30, 2008.

We are currently considering options for negotiating renewal or extension of our Revolving Credit Facility, or for negotiating a new lending facility with new lenders.  Although we expect that we will be able to renew, extend or replace the existing facility, no assurances can be made that we can do so on terms that will be favorable to us in comparison with our Revolving Credit Facility or at all.

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Hedge Facility

Although we engage in hedging activities with various counterparties for electricity, we utilize the Hedge Facility as our primary hedge facility for natural gas.  Under the Hedge Facility, we utilize NYMEX referenced over-the-counter swaps, basis price swaps and options to hedge the risk of variability in the cost of natural gas.  The Hedge Facility is secured by a first lien on customer accounts receivable and by a second lien on substantially all other assets.  We posted an initial balance of $25.0 million in cash collateral (obtained from proceeds from the sale of the Senior Notes) for potential negative mark-to-market changes in the value of the forward hedge position.  Under the Hedge Facility, we have the flexibility to post either cash collateral or issue a letter of credit as margin for the Hedge Facility.  Prior to March 1, 2008, we were not required to post additional collateral beyond the initial margin requirements unless our NYMEX referenced forward swap hedge positions exceeded 65,000,000 MMBtus.  As a result of an amendment to the agreement governing the Hedge Facility, effective March 1, 2008, we will not be required to post additional collateral unless our NYMEX referenced forward swap hedge positions exceed 35,000,000 MMBtus.  At June 30, 2008, our NYMEX referenced forward swap hedge positions and the unrealized gains related to those positions totaled approximately 13,967,000 MMBtus and $43.8 million, respectively.  At June 30, 2008, we posted a $25.0 million letter of credit as margin under the Hedge Facility.

The agreement governing the Hedge Facility was amended in March 2008 and July 2008, as follows:

· In July 2008, the termination date was extended to the earlier of August 1, 2009 or thirty days prior to expiration of the Revolving Credit Facility. As a result of extension of the Revolving Credit Facility to July 31, 2009, the Hedge Facility is currently due to expire on July 1, 2009.

· In July 2008, the collateral requirement was amended to require us to increase the posted amount from $25.0 million to $35.0 million if our mark-to-market exposure under the Hedge Facility exceeds $25.0 million;

· Prior to March 1, 2008, we were not required to post additional collateral beyond the initial margin requirements unless the amount of NYMEX referenced forward swap hedge positions exceeded 65,000,000 MMBtus. As a result of an amendment to the agreement governing the Hedge Facility, effective March 1, 2008, we will not be required to post additional collateral unless its NYMEX referenced forward swap hedge positions exceed 35,000,000 MMBtus. In July 2008, this limit was further reduced to 25,000,000 MMBtus.; and

· Certain financial covenants, which are the same as those included in the agreement governing the Revolving Credit Facility were also amended.

In September 2008, we increased the letter of credit posted as margin to $35.0 million because our mark-to-market exposure exceeded $25.0 million.

We are currently considering options for negotiating renewal or extension of the current Hedge Facility, or for negotiating a new hedge facility with new hedge providers.  Although we expect that we will be able to renew, extend or replace the existing facility, no assurances can be made that we will be able to do so on terms that will be favorable to us relative to the terms of our Hedge Facility or at all.

Senior Notes

On August 4, 2006, we issued $190.0 million aggregate principal amount of Senior Notes, which mature on August 1, 2011 and bear interest at a rate equal to LIBOR plus 7.5% per annum.  The interest rate on the Senior Notes was 12.9006% at June 30, 2007.  The interest rate was reset to 12.8125% on August 1, 2007, 10.6863% on February 1, 2008 and 10.6250% on August 1, 2008.  The weighted-average interest rate was 11.9462% and 12.9650% for the fiscal years ended June 30, 2008 and 2007, respectively.  We have entered into interest rate swap agreements to hedge the floating rate interest expense on the Senior Notes.  Refer to Note 8 to the consolidated financial statements included elsewhere in this Annual Report for additional information regarding the interest rate swaps.

During the fiscal year ended June 30, 2007, we purchased $12.0 million aggregate principal amount of Senior Notes outstanding, plus accrued interest, from a noteholder for an amount less than face value.  We used borrowings under the Denham Credit Facility to acquire such Senior Notes.  This transaction resulted in a gain on early extinguishment of debt of approximately $1.0 million, which was recorded as a reduction of interest expense for the fiscal year ended June 30, 2007.  We also recorded as additional interest expense $0.6 million of original issue discount and debt issuance costs for the fiscal year ended June 30, 2007, which represents a pro rata portion of such costs that were deferred at the issuance date of the Senior Notes.

During the fiscal year ended June 30, 2008, we utilized cash and cash equivalents to acquire $12.8 million aggregate principal amount of outstanding Senior Notes from noteholders, in each case, for an amount less than face value.  These transactions resulted in $0.8 million of aggregated gains on the early extinguishment of debt that was recorded as a reduction of interest expense for the fiscal year ended June 30, 2008.  We also recorded as additional interest expense $0.5

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million of original issue discount and debt issuance costs for the fiscal year ended June 30, 2008, which represents a pro rata portion of such costs that were deferred at the issuance date of the Senior Notes.

On or before August 1, 2009, upon an equity offering, we may redeem up to 35% of the aggregate principal amount of the Senior Notes at a price equal to 100% of the principal amount, plus a premium equal to the rate per annum on the Senior Notes outstanding on the date notice is given to redeem the Senior Notes plus accrued and unpaid interest to the redemption date.  As of June 30, 2008, we have not given notice of any intention to redeem any of the Senior Notes.

If a change of control, as defined in the indenture governing the Senior Notes, were to occur, we would be obligated to make an offer to purchase the Senior Notes, in whole or in part, at a price equal to 101% of the aggregate principal amount of the Senior Notes, plus accrued and unpaid interest, if any, to the date of purchase.  If a change of control were to occur, we may not have the financial resources to repay all of our obligations under the Senior Notes.  During the fiscal year ended June 30, 2008, there was no change in control, as defined in the indenture, which would obligate us to purchase the Senior Notes.

Denham Credit Facility

The Denham Credit Facility is a $12.0 million line of credit that bears interest at 9% per annum.  In December 2007, the agreement governing the Denham Credit Facility was amended to allow us to make principal draws until November 14, 2008.  In January 2008, we repaid the entire $11.0 million outstanding principal balance of the Denham Credit Facility.  The termination date for the Denham Credit Facility is May 19, 2010, at which time any outstanding principal balance will become due as of June 30, 2008, no amounts were outstanding under the Denham Credit Facility.

In accordance with the amended and restated agreement that governs our Revolving Credit Facility entered into on September 30, 2008, we are required to borrow any available balance under the Denham Credit Facility prior to November 7, 2008, and to maintain such balance outstanding until the Revolving Credit Facility expires on July 31, 2009.  In September 2008, we borrowed the entire $12.0 million balance available under the Revolving Credit Facility.

Redeemable Convertible Preferred Stock

At any time on or after the fifth anniversary of the issuance of the Preferred Stock, we may redeem all, but not less than all, of the outstanding shares of Preferred Stock with cash if, as of the date notice of redemption is given, the fair market value of our common stock is at a level that would provide an annual rate of return of not less than 40%, compounded annually, to the majority of the Preferred Investors.  The redemption price would be equivalent to the fair market value of our common stock on the redemption date.

On or after the fifth anniversary of the issuance of the Preferred Stock, if the fair market value of our common stock is at a level that would not provide the Preferred Investors with an annual rate of return of at least 25%, compounded annually, for the five-year period ending June 30, 2009, the Preferred Investors may require that we make a redemption election.  If we elect to redeem the Preferred Stock, the redemption amount is payable in cash equal to the greater of: (1) the fair market value of the Shares of common stock into which the Preferred Stock may be converted on the date of the redemption election notice; or (2), the original issue price of $21.36 per share, plus any accrual of dividends or dividends in arrears.  However, our ability to redeem the Preferred Stock is limited by debt covenants and other provisions of the agreements governing the Hedge Facility, the Revolving Credit Facility and the Senior Notes.  We are unlikely to have the available liquidity to redeem the Preferred Stock for cash.  Therefore, we do not intend to elect to redeem the Preferred Stock if requested to make such election by the Preferred Investors.

If we elect not to redeem the Preferred Stock, we are required to grant effective control of our Board of Directors to the Preferred Investors.  With this effective control over our Board of Directors, the Preferred Investors could attempt to cause us to redeem the Preferred Stock.  However, as noted above, our ability to redeem the Preferred Stock is limited by various agreements and by a probable lack of liquidity necessary to redeem the Preferred Stock for cash.  Therefore, management does not believe that redemption is probable if the Preferred Investors are granted effective control over our Board of Directors without a substantial new equity investment to provide adequate liquidity to do so.

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Agency Credit Ratings

Our credit ratings as of June 30, 2008 are summarized in the following table.

	Standard & Poor’s	Moody’s Investors Service
Corporate Rating	B	B3
Senior Notes	CCC+	Caa1
Ratings outlook	Negative	Stable

In May 2008, Standard & Poor’s downgraded our ratings outlook to ‘Negative’ from ‘Stable’, due principally to a decline in Adjusted EBITDA and its impact on certain debt covenants.  Although Moody’s Investors Service did not revise their ratings for us during fiscal year 2008, they have notified us that we are likely to be reviewed in the upcoming months.

Our credit ratings are subject to further review, revision or withdrawal at any time by any rating agency if, in its judgment, circumstances so warrant.  If the rating agencies downgrade or withdraw our ratings, our access to capital markets could be significantly limited and our costs of borrowing, including the interest rate for future financings, may increase.

Summary of Contractual Obligations

The following table discloses aggregate information about our contractual obligations and commercial commitments as of June 30, 2008:

	Contractual Obligation Amounts Maturing In
	Less Than 1 Year		1-3 Years		4-5 Years		Thereafter		Total
	(in millions)
Floating Rate Senior Notes due 2011 (1)	$	—	$	165.2	$	—	$	—	$	165.2
Hedge Facility (2)	1.2		.2		—		—		1.4
Operating leases	1.0		1.0		0.4		1.1		3.5
Natural gas physical purchase commitments (3)	92.4		3.9		—		—		96.3
Electricity physical purchase commitments (3)	11.0		3.4		—		—		14.4
Total	$	105.6	$	173.7	$	0.4	$	1.1	$	280.8

(1)	Amount excludes $2.6 million of original issue discount and annual interest expense, which averaged approximately $21.0 million for both of the fiscal years ended June 30, 2008 and 2007.
(2)	Amount represents monthly facility management fees.
(3)	Includes both fixed and variable portions of physical forward contracts. The variable portion is indexed as the NYMEX settle price for the corresponding delivery month in which the natural gas is purchased. The estimated contractual obligations are based on the NYMEX forward curve as of June 30, 2008 for all corresponding delivery months.

Amounts in the table exclude any amounts that may be payable to the Preferred Investors if a redemption were to occur on or after June 30, 2009 because the timing and amount of any such redemption is not certain as of June 30, 2008. Refer to Note 16 to our consolidated financial statements included elsewhere in this Annual Report for additional information regarding Preferred Stock.

Also excluded from the table is $12.0 million borrowed under our Denham Credit Facility in September 2008.  All amounts outstanding under the Denham Credit Facility are due in May 2010.

In addition, we are required to provide collateral in the form of cash or letters of credit related to activity under our Hedge Facility, commodity supplier agreements, transportation and storage arrangements.  At June 30, 2008, we posted a $25.0 million letter of credit as collateral under our Hedge Facility, $77.3 million of letters of credit as collateral under various supplier agreements and $45.6 million of letters of credit under various transportation and storage agreements.  As of June 30, 2008, all outstanding letters of credit were scheduled to mature during fiscal 2009.

Off-Balance Sheet Arrangements

We did not have any off-balance sheet arrangements as of June 30, 2008 or 2007.

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Critical Accounting Policies

The preceding discussion and analysis of our financial condition and results of operating results are based on our consolidated financial statements, which have been prepared in conformity with U.S. GAAP.  The significant accounting policies used in the preparation of our consolidated financial statements are more fully described in Note 2 of the consolidated financial statements included elsewhere in this Annual Report.

Many of our significant accounting policies require complex judgments to estimate values of assets and liabilities.  In making these judgments, management must make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses.  Because changes in such estimates and assumptions could significantly affect our reported financial position and results of operations, detailed policies and control procedures have been established to ensure that valuation methods, including judgments made as part of such methods, are well controlled, independently reviewed, and are applied consistently from period to period.

On an on-going basis, we evaluate our estimates, which are based on historical experience, weather data, terms of existing customer contracts, and various other assumptions that we believe to be reasonable under the circumstances.  Our actual results may differ from these estimates and assumptions.

Of the significant policies used to prepare our consolidated financial statements, the items discussed below require critical accounting estimates involving a high degree of judgment and complexity.  For all of these critical policies, we caution that future events rarely develop exactly as forecasted, and the best estimates routinely require adjustment. This information should be read in conjunction with our consolidated financial statements included elsewhere in this Annual Report.

Revenue Recognition

We recognize revenue from the sale of natural gas and electricity in the period in which the commodity is consumed by customers.  Our customers are billed monthly on various dates throughout the month.  We accrue for revenues applicable to gas and electricity consumed by customers but not yet billed under the cycle billing method.  These unbilled revenues are determined by considering the following factors: (1) estimates of the volume consumed by customers during a calendar month; (2) the average sales price per unit for each respective market area or customer class; (3) the volumes delivered to the LDC during the calendar month; and (4) the timing of billings completed under the cycle billing method.  These estimates are adjusted to actual billings in subsequent periods when the meters are read and any change in previous estimates is reflected in operations during the period that the change is determined.  Revenue recognition is considered to be a critical accounting policy due to the following factors:

· Volume estimates are dependent upon projected weather conditions, which in turn are based upon historical temperature trends. Actual weather conditions may differ from historical averages; and

· Due to the seasonality of our business, such estimates may vary significantly from quarter to quarter.

Allowance for Doubtful Accounts

We assume the credit risk associated with non-payment by our customers in markets where LDCs do not guarantee the customer accounts receivable.  In those markets, we record an allowance for doubtful accounts based on the age of accounts receivable, customer payment history, past loss experience and current market conditions.  We recognize that there is a high degree of subjectivity and imprecision inherent in the process of estimating future credit losses that are based on historical trends and customer data.  Critical factors that could impact the recorded level of allowances for doubtful accounts include:

·Economic trends and conditions in the markets we serve, which may deteriorate and impact the ability of our customers to pay balances owed to us; and

·Higher concentrations of our business in certain markets, such as Georgia and Texas, which could expose us to higher losses if economic conditions in those specific markets were to deteriorate.

We are also subject to credit risk associated with the creditworthiness of LDCs that guarantee customer accounts receivable balances.  Although the LDCs that guarantee our customer accounts receivable have investment grade credit ratings, any detrimental change in the creditworthiness of these LDCs could affect their ability to pay us amounts when due, and may result in the need for higher allowances and provisions for doubtful accounts.

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Goodwill

Goodwill is not amortized, but is reviewed for impairment at least annually or more frequently if events or changes in circumstances indicate that the carrying amount may not be recoverable.  Goodwill is tested for impairment during the fourth quarter of our fiscal year.  We utilize a discounted cash flow methodology for our impairment testing, which gives consideration to significant and long-term changes in industry and economic conditions as primary indicators of potential impairment.

Goodwill of $3.8 million on our consolidated balance sheet represents the excess of purchase price over the fair value of identifiable net assets acquired from SESCo in August 2006.   The goodwill related to the SESCo Acquisition was recorded at June 30, 2007, which is the date that the purchase allocation was finalized.  The goodwill has been assigned entirely to the natural gas business segment since the customers acquired in the SESCo Acquisition were primarily natural gas accounts.  It is our current policy to conduct a formal test for impairment of goodwill using an annual testing date of June 30.

Impairment testing of goodwill is considered to be a critical accounting estimate due to the significant judgment required in the use of discounted cash flow models to determine fair value.  Assumptions used involve a high degree of subjectivity and are based on historical experience and internal forecasts of future results.  Actual results in future periods may not necessarily approximate historical experience or forecasts.

For the purpose of testing for goodwill impairment, we have elected to use a valuation technique that is based on a multiple of earnings.  The fair value of our natural gas net assets are calculated using a similar earnings forecasting model as that used for our annual forecast and for our common stock valuation model.  Critical assumptions used for the fair value model, include:

·Growth in natural gas RCEs, net of attrition, and related growth in the volume of natural gas MMBtus sold;

·Expected natural gas gross profit per MMBtu sold;

·Expense trends; and

·The discount rate to calculate the present value of future earnings.

We conducted our initial annual goodwill impairment test as of June 30, 2008, and have concluded that there was no impairment of goodwill as of that date.

Customer Acquisition Costs, net

Customer acquisition costs are comprised of: (1) customer contracts acquired through bulk acquisitions and business combinations; and (2) direct sales and advertising costs, which consist primarily of direct-response hourly telemarketing, non-hourly telemarketing and door-to-door marketing costs incurred through independent third parties, and which are associated with proven customer generation.

Customer acquisition costs are capitalized and generally amortized over the estimated life of a customer, which we currently estimate to be three years.  Customer acquisition costs that are subject to amortization are reviewed for recoverability quarterly, or whenever events or changes in circumstances indicate that the carrying amount may not be recoverable.  Examples of such events or changes in circumstances include the following:

·A significant decrease in the market value of an acquired asset;

·A significant change in the extent or manner in which the asset is used, or a significant change in its physical condition;

·A significant adverse change in the legal factors or in the business climate that could affect the value of the asset, including an adverse action or assessment by a regulator;

·An accumulation of costs significantly in excess of the amount originally expected to acquire the asset;

·A current period operating or cash flow loss combined with a history of operating or cash flow losses or a projection of continued loss;

·A current expectation that, more likely than not, the asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.

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Our model used to assess the estimated recoverability of customer acquisition costs includes estimates of the future cash flows expected to result from the use of the customer assets and their eventual disposition.  The estimated fair value resulting from this model is compared with the carrying amount of the asset.  If impairment were to be identified, it could result in additional expense recorded in our consolidated statement of operations.  Estimation of future cash flows includes consideration of specific assumptions for customer attrition, per unit gross profit, and operating costs.  The estimate of future cash flows is considered to be a critical estimate because the assumptions used involve a high degree of subjectivity and are based on historical experience and internal forecasts of future results.  Actual results in future periods may not necessarily approximate historical experience or forecasts.

The average three-year life of a customer is also considered to be a critical assumption because it is an estimate of the expected period over which an average customer will provide us with cash flows.  If competitive market conditions were to deteriorate for us, customer attrition could increase, which could result in a lower average life of a customer.

As a result of all quarterly reviews conducted for the fiscal year ended June 30, 2008, we have concluded that there was no impairment to the carrying value of customer acquisition costs recorded on our consolidated balance sheets.

Income Taxes

The calculations of income tax expense and related balance sheet amounts involve a high degree of management judgment regarding estimates of the timing and probability of recognition of revenue and deductions by taxing authorities.  In assessing the likelihood of realization of deferred tax assets, management considers estimates of the amount and character of future taxable income.  Actual income taxes expensed and/or paid could vary from estimated amounts due to the impacts of various items, including:

·changes to tax laws by taxing authorities;

·final review of filed tax returns by taxing authorities; and

·actual financial condition and results of operations of future periods that could differ from forecasted amounts.

In management’s opinion, adequate reserves have been recorded for any future taxes that may be owed as a result of examination by any taxing authority.  Refer to Note 12 of the consolidated financial statements, included elsewhere in this Annual Report, for additional information regarding tax matters.

Derivatives

We utilize both physical and derivative financial instruments to reduce our exposure to fluctuations in the price of natural gas and electricity.  Settlements on derivative financial instruments are realized on a monthly basis, generally based upon the difference between the contract price and the settlement price as quoted on NYMEX or other published indices.  All derivative financial instruments are carried on the balance sheet at fair value.  Any changes in fair value are adjusted through unrealized losses (gains) from risk management activities in the consolidated statements of operations. This accounting results in significant volatility in earnings due to the impact market prices have on the market positions and financial instruments that we have entered into.  In determining the fair value of derivative financial instruments, we use quoted market prices whenever possible.  As of June 30, 2008, less than 1% of the notional values of all derivative financial instruments outstanding were valued using non-quoted prices.

If quoted market prices are not available, quotes from third party brokers or internally-developed pricing models that are based on various assumptions and management judgment are used.  Although the total notional value of these instruments is not material at June 30, 2008, the assumptions used for these pricing models are considered to be critical estimates due to the high level of management judgment utilized in their development.

We have implemented risk management controls and limits to monitor our risk position related to derivatives and to ensure that hedging performance is in line with agreed-upon objectives (refer to “Item 7A. Quantitative and Qualitative Disclosures About Market Risk”).

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Redeemable Convertible Preferred Stock

The holders of Preferred Stock have rights, subject to certain limitations, for redemption of their Preferred Stock, for conversion of their Preferred Stock into common stock, or to receive dividends.  Under certain circumstances, the appropriate redemption, conversion and dividend amounts are dependent upon the fair value of our common stock.  Because our common stock is not publicly traded, we obtain an independent valuation for the fair value at June 30 of each fiscal year.  For the three month periods ended September 30, December 31, and March 31 of each fiscal year, we calculate the fair value of our common stock using an internally developed model that approximates the independent model.  The models used to calculate the fair value of our common stock are considered to be critical accounting estimates because the assumptions used involve a high degree of subjectivity and are based on historical experience and internal forecasts of future results.  Actual results in future periods may not necessarily approximate historical experience or forecasts.

Because our common stock is not publicly traded and we have limited historical stock price data, expected stock price volatilities used in the common stock valuation models are estimated based on historical realized volatilities of comparable publicly traded company stock prices over a period of time commensurate with the expected term of the option award.

Stock-Based Compensation

We currently have three stock-based compensation plans in effect, under which warrants and options have been granted to employees, non-employees and directors.  We use the Black-Scholes-Merton option-pricing model for estimating the fair value of awards granted after June 30, 2006.  The Black-Scholes-Merton option-pricing model was developed for use in estimating the fair value of traded options which have no vesting restrictions and are fully transferable.  In addition, option-pricing models require the input of highly subjective assumptions, including expected stock price volatility, expected term of the option award, expected annual forfeiture rate and risk-free interest rate.  These assumptions are primarily based on historical experience that may not necessarily approximate future results.

For awards of warrants and options granted prior to July 1, 2006, expense recorded in our statements of operations may fluctuate from reporting period to reporting period based upon the calculated fair value of our common stock.  Because our common stock is not publicly traded, we use valuation models to calculate fair value.  Refer to “Redeemable Convertible Preferred Stock” above for commentary regarding the models used to calculate the fair value of our common stock.

Because our stock options and warrants have characteristics significantly different from those of traded options, and because changes in the subjective assumptions used in the valuation models can materially affect fair value estimates, the existing models do not necessarily provide a reliable single measure of the fair value of our stock options.

New Accounting Pronouncements

Accounting Pronouncements Adopted During the Fiscal Year Ended June 30, 2008

In June 2006, the Financial Accounting Standards Board (the “FASB”) issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes–an interpretation of FASB Statement No. 109” (“FIN No. 48”).  FIN No. 48 establishes threshold and measurement attributes for financial statement recognition and measurement of tax positions taken or expected to be taken in a tax return.  FIN No. 48 also provides guidance on de-recognition of a previously recognized tax position, classification, interest and penalties, accounting in interim periods, disclosure and transition.  We adopted the provisions of FIN No. 48 effective July 1, 2007.  The adoption of FIN No. 48 did not have a material impact on our financial position or results of operations (refer to Note 12 to the consolidated financial statements included elsewhere in this Annual Report).

Accounting Pronouncements Not Yet Adopted as of June 30, 2008

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (“SFAS No. 157”).  SFAS No. 157 defines fair value, establishes a framework for measuring fair value, and requires additional disclosures regarding fair value measurements.  In addition, SFAS No. 157 requires that entities consider their own credit risk when measuring the fair value of liabilities including, but not limited to, liabilities related to derivative contracts.   We intend to adopt the provisions of SFAS No. 157 effective July 1, 2008.  We are currently evaluating the impact that SFAS No. 157 will have on our financial position, results of operations and financial statement disclosures.

In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS No. 159”), which creates an alternate measurement method for certain

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financial assets and liabilities.  SFAS No. 159 permits entities to elect fair value measurement for both the initial and subsequent measurements of certain financial assets and liabilities, generally on an instrument by instrument basis.  Changes in fair value subsequent to initial measurement are to be recognized in earnings during the periods when those changes occur.  SFAS No. 159 also requires additional disclosures to compensate for the lack of comparability that will arise from the election of the fair value option for those financial instruments.  We intend to adopt the provisions of SFAS No. 159 effective July 1, 2008.  We are currently evaluating the provisions of SFAS No. 159 to determine whether we will adopt the fair value option for any financial instruments.

In December 2007, the FASB issued Statement of Financial Accounting Standards No. 141(R), “Business Combinations” (“SFAS No. 141(R)”).  SFAS No. 141(R) establishes principles and requirements for an acquiring company to recognize and measure in its financial statements the identifiable assets acquired, liabilities assumed, goodwill acquired, any gain from a bargain purchase, and any noncontrolling interest in an acquired company.  In addition, SFAS No. 141(R) provides guidance for disclosures relating to business combinations.  SFAS No. 141(R) applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008.  Early adoption is not permitted.

In addition, also in December 2007, the FASB issued Statement of Financial Accounting Standards No. 160, “Noncontrolling Interests in Consolidated Financial Statements – An Amendment of ARB No. 51” (“SFAS No. 160”).  SFAS No. 160 establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, for changes in a parent’s ownership interest while the parent retains its controlling financial interest in a subsidiary, and for any retained noncontrolling equity investment by a parent when a subsidiary is deconsolidated.  SFAS No. 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008.  Early adoption is not permitted.

We are currently evaluating the provisions of SFAS No. 141(R) and SFAS No. 160 to determine their likely impact on our accounting and reporting for acquisitions, if any.

In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161, “Disclosures about Derivative Instruments and Hedging Activities” (“SFAS No. 161”).  SFAS No. 161 requires companies with derivative instruments to disclose information that would enable readers of financial statements to understand: 1) how and why a company uses derivative instruments; 2) how derivative instruments and related hedged items are accounted for under U.S. GAAP; and 3) how derivative instruments and related hedged items affect a company’s financial position, financial performance and cash flows.  SFAS No. 161 must be applied prospectively for fiscal years and interim periods beginning after November 15, 2008.  We  intend to apply the provisions of SFAS No. 161 beginning January 1, 2009.  We are currently evaluating the impact that adoption of SFAS No. 161 will have, if any, on our financial statement disclosures.

In May 2008, the FASB issued Statement of Financial Accounting Standards No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS No. 162”).  SFAS No. 162 identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements that are presented in conformity with U.S. GAAP.  Any effect of applying the provisions of SFAS No. 162 shall be reported as a change of accounting principle in accordance with FASB Statement of Financial Accounting Standards No. 154, “Accounting Changes and Error Corrections.”  SFAS No. 162 will become effective 60 days following the SEC’s approval of related amendments to Public Company Accounting Oversight Board guidelines.  The adoption of SFAS No. 162 is not expected to have any impact on our financial position or results of operations.

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Risk Management

Overview

Some degree of risk is inherent in virtually all of our activities.  As a result of our business growth into new markets and increased complexity of our operating infrastructure, we continuously review and, where necessary, upgrade our risk management policies and systems.  The objectives of our risk management policies and systems include:

· Timely identification of various risks associated with our business;

· Assessment of potential costs that can be considered in relation to expected rewards from taking such risks;

· Development and/or acquisition of adequate protections against identified risks;

· Appropriate monitoring and disclosure of risks to all concerned parties; and

· Development of adequate staff training programs regarding compliance with relevant laws, regulations, internal policies and procedures and established systems of internal controls.

Risk management oversight begins with our Board of Directors and its various committees, principally the Audit Committee and the Risk Oversight Committee.  The Audit Committee consists of three members of the Board of Directors and is chaired by an independent director.  The Audit Committee meets regularly and has overseen the strengthening of our internal audit function and our internal financial control environment over the past two fiscal years.  The Audit Committee also meets with our outside auditors shortly after the end of each quarterly and year-end reporting period and reviews and approves all financial reports filed with the SEC.

The Risk Oversight Committee is primarily responsible for oversight of our process for identifying and mitigating risks associated with acquiring natural gas and electricity commodities for distribution to our customers (refer to “Market Risk Management” below for further discussion).

Market Risk Management

Market risks relating to our operations result primarily from changes in commodity prices and interest rates.  In the normal course of business, we also have limited credit risks associated with our ability to collect from derivative counterparties and collect billed accounts receivable from customers and LDCs.

The Risk Oversight Committee is chaired by an independent director, and includes another member of the Board of Directors as well as the Company’s Chief Executive Officer (“CEO”), Chief Financial Officer (“CFO”), Chief Operating Officer (“COO”) and Executive Vice President (“EVP”).  The Risk Oversight Committee meets regularly to ensure that we have adhered to established risk management policies and that we continue to be price and volume neutral through proper commodity hedging.  Risk management policies are reviewed at least annually to ensure that material risks associated with new products, asset acquisitions, current market and other changes in our risk profile are adequately addressed.  The Risk Oversight Committee reports to the Board of Directors on a quarterly basis as to the status of the risk management activities and positions.  We have an independent risk management department that is responsible for monitoring and enforcing risk management policies related to commodities hedging activities.

Refer to “Item 7. Quantitative and Qualitative Disclosures about Market Risks” for additional commentary regarding market risks.

Liquidity Risk Management

Liquidity risk is the risk that we would be unable to meet our obligations as they become due or unable to fund business growth because of an inability to liquidate assets or obtain adequate funding.  Under the oversight of the Audit Committee, liquidity is managed by the CFO to provide the ability to generate cash to fund current operating, investing and financing activities and to manage the cost of purchases of natural gas and electricity at a reasonable cost in a reasonable amount of time, while maintaining routine operations and market confidence.  The following strategies and processes are utilized to manage liquidity:

·Utilize the Hedge Facility to reduce the impact of volatile commodity prices – We have a risk management policy that is intended to reduce our financial exposure related to changes in the price of natural gas and electricity.  Under this policy, we hedge all anticipated natural gas and electricity commodity purchases required to meet expected customer demand for all accounts served under fixed price contracts.  Although the Company engages in hedging activities with various counterparties for electricity, the Company utilizes the Hedge Facility as its primary natural gas hedge facility.  During fiscal year 2008, we extended our Hedge Facility to cover our hedging activities through the end of Fiscal Year 2009. 

·      Utilize the Revolving Credit Facility to provide liquidity for operating requirements – In September 2008, we extended our Revolving Credit Facility through July 31, 2009.  As a result, we have a ready source of liquidity, primarily in the form of letters of credit used for collateral to be placed with hedge counterparties, commodity suppliers and providers of transportation and storage services.  Management believes that the Revolving Credit Facility is adequate to supplement cash provided from operations for funding our operational liquidity needs for fiscal year 2009.

·      Maximize pricing opportunities within the markets that we serve – Our ability to develop products and prices that are competitive within the markets we serve, and to tailor our marketing activities to the optimal mix for various markets, while maintaining a reasonable gross profit per MMBtu or MWhr sold, is crucial to our overall financial success as well as our liquidity position. 

·      Maximize cash collections from customers and LDCs – During fiscal year 2008, approximately 44% of our sales of natural gas and electricity was within markets that guarantee customer accounts receivable.  The LDCs in these markets have credit ratings that are investment grade.  We monitor the payment histories, credit ratings and other financial information for these LDCs in order to identify and address adverse trends, if any.  As of June 30, 2008, we do not maintain an allowance for doubtful accounts against receivables from these LDCs as we have not experienced any material credit losses related to these receivables. 

For customer accounts receivable that are not guaranteed by LDCs, we have processes and information systems in place that are designed to ensure that appropriate amounts are billed and collected from our customers on a timely basis. 

We are continuously identifying and addressing opportunities to improve the processes and systems that support all of the liquidity management initiatives noted above. 

Refer to “Liquidity and Capital Resources” above for commentary regarding significant cash flow and other liquidity activity during the fiscal year ended June 30, 2008.

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Operational and Compliance Risk Management

Operational risk is the risk of loss arising from fraud, unauthorized activities, errors, omissions, inefficiency, system failure or from other external events.  Operational risk is inherent throughout our business organization and covers a wide spectrum of issues.

Compliance risk is the risk arising from failure to comply with relevant laws, regulations and regulatory requirements governing the conduct of our business.  Failure to effectively identify and address various compliance risks can result in financial penalties and other regulatory sanctions, litigation and damage to reputation.

Under the general oversight of our Board of Directors, CEO, COO, CFO and EVP, operational and compliance risks are directly managed within the following functional areas of the organization:

· Regulatory affairs;

· Marketing and sales;

· Contract pricing;

· Natural gas supply;

· Electricity supply;

· Customer Operations (including billing activities, quality assurance activities related to various marketing programs and management of customer communications);

· Compliance;

· Financial and tax reporting;

· Legal counsel; and

· Human Resources and payroll.

Management within each of these areas is directly responsible for identification of risks, development of formal policies and procedures to manage such risks, and reporting any incidents, events or transactions, if any, where risks may not be adequately mitigated.  Under the direction of the Audit Committee and the CFO, the Director of Internal Audit is responsible for investigating and addressing any such incidents, events or transactions for their impact on our overall risk management environment, on our internal control framework, and on our planning of internal audits.

Fraud Risk

During the fiscal year ended June 30, 2008, we developed and implemented a formal fraud risk assessment program, which is designed to facilitate:

· identification of potential fraud risks;

· design of internal controls to address and/or mitigate the fraud risks identified;

· periodic reviews of controls for effectiveness; and

· monitoring of corporate activities and formal reporting of potential incidents, if necessary, to senior management and the Board of Directors.

Under the general oversight of the Audit Committee and the CFO, our Director of Internal Audit is responsible for administering the fraud risk assessment program and reporting results to the Audit Committee.

Information Systems

We maintain a number of information systems for capturing customer, accounting, supply forecasting and risk management information.  Prior to fiscal 2007, these systems were operating on hardware within all of our four offices in Connecticut, Maryland, New Jersey and Texas.  The vast majority of these systems are hosted at an offsite data center in Houston, Texas.  During fiscal year 2008, in conjunction with our hosting provider, we launched an initiative to modernize our key server infrastructure to further increase reliability and supportability, and to reduce redundancy.

During fiscal 2008, we continued to consolidate our multiple existing customer relationship management tools and multiple billing platforms.  As of June 30, 2008, more than 70% of our customers had been consolidated into our primary strategic systems.  We are also continuing to convert our demand forecasting and risk management operations to new or enhanced third party software systems.  We are currently utilizing these systems and will continue to make enhancements during fiscal 2009.

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We perform daily backup of our key servers and maintain backup tapes for a period of four weeks before they are overwritten.  We also perform a month-end backup of key servers and keep such data for a period of six months to one year. All backup tapes are rotated offsite at a secure storage facility on a weekly basis.

We currently replicate our email and various other production servers to ensure availability of our critical systems.  We are in the process of increasing this functionality to additional servers.  Our managed hosting facility in Houston, Texas maintains 24/7 security and has stand-alone power generation to keep the datacenter functional in the case of an extended power outage.

We have taken a multi-tiered approach to protecting our network from malware and intrusions.  We employ endpoint security that includes locked down routers, dual firewalls, and other security appliances.  These are supplemented with anti-spyware and virus protection on all workstations and windows servers.  These applications are monitored and updated to respond pro-actively and successfully to changing threats.

Our website has been custom-developed by an outsourced marketing company and is hosted offsite.  A full-time employee of the Company serves as our webmaster.

Business Continuity Planning

We are committed to the protection of our employees, customers, shareholders, physical buildings, information systems and corporate records.  Our disaster recovery plan and the geographic distance between our offices mitigate the risk of catastrophic interruption of our business.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

Commodity price risk is the risk of exposure to fluctuations in the price of natural gas and electricity.  Because our contracts require that we deliver full commodity requirements to many of our customers and because our customers’ usage is impacted by factors such as weather, we are exposed to fluctuations in customer load requirements.  We typically purchase commodity equal to expected customer consumption assuming normal weather patterns.  We may purchase additional commodity volumes for the summer in the case of electricity and for the winter in the case of natural gas in order to protect against a potential demand increase in peak seasons.  As a result of the natural swing in customer consumption related weather changes, we may have to buy or sell additional volumes, and therefore may be exposed to price volatility.   We utilize various hedging strategies in order to mitigate the risk associated with potential volumetric variability of our monthly deliveries for fixed priced customers.

We utilize NYMEX-referenced swaps and basis swaps as well as physical hedges and physical basis hedges to offset price risk associated with volume commitments under fixed price contracts or variable price contracts where the price to the customer must be established ahead of the index settlement.  The financial swaps are generally settled against each month’s last trading day’s closing price for natural gas listed on the NYMEX Henry Hub futures contract.  The financial basis swaps are typically settled against the first of the month published index prices at various trading points that relate to locations where we have customer obligations.  Physical basis swaps are priced based on NYMEX last day settle plus or minus an agreed upon premium or discount.  All of the natural gas swaps we have executed have been done over-the-counter on a bilateral basis under the Hedge Facility or with other credit-worthy counterparties.  We also enter into financial swaps with other counterparties in order to meet fixed and variable price obligations. These are settled based on each ISO index price.  We only execute financial swaps with entities with investment grade credit ratings.  As of June 30, 2008, our hedge positions extend through June 2011.

We have adopted a risk management policy to measure and limit market risk and credit risk associated with our customer portfolio.  The risk policy requires that we maintain a balanced position at all times and does not permit speculative trading.  None of our employees are compensated on the basis of his or her trading gains.  In marketing fixed price products to residential and small commercial customers, we hedge in advance up to four weeks of anticipated contract sales (adjusted to reflect attrition).  When marketing to larger commercial accounts, the hedge is executed at the time of the contract sale.  Our current risk policy requires that the following exposures be promptly mitigated: (1) any natural gas position exposure in excess of $1.0 million for more than one day be brought back in compliance within one business day; and (2) any electricity position exposure in excess of $250,000 behind any ISO for more than one day be brought back in compliance within one business day.

In order to address the potential volume variability of future deliveries, we utilize various hedging strategies to mitigate our exposure.  For natural gas, hedging tools may include:  (i) over-hedging winter volume obligations in certain markets by up to 10% in order to provide price and volume protection resulting from unexpected increases in demand or by purchasing calls; (ii) utilizing gas in storage to offset variability in winter demand; (iii) entering into daily swing contracts for some or all of the winter months that provide for additional daily volumes if demand increases; and (iv) purchasing put options to protect against falling prices if unused volume needs to be sold and to protect against customer attrition in excess of that historically experienced.  For electricity, hedging tools include: (i) over-hedging summer on-peak volume obligations by up to 10% in order to provide price and volume protection from unexpected increases in demand; (ii) entering into load shape hedges to cover the inherent imbalance from a normal consumption curve that a block hedge creates; and (iii) purchasing put options to protect against falling prices if unused volume needs to be sold and to protect against customer attrition in excess of that historically experienced.

We utilize an internally developed modified variance/co-variance “value-at-risk,” or VAR, model to estimate a maximum potential loss in the fair value of our natural gas portfolio.  For our VAR model, we utilize the higher of 10-day and 30-day NYMEX volatility on a 2 standard deviation basis and (95.45% confidence level).  Using this VAR model, the estimated average, maximum and minimum potential loss in the fixed price natural gas portfolio using our actual net open position at the end of any month during the fiscal year ended June 30, 2008 were approximately $102,000, $366,000 and $7,000, respectively. The estimated average, maximum and minimum potential losses in the fixed price natural gas portfolio using our actual net open position at the end of any month during fiscal year 2007 were approximately $178,000, $548,000 and $53,000, respectively.

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Credit Risk

We are exposed to credit risk in our risk management activities.  Credit risk is the risk of loss resulting from the nonperformance by a counterparty of its contractual obligations.  Our fixed price positions are executed under agreements that include master netting arrangements, which mitigate outstanding credit exposure.  Under our Hedge Facility, our risk management activities are with an
AA-/Aa2 rated financial institution.  To the extent we purchase financial hedges or physical commodity from other counterparties, our risk policy provides for ongoing financial reviews, established credit limits as well as monitoring, managing and mitigating credit exposure.

We also are exposed to credit risk in our sales activities.  As of June 30, 2008, approximately 56% of our total sales of natural gas and electricity was within markets where LDCs do not guarantee customer accounts receivable while 44% of our total sales was within markets where LDCs guarantee customer accounts receivable at a weighted average discount rate of approximately 1%.  Such discount is the cost of service to guarantee the customer accounts receivable.  In cases where customer accounts receivable are guaranteed by the LDC, we are exposed only to the credit risk of the LDC, rather than that of our actual customers.  As of June 30, 2008, all of our accounts receivable in guaranteed markets were with LDCs with investment grade credit ratings.  We record a provision for doubtful accounts for the estimated total revenue that is not expected to be collected from customers in non-guaranteed markets.  For both of the fiscal years ended June 30, 2008 and 2007, the provision for doubtful accounts represented less than 1% of total sales of natural gas and electricity.

We periodically review payment history, credit ratings and financial information for LDCs to ensure that we identify and respond to any deteriorating trends.

Interest Rate Risk

We are exposed to fluctuations in interest rates under our Revolving Credit Facility.  Effective August 4, 2006, we also became exposed to fluctuations in interest rates under the Senior Notes.  As of June 30, 2008, $162.6 million aggregate principal of the Senior Notes was outstanding, net of original issue discount.  In anticipation of issuing the Senior Notes, we entered into interest rate swap agreements during fiscal 2007.  Such interest rate swap agreements are utilized to manage our exposure to interest rate fluctuations on the Senior Notes.  These agreements effectively convert interest rate exposure from a variable rate to a fixed rate of interest.  As of June 30, 2008, the following interest rate swaps were outstanding:

· a $50.0 million swap that expired on August 1, 2008;

· a $30.0 million swap that expires on August 2, 2010; and

· an $80.0 million swap that expires on August 1, 2011.

All swaps are fixed-for-floating and settle against the six-month LIBOR rate.  None of these interest rate swaps have been designated as a hedge and, accordingly, changes in the market value of the interest rate swaps are charged directly to interest expense.  The additional interest expense associated with changes in the market value of interest rate swaps was $3.3 million and $0.9 million for the fiscal years ended June 30, 2008 and 2007, respectively.

Our average, high and low month-end balances for the Senior Notes during fiscal year 2008, which bears interest at variable rates, net of the effects of the interest rate swaps, were approximately $42.0 million, $48.0 million and $35.2 million, respectively. Based on the average outstanding amount of our variable rate indebtedness under the senior notes during the fiscal years ended June 30, 2008 and 2007, a one percentage point change in the interest rates, net of the effects of the interest rate swaps, would have impacted our annual interest expense by approximately $0.3 million and $0.5 million, respectively.  Based on the average outstanding amount of variable rate indebtedness expected for the fiscal year ending June 30, 2009, a one percentage point change in the interest rates would impact fiscal 2009 interest expense by approximately $0.5 million, net of the effects of the interest rate swaps.

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM AND CONSOLIDATED
FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm	59
Consolidated Balance Sheets at June 30, 2008 and 2007	60
Consolidated Statements of Operations for the years ended June 30, 2008, 2007 and 2006	61
Consolidated Statements of Stockholders’ Equity for the years ended June 30, 2008, 2007 and 2006	62
Consolidated Statements of Cash Flows for the years ended June 30, 2008, 2007 and 2006	63
Notes to Consolidated Financial Statements	64

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders
MXenergy Holdings Inc.

We have audited the accompanying consolidated balance sheets of MXenergy Holdings Inc. as of June 30, 2008 and 2007, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended June 30, 2008. 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. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits 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, and 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 consolidated financial position of MXenergy Holdings Inc. at June 30, 2008, and 2007, and the consolidated results of its operations and its cash flows for each of the three years in the period ended June 30, 2008, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 2 to the consolidated financial statements, effective July 1, 2006, the Company adopted Statement of Financial Accounting Standards No. 123R, Share-Based Payments.

/s/ Ernst & Young LLP

Stamford, Connecticut

October 9, 2008

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MXENERGY HOLDINGS INC.

Consolidated Balance Sheets

(dollars in thousands)

	June 30,
	2008			2007
Assets
Current assets:
Cash and cash equivalents	$	71,958		$	136,942
Restricted cash	587			1,050
Accounts receivable, net (Notes 6 and 7)	87,673			48,321
Natural gas inventories	65,006			56,547
Current portion of unrealized gains from risk management activities	35,864			50
Income taxes receivable	7,524			351
Deferred income taxes	—			9,136
Other current assets	3,361			5,311
Total current assets	271,973			257,708
Unrealized gains from risk management activities	13,221			—
Goodwill	3,810			3,810
Customer acquisition costs, net (Note 10)	41,693			38,954
Fixed assets, net (Note 11)	10,525			17,849
Deferred income taxes	10,503			9,754
Other assets	4,027			7,569
Total assets	$	355,752		$	335,644
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	36,602		$	31,528
Accrued commodity purchases	51,461			31,297
Current portion of unrealized losses from risk management activities	2,978			17,074
Deferred revenue	7,435			11,787
Deferred income taxes	9,800			—
Total current liabilities	108,276			91,686
Unrealized losses from risk management activities	2,839			3,586
Long-term debt:
Floating Rate Senior Notes due 2011 (Note 15)	162,648			174,364
Denham Credit Facility	—			11,040
Total long-term debt	162,648			185,404
Total liabilities	273,763			280,676
Redeemable Convertible Preferred Stock (Note 16)	48,779			29,357
Commitments and contingencies (Note 20)	—			—
Stockholders’ equity:
Common stock, par value $0.01, 10,000,000 shares authorized; 3,604,788 and 3,404,277 shares issued and outstanding, respectively	36			34
Additional paid-in capital	23,635			21,367
Unearned stock compensation	(4		)	(22		)
Accumulated other comprehensive loss	(189		)	(129		)
Retained earnings	9,732			4,361
Total stockholders’ equity	33,210			25,611
Total liabilities and stockholders’ equity	$	355,752		$	335,644

The accompanying notes are an integral part of these consolidated financial statements.

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MXENERGY HOLDINGS INC.

Consolidated Statements of Operations

(dollars in thousands)

	Years ended June 30,
	2008			2007			2006
Sales of natural gas and electricity	$	752,283		$	703,926		$	362,561
Cost of goods sold (excluding depreciation and amortization):
Cost of natural gas and electricity sold	630,006			552,028			392,612
Realized losses (gains) from risk management activities	6,747			33,039			(82,983		)
Unrealized (gains) losses from risk management activities	(67,168		)	17,079			79,897
	569,585			602,146			389,526
Gross profit (loss)	182,698			101,780			(26,965		)
Operating expenses:
General and administrative expenses	62,271			54,516			22,623
Advertising and marketing expenses	4,546			4,044			2,096
Reserves and discounts	7,130			4,725			3,395
Depreciation and amortization	32,698			27,730			8,504
Total operating expenses	106,645			91,015			36,618
Operating profit (loss)	76,053			10,765			(63,583		)
Interest expense (net of interest income of $3,806, $4,299 and $1,061, respectively)	34,105			33,058			3,200
Income (loss) before income tax (expense) benefit	41,948			(22,293		)	(66,783		)
Income tax (expense) benefit	(17,155		)	8,495			27,001
Net income (loss)	$	24,793		$	(13,798	)	$	(39,782	)

The accompanying notes are an integral part of these consolidated financial statements.

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MXENERGY HOLDINGS INC.

Consolidated Statements of Stockholders’ Equity

(dollars in thousands)

	Common Stock (Par Value)			Additional Paid-in Capital			Unearned Stock Compensation			Accumulated Other Comprehensive Loss			Retained Earnings			Total Stockholders’ Equity
Balance at June 30, 2005	$	33		$	18,114		$	(165	)	$	(4	)	$	57,941		$	75,919
Issuance of common stock	2			530			—			—			—			532
Unamortized stock compensation	—			861			(861		)	—			—			—
Purchase and cancellation of treasury shares	(1		)	(2,150		)	—			—			—			(2,151		)
Amortization of stock compensation	—			—			911			—			—			911
Comprehensive income (loss):
Net loss	—			—			—			—			(39,782		)	(39,782		)
Foreign currency translation	—			—			—			(36		)	—			(36		)
Comprehensive loss																(39,818		)
Balance at June 30, 2006	34			17,355			(115		)	(40		)	18,159			35,393
Issuance of common stock	—			22			—			—			—			22
Unamortized stock compensation	—			2,219			(2,219		)	—			—			—
Purchase and cancellation of treasury shares	—			(654		)	—			—			—			(654		)
Stock compensation expense	—			2,227			—			—			—			2,227
Tax benefit on issuance of common stock from options	—			198			—			—			—			198
Amortization of stock compensation	—			—			2,312			—			—			2,312
Comprehensive income (loss):
Net loss	—			—			—			—			(13,798		)	(13,798		)
Foreign currency translation	—			—			—			(89		)	—			(89		)
Comprehensive loss																(13,887		)
Balance at June 30, 2007	34			21,367			(22		)	(129		)	4,361			25,611
Issuance of common stock	2			1,337			—			—			—			1,339
Revaluation of Redeemable Convertible Preferred Stock	—			—			—			—			(19,422		)	(19,422		)
Unamortized stock compensation	—			(558		)	558			—			—			—
Purchase and cancellation of treasury shares	—			(1,559		)	—			—			—			(1,559		)
Stock compensation expense	—			2,244			—			—			—			2,244
Tax benefit on issuance of common stock from options	—			804			—			—			—			804
Amortization of stock compensation	—			—			(540		)	—			—			(540		)
Comprehensive income (loss):
Net income	—			—			—			—			24,793			24,793
Foreign currency translation	—			—			—			(60		)	—			(60		)
Comprehensive income	—			—			—			—			—			24,733
Balance at June 30, 2008	$	36		$	23,635		$	(4	)	$	(189	)	$	9,732		$	33,210

The accompanying notes are an integral part of these consolidated financial statements.

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MXENERGY HOLDINGS INC.

Consolidated Statements of Cash Flows

(dollars in thousands)

	Years ended June 30,
	2008			2007			2006
Operating activities:
Net income (loss)	$	24,793		$	(13,798	)	$	(39,782	)
Adjustments to reconcile net income (loss) to net cash (used in) provided by operating activities:
Unrealized (gains) losses from risk management activities	(67,168		)	17,079			79,897
Stock compensation expense	1,704			4,539			911
Depreciation and amortization	32,698			27,730			8,504
Deferred income tax expense (benefit)	18,187			(14,449		)	(32,764		)
Unrealized losses on interest rate swaps and amortization of deferred financing fees	10,836			7,906			1,057
Amortization of customer contracts acquired	(762		)	11,891			(3,276		)
Changes in assets and liabilities, net of effects of acquisitions:
Restricted cash	463			(623		)	6,953
Accounts receivable	(30,181		)	3,453			(13,003		)
Natural gas inventories	(7,308		)	(1,712		)	(2,685		)
Income taxes receivable	(7,173		)	5,184			(5,535		)
Option premiums	1,191			1,835			(1,834		)
Other assets	609			(993		)	2,645
Accounts payable, accrued commodity purchases and other accrued liabilities	17,882			31,555			(5,320		)
Deferred revenue	(4,352		)	9,384			865
Net cash (used in) provided by operating activities	(8,581		)	88,981			(3,367		)
Investing activities:
Loan to PS Energy Group, Inc. related to purchase of GasKey assets	(8,983		)	—			—
Cash received from PS Energy Group, Inc. for repayment of loan.	8,983			—			—
Purchase of GasKey assets	(12,427		)	—			—
Purchase of SESCo assets	—			(126,044		)	—
Deposit and capitalized costs related to purchase of SESCo assets	—			3,348			(3,348		)
Purchase of Vantage assets	—			(732		)	—
Purchase of Castle customer portfolio	—			—			(3,150		)
Customer acquisition costs	(19,555		)	(7,610		)	(6,149		)
Purchases of fixed assets	(1,959		)	(1,882		)	(6,178		)
Net cash used in investing activities	(33,941		)	(132,920		)	(18,825		)
Financing activities:
Proceeds from loans	—			6,000			210,123
Repayments of loans	—			(6,000		)	(226,502		)
Debt financing costs	—			(9,345		)	(2,347		)
Repayments of long-term debt	—			—			(5,000		)
Proceeds from Denham Credit Facility	—			23,040			—
Repayments of Denham Credit Facility	(11,040		)	(12,000		)	—
Proceeds from bridge loan	—			190,000			—
Repayment of bridge loan	—			(190,000		)	—
Proceeds from Senior Notes	—			185,250			—
Repurchase of Senior Notes	(12,006		)	(11,723		)	—
Issuance of common stock from exercise of warrants and options	387			22			532
Issuance of common stock from other executive compensation	952			—			—
Purchase and cancellation of treasury shares, net of tax benefit	(755		)	(456		)	(2,151		)
Net cash (used in) provided by financing activities	(22,462		)	174,788			(25,345		)
Net (decrease) increase in cash	(64,984		)	130,849			(47,537		)
Cash and cash equivalents at beginning of year	136,942			6,093			53,630
Cash and cash equivalents at end of year	$	71,958		$	136,942		$	6,093
Supplemental cash flow information:
Income taxes paid	$	5,405		$	753		$	12,223
Interest paid	$	29,426		$	17,345		$	3,710

The accompanying notes are an integral part of these consolidated financial statements.

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MXenergy Holdings Inc.

Notes to Consolidated Financial Statements

Note 1.   Organization

MXenergy Holdings Inc. (“Holdings”), originally founded in 1999 as a retail energy marketer, was incorporated as a Delaware corporation on January 24, 2005 as part of a corporate reorganization.  The two principal operating subsidiaries of Holdings, MXenergy Inc. and MXenergy Electric Inc., are engaged in the marketing and supply of natural gas and electricity, respectively.  Holdings and its operating and holding subsidiaries (collectively, the “Company”) operate in 39 market areas located in 14 states in the United States (the “U.S.”) and two Canadian provinces.

Note 2.   Significant Accounting Policies

Basis of Presentation

The accounting and reporting policies of the Company conform to accounting principles generally accepted in the United States of America (“U.S. GAAP”).  Certain reclassifications have been made to prior year amounts to conform to the current year’s presentation.

Principles of Consolidation

The Company owns 100% of all of its subsidiaries.  Accordingly, the consolidated financial statements include the accounts of Holdings and all of its subsidiaries.  Intercompany accounts and transactions have been eliminated in consolidation.

Use of Estimates and Assumptions

The preparation of financial statements in accordance with U.S. GAAP requires management to make estimates and assumptions that affect amounts reported in the consolidated financial statements and accompanying notes.  Estimates used in connection with revenue recognition, fair value measurements, allowance for doubtful accounts, valuation of goodwill and other intangible assets, tax-related reserves and share-based compensation are often complex and may significantly impact the amounts reported for those items.  Although management uses its best judgment, actual results could differ from estimated amounts.

Revenue Recognition

Sales of Natural Gas and Electricity

Revenues from the sale of natural gas and electricity are recognized in the period in which the commodity is consumed by customers.  Sales of natural gas and electricity are generally billed by the local distribution companies (“LDCs”), acting as the Company’s agent, on a monthly cycle basis.  The billing cycles for customers do not coincide with the accounting periods used for financial reporting purposes.  The Company follows the accrual method of accounting for revenues whereby revenues applicable to gas and electricity consumed by customers, but not yet billed under the cycle billing method, are estimated and accrued along with the related costs, and included in operations.  Such estimates are adjusted to actual billed amounts in subsequent periods upon obtaining final information from the LDC.  Changes in these estimates are reflected in operations in the period in which they are refined.

Pass-through Revenues

Revenues also include certain “pass-through” revenues, which primarily represent transportation and distribution charges billed to customers by certain LDCs.  These revenues are offset by corresponding amounts in cost of goods sold for amounts billed to the Company by the LDC.  Pass-through revenue approximated $63.6 million and $54.5 million for the fiscal years ended June 30, 2008 and 2007.  Pass-through revenue was not material for the fiscal year ended June 30, 2006.

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Deferred Revenue

Customers who are on budget-billed plans pay for their natural gas or electricity at ratable monthly amounts, based on estimated annual usage, while the Company records revenue when the natural gas or electricity is consumed by the customer.  The cumulative difference between actual usage for these customers and the budget-billed amount actually invoiced, net of cash payments made by the customers, is equal to the net budget-billed variance.  If the net budget-billed variance is a receivable from the customer at the balance sheet date, indicating that the customer’s actual usage has exceeded amounts billed to the customer, the amount is reported as accounts receivable in the consolidated balance sheets.  If the net budget-billed variance is a liability to the customer, indicating that amounts billed have exceeded actual usage, the amount is reported as deferred revenue in the consolidated balance sheets.  Budget billed customer accounts are adjusted annually for differences between estimated and actual consumption.

Sales Incentives

Cash rebates paid to customers under the terms of certain product agreements are recorded as a reduction of sales revenue.  Non-cash incentives, such as free products or services, are recorded as marketing expenses.

Fees Charged to Customers

Various fees charged to customers, such as late payment fees, early contract termination fees, service shut-off fees and fees charged to customers for providing copies of bills, are generally recorded as revenue when earned and when collection is deemed to be reasonably assured.  Fee revenue approximated $19.4 million and $17.1 million for the fiscal years ended June 30, 2008 and 2007.  Fee revenue was not material for the fiscal year ended June 30, 2006.

Collections of Sales Tax

Sales tax is added to customer bills for many of the markets served by the Company.  Sales tax collected from customers on behalf of governmental entities is recorded in accounts payable and accrued liabilities on the consolidated balance sheets.

Fair Value of Financial Instruments

The fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties, other than in a forced or liquidation sale.  Where available, the Company uses quoted market prices as estimates of the fair value of financial instruments.  For financial instruments without quoted market prices, fair value represents management’s best estimate based on a range of methods and assumptions, which are described below.  The use of different assumptions could significantly affect the estimates of fair value.  Accordingly, the net values realized upon liquidation of the financial instruments could be materially different from the estimated fair values presented.

Short-term Financial Assets and Liabilities

The carrying value of certain financial assets and liabilities carried at cost is considered to approximate fair value because they are short-term in nature, bear interest rates that approximate market rates, and generally have minimal credit risk.  These items include cash and cash equivalents, restricted cash, accounts receivable, accounts payable and accrued liabilities, accrued commodity purchases and deferred revenue.

The Company had approximately $68.5 million and $136.5 million invested in money market funds, each share of which was valued at $1.00 at June 30, 2008 and 2007, respectively.

Derivatives

Derivatives are recorded at fair value.   Since the Company has not elected to designate any derivatives as hedges, any changes in fair value are adjusted through unrealized losses (gains) from risk management activities in the consolidated statements of operations, with related outstanding settlement amounts recorded in unrealized gains asset accounts and unrealized losses liability accounts in the consolidated balance sheets.

Market prices used to value derivative positions reflect management’s best estimate considering various factors including closing exchange and over-the-counter quotations, parity differentials, time value, and volatility factors underlying the

65

commitments.

Long-term Debt

At June 30, 2008, long-term debt consisted of The Floating Rate Senior Notes due 2011 (the “Senior Notes”), which had a carrying value, net of unearned discount, of $162.6 million.  Utilizing a weighted average value for the bonds traded on June 30, 2008, the fair market value of the Senior Notes was approximately $140.0 million as of June 30, 2008.

Foreign Currency Translation

The Company has Canadian operations that are measured using Canadian dollars as the functional currency.  Assets and liabilities are translated into U.S. dollars at the rate of exchange in effect on the balance sheet date.  Income and expenses are translated at the average daily exchange rate for the month of activity.  Net exchange gains or losses resulting from such translation are included in common stockholders’ equity as a component of accumulated other comprehensive loss.

Cash and Cash Equivalents

The Company’s cash and cash equivalents consist primarily of cash on deposit and money market accounts.

Restricted Cash

Restricted cash consists of: (1) money market funds held in escrow as contingent consideration related to the acquisition of Vantage Power Services, L.P.; (2) cash deposits received from customers acquired from PS Energy Group, Inc. (refer to Note 4 of these consolidated financial statements) that are held in escrow; and (3) cash and money market funds required as security for letters of credit and surety bonds required by LDCs, utility commissions, pipeline tariffs and regulations.

Accounts Receivable and Allowance for Doubtful Accounts

The Company delivers natural gas and electricity to its customers through LDCs, many of which guarantee amounts due from customers for consumed gas and electricity.  Accounts receivable, net primarily represents amounts due for commodity consumed by customers, net of an allowance for estimated amounts that will not be collected from customers. For those markets where accounts receivable are guaranteed by LDCs, the Company pays guarantee discounts that average approximately 1% of billed accounts receivable, which are charged to reserves and discounts in the consolidated statements of operations as revenue is billed.  The Company does not maintain an allowance for doubtful accounts related to accounts receivable in these guaranteed markets, as it has not experienced material credit losses from any of the respective LDC’s.

In markets where no LDC guarantees exist, the Company calculates and records an allowance for doubtful accounts based on aging of accounts receivable balances, collections history, past loss experience and other current economic or other trends.  Charge offs of accounts receivable balances are recorded as reductions of the allowance for doubtful accounts during the month when the accounts are transferred to outside collection agencies.  Delinquency status for customer accounts is based on the number of days an account balance is outstanding past an invoice due date.  Accounts are generally reviewed for transfer to collection agencies by 120 days from the initial invoice date.  Recoveries of accounts receivable balances previously charged off are recorded when received as additions to the allowance for doubtful accounts.  Adjustments to record the allowance for doubtful accounts at the calculated month-end balance are recorded in reserves and discounts in the consolidated statements of operations.

Accounts receivable, net also includes imbalance settlements due from LDCs, which represent differences between the natural gas delivered to LDCs for consumption by our customers and actual usage by our customers.  Such imbalances are expected to be settled in cash in accordance with contractual payment arrangements.

Natural Gas Inventories

Natural gas inventories primarily represent natural gas held by third parties on the Company’s behalf.  Also included are estimated commodity delivery/usage imbalance settlement amounts that represent natural gas to be transferred to the Company from various third parties within the upcoming twelve-month period.  Natural gas inventories are valued at the lower of cost or market value on a weighted-average cost basis.  The weighted-average cost of inventory includes related transportation costs.

Business Combinations and Goodwill

Since its organization in 1999, the Company has acquired natural gas and electricity operations of numerous energy companies, each of which was recorded as a purchase business combination.  For a purchase business combination, the purchase price is allocated to the net assets acquired based on their fair values at the acquisition date.  Certain intangible

66

assets, such as goodwill and customer acquisition costs, may be recorded in the Company’s consolidated financial statements as a result of these acquisitions if the purchase price exceeds the values assigned to identifiable tangible assets.  The initial purchase price allocation may be reviewed and adjusted for a period of twelve months subsequent to the acquisition date as new or revised information becomes available.

As of June 30, 2008, the Company had goodwill of $3.8 million, which represented the excess of purchase price over the fair value of identifiable net assets acquired from Shell Energy Services Company L.L.C. (“SESCo”) in August 2006.   Goodwill is not amortized, but rather is reviewed for impairment at least annually or more frequently if events or changes in circumstances indicate that the carrying amount may not be recoverable.  Goodwill is tested for impairment annually at June 30.  The Company utilizes an undiscounted cash flow methodology for its impairment testing, which gives consideration to significant and long-term changes in industry and economic conditions as primary indicators of potential impairment.

Customer Acquisition Costs, Net

Customer acquisition costs are comprised of: (1) customer contracts acquired through bulk acquisitions and business combinations; and (2) direct sales and advertising costs, which consist primarily of direct-response hourly telemarketing, non-hourly telemarketing and door-to-door marketing costs incurred through independent third parties, and which are associated with proven customer generation.

For customer contracts acquired through bulk acquisitions and business combinations, acquisition costs are recorded at their fair value on the acquisition date and amortized on a straight-line basis over the estimated life of the customers acquired.  Non-hourly telemarketing and door-to-door costs represent incremental direct costs related to arrangements with third-party contractors.  The Company currently estimates a three-year life for these assets.

Direct-response telemarketing costs are capitalized to the extent that: (1) their purpose was to elicit sales to customers; (2) customers have responded specifically to the advertising; and (3) probable future economic benefit results from the activity.  Such costs are amortized over the period during which the future economic benefits are expected to be realized.  The Company currently estimates a three-year benefit period for these assets.  Periodic amortization expense is calculated on a cost-pool-by-cost-pool basis, and is based on the current revenues generated for a cost-pool in relation to the total current and future estimated revenues for that cost-pool.

Amortization of customer acquisition costs is recorded in depreciation and amortization on the consolidated statements of operations.  Advertising and marketing costs not recorded as customer acquisition costs are expensed as incurred by the Company and recorded as advertising and marketing expenses on the consolidated statements of operations.

Customer acquisition costs are reviewed for recoverability on a quarterly basis, or whenever events or changes in circumstances indicate that their carrying amount may not be recoverable.  In the event that recoverability of the entire carrying amount of the recorded asset becomes doubtful, the non-discounted future cash flows expected to result from the use of the asset and its eventual disposition will be estimated.  If the sum of the expected cash flows to be generated by the asset is less than the carrying amount, the Company shall recognize an impairment loss and adjust the carrying value accordingly.  The adjusted carrying amount of the asset would then become its new cost basis, and would be amortized over the remaining useful life of that asset.

Fixed Assets, Net

Fixed assets consist primarily of computer hardware and software, office equipment and furniture.  Fixed assets are stated at cost on the consolidated balance sheets, less accumulated depreciation.  Depreciation is recorded on a straight-line basis over the estimated useful lives of the related assets, which generally range from three to five years.  Costs of maintenance and repairs to fixed assets are generally expensed as incurred.

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Capitalized Software Costs

The Company capitalizes costs of software acquisition and development projects, including costs related to software design, configuration, coding, installation, testing and parallel processing.  Capitalized software costs are recorded in fixed assets, net of accumulated amortization, on the consolidated balance sheets.  Capitalized software development costs generally include:

·external direct costs of materials and services consumed to obtain or develop software for internal use;

·payroll and payroll-related costs for employees who are directly associated with and who devote time to the project, to the extent of time spent directly on the project;

·costs to obtain or develop software that allows for access or conversion of old data by new systems;

·costs of upgrades and/or enhancements that result in additional functionality for existing software; and

·interest costs incurred while developing internal-use software that could have been avoided if the expenditures had not been made.

The following software-related costs are generally expensed as incurred:

·research costs, such as costs related to the determination of needed technology and the formulation, evaluation and selection of alternatives;

·costs to determine system performance requirements for a proposed software project;

·costs of selecting a vendor for acquired software;

·costs of selecting a consultant to assist in the development or installation of new software;

·internal or external training costs related to software;

·internal or external maintenance costs related to software;

·costs associated with the process of converting data from old to new systems, including purging or cleansing existing data, reconciling or balancing of data in the old and new systems and creation of new data;

·updates and minor modifications; and

·fees paid for general systems consulting and overall control reviews that are not directly associated with the development of software.

The costs of computer software obtained or developed for internal use is amortized on a straight-line basis over the estimated useful life of the software.  Amortization begins when the software and all related software modules on which it is functionally dependant are ready for their intended use.  Amortization expense is recorded in depreciation and amortization in the consolidated statements of operations.  The Company’s amortization period generally does not exceed five years for any capitalized software project.

Capitalized software costs are evaluated for recoverability whenever events or changes in circumstances indicate that its carrying amount may not be recoverable, including when:

·existing software is not expected to provide future service potential;

·it is no longer probable that software under development will be completed and placed in service; and

·costs of developing or modifying internal-use software significantly exceed expected development costs or costs of comparable third-party software.

Income Taxes

The Company files a consolidated federal U.S. income tax return that includes all of its consolidated subsidiaries, as well as various U.S. state returns.  For operations in Canada, a Canadian federal tax return is filed, as well as an Ontario provincial return.

Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases using enacted tax rates expected to be in effect for the year in which the temporary differences are expected to reverse.

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Derivatives and Hedging Activities

Commodity Derivatives

The Company utilizes derivative financial instruments to reduce its exposure to fluctuations in the price of natural gas and electricity.  Commodity derivatives utilized typically include, swaps forwards and options that are bilateral contracts with counterparties.  In addition, certain contracts with customers are also accounted for as derivatives.  The Company has not elected to designate any derivative instruments as hedges under U.S. GAAP guidelines.  Accordingly, any changes in fair value during the term of a derivative contract are adjusted through unrealized losses (gains) from risk management activities in the consolidated statements of operations with offsetting adjustments to unrealized gains or unrealized losses from risk management activities in the consolidated balance sheets.  Unrealized gains from risk management activities on the consolidated balance sheets represent receivables from various derivative counterparties, net of amounts due to the same counterparties when master netting agreements exist.  Unrealized losses from risk management activities represent liabilities to various derivative counterparties, net of receivables from the same counterparties when master netting agreements exist.  Settlements on the derivative instruments are realized monthly and are generally based upon the difference between the contract price and the closing price as quoted on the New York Mercantile Exchange (“NYMEX”) or other published index.

The Company also utilizes certain physical forward commodity purchase and sale contracts to reduce exposure to fluctuations in the price of natural gas and electricity, which are deemed to be “normal purchases and normal sales” under U.S. GAAP guidelines.  Accordingly, such contracts are not carried on the balance sheet at fair value.  All contracts documented for the “normal purchases and normal sales” exception are accounted for as executory contracts with the corresponding purchase and sale recorded for accounting purposes at the settlement date.  Refer to Note 20 of these consolidated financial statements for additional information regarding the Company’s physical forward contracts.

Market prices used to value derivative positions reflect management’s best estimate considering various factors including closing exchange and over-the-counter quotations, parity differentials, time value, and volatility factors underlying the commitments.

Interest Rate Swaps

The Company utilizes interest rate swaps to reduce its exposure to interest rate fluctuations related to its Senior Notes.  The swaps are fixed-for-floating and settle against the six month LIBOR rate.  None of the interest rate swaps has been designated as a hedge, and accordingly, these instruments are carried at fair value on the consolidated balance sheets with changes in fair value recorded as adjustments to interest expense.

Debt

Debt instruments are recorded at their face amounts on the consolidated balance sheet, less any discount or plus any premium.  Debt intended to be repaid within one year is classified as a current liability.

Debt Issue Discounts and Debt Issue Costs

Debt issue discounts are recorded as decreases to recorded debt balances and are amortized to interest expense over the remaining life of the related debt instrument.  Certain costs that are directly related to the issuance of debt, such as underwriting fees, legal fees and other professional services, are deferred and recorded in other assets on the Company’s consolidated balance sheets and amortized to interest expense over the remaining life of the related debt instrument.  In the event that debt instruments are partially or entirely repaid by the Company, a pro rata portion of related premium (discount) and debt issue costs are recorded as an adjustment to interest expense.

Early Extinguishment of Debt

Since the Senior Notes were issued in August 2006, the Company has purchased approximately $24.8 million in aggregate principal amount of Senior Notes from noteholders.  These transactions were recorded as early extinguishments of debt.  Gains from these transactions, which result from the discounts paid by the Company for outstanding Senior Notes, are recorded as adjustments to interest expense.

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Interest Expense

Interest expense is presented net of interest income earned from cash and restricted investments on the consolidated statements of operations.

Redeemable Convertible Preferred Stock

Redeemable convertible preferred stock (the “Preferred Stock”) is recorded outside of stockholders’ equity on the consolidated balance sheets since it is deemed to be redeemable at the option of the holders of the Preferred Stock.  Since the Company has determined that it is probable that the Preferred Stock will become redeemable at June 30, 2009, the Preferred Stock is recorded at its estimated redemption value as of June 30, 2008.

The agreement that governs the Preferred Stock contains various provisions for redemption of the Preferred Stock, for conversion of the Preferred Stock to common stock and for preferences of the holders of the Preferred Stock should the Company be liquidated.  Should any of these events occur, the holders of the Preferred Stock are guaranteed a minimum return of 12% per annum, compounded annually, from the June 30, 2004 issue date through the date of the redemption, conversion or liquidation event.  Any adjustment to the carrying value of the Preferred Stock as a result of any of these events would be recorded as a charge against retained earnings or, in the absence of retained earnings, by charges against additional paid-in capital.

Stock Based Compensation

The Company currently has three stock-based compensation plans in effect, under which stock options to acquire the Company’s common stock have been granted to employees, directors and other non-employees of the Company.  In addition, the Company has issued warrants to purchase its common stock to certain employees and non-employees that were not issued under any of its three approved stock-based compensation plans.  Refer to Note 17 to these consolidated financial statements for additional information regarding the Company’s stock based compensation plans and its grants of options and warrants.

Awards of Stock Options to Acquire the Company’s Common Stock

In December 2004, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standard No. 123 (revised 2004), “Share-Based Payment” (“SFAS No. 123R”), which requires the recognition of the cost of employee services received in exchange for an award of equity instruments in the financial statements.  The measurement of such cost to be recognized must be based on the fair value of the award on the grant date. It also requires the cost to be recognized over the period during which an employee is required to provide services in exchange for the award (the “vesting period”).  SFAS No. 123R replaced SFAS No. 123, “Accounting for Stock Based Compensation” (“SFAS No. 123”) and superseded Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB No. 25”) and related interpretations. The Company adopted SFAS No. 123R on July 1, 2006. As the Company historically utilized the minimum value method for pro forma disclosures under the original provisions of SFAS No. 123, it was required to adopt the provisions of SFAS No. 123R using the prospective method.  Under the prospective method, the Company continues to account for non-vested awards outstanding at the date of adoption of SFAS No. 123R in the same manner as they had been accounted for prior to adoption for financial statement recognition purposes.  All awards granted, modified or settled after the adoption will be accounted for using the measurement, recognition and attribution provisions of SFAS No. 123R.  The adoption of SFAS No. 123R did not have any financial impact on the Company’s financial position, results of operations or cash flows for any awards granted prior to June 30, 2006.

For stock option awards granted after June 30, 2006, the Company follows the provisions of SFAS No. 123R and recognizes compensation expense prospectively over the vesting period.  Total compensation expense to be recognized over the vesting period is based on: (1) the fair value of the Company’s common stock at the quarterly reporting date (e.g., September 30, December 31, March 31 and June 30) immediately prior to the grant date, as determined by an independent valuation of the Company’s common stock or internally developed valuation models; and (2) the total number of options expected to be exercised, net of expected forfeitures.  The cumulative effect on current and prior periods of a change in the number of options expected to be exercised, net of forfeitures, is recognized in compensation expense in the period of the change.

The Company has elected to follow APB No. 25, and related interpretations, in accounting for stock option awards granted to employees prior to June 30, 2006, rather than the alternative fair value method allowed under SFAS No. 123.  APB

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No. 25 provides that compensation expense relative to the Company’s employee stock and stock option grants be measured based on the intrinsic value of the stock or stock option at the grant date.  Pursuant to APB No. 25, for options granted to employees prior to June 30, 2006, the Company was not required to recognize compensation expense during the fiscal years ended June 30, 2008, 2007 or 2006 because the exercise price for all such awards equaled or exceeded the estimated fair value of the Company’s common stock at the grant date.

Awards of Warrants to Acquire the Company’s Common Stock

Prior to June 30, 2006, the Company issued warrants to certain employees and non-employees that permit the warrant holder the option to: (1) exercise such warrant for cash; or (2) exercise by withholding that number of common shares having a total fair value equal to the warrant exercise amount from the total number of common shares that would otherwise have been issued upon exercise of the warrant (a “cashless exercise”).  Compensation cost is accrued as a charge to expense over the vesting period of such warrants using the accelerated expense attribution method under FASB Interpretation No. 28 “Accounting for Stock Appreciation Rights and Other Variable Stock Option or Award Plans.”  For these awards, it is presumed that the employee will elect the cashless exercise and compensation expense is adjusted periodically to reflect the amount by which the estimated current fair value of the Company’s common shares exceeds the exercise price of the warrant (known as “variable plan accounting”).  Increases or decreases in the estimated fair value of the Company’s common stock between the grant date and the exercise date result in corresponding increases or decreases, respectively, in compensation expense in the period in which the change in estimated fair value of common stock occurs.  Accrued compensation for an award that is subsequently forfeited or cancelled is adjusted by decreasing compensation expense in the period of forfeiture or cancellation.

Prior to June 30, 2006, warrants were issued to a stockholder of the Company which are not subject to variable plan accounting because there is no requirement to provide any future service to the Company in order to exercise the warrants.  Therefore, the Company does not record any compensation expense related to these warrants.

Compensation expense for option awards subject to graded vesting is recognized based on the accelerated attribution method as specified under U.S. GAAP guidelines.  Compensation expense related to stock compensation plans is recorded in general and administrative expenses in the consolidated statements of operations.

Transactions with Related Parties

In the normal course of business, the Company enters into transactions with various non-employee related parties for financing arrangements, legal services, financial advisory services and management services.  Refer to Note 18 to these consolidated financial statements for additional information regarding related party transactions.

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Note 3.   New Accounting Pronouncements

Accounting Pronouncements Adopted During the Fiscal Year Ended June 30, 2008

In June 2006, the Financial Accounting Standards Board (the “FASB”) issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109” (“FIN No. 48”).  FIN No. 48 establishes threshold and measurement attributes for financial statement recognition and measurement of tax positions taken or expected to be taken in a tax return.  FIN No. 48 also provides guidance on de-recognition of a previously recognized tax position, classification, interest and penalties, accounting in interim periods, disclosure and transition.  The Company adopted the provisions of FIN No. 48 effective July 1, 2007.  The adoption of FIN No. 48 did not have a material impact on the Company’s financial position or results of operations (refer to Note 12 of these consolidated financial statements).

Accounting Pronouncements Not Yet Adopted as of June 30, 2008

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (“SFAS No. 157”).  SFAS No. 157 defines fair value, establishes a framework for measuring fair value, and requires additional disclosures regarding fair value measurements.  In addition, SFAS No. 157 requires that entities consider their own credit risk when measuring the fair value of liabilities including, but not limited to, liabilities related to derivative contracts.   The Company intends to adopt the provisions of SFAS No. 157 effective July 1, 2008.  The Company is currently evaluating the impact that SFAS No. 157 will have on its financial position, results of operations and financial statement disclosures.

In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS No. 159”), which creates an alternate measurement method for certain financial assets and liabilities.  SFAS No. 159 permits entities to elect fair value measurement for both the initial and subsequent measurements of certain financial assets and liabilities, generally on an instrument by instrument basis.  Changes in fair value subsequent to initial measurement are to be recognized in earnings during the periods when those changes occur.  SFAS No. 159 also requires additional disclosures to compensate for the lack of comparability that will arise from the election of the fair value option for those financial instruments.  The Company intends to adopt the provisions of SFAS No. 159 effective July 1, 2008.  The Company is currently evaluating the provisions of SFAS No. 159 to determine whether it will adopt the fair value option for any financial instruments.

In December 2007, the FASB issued Statement of Financial Accounting Standards No. 141(R), “Business Combinations” (“SFAS No. 141(R)”).  SFAS No. 141(R) establishes principles and requirements for an acquiring company to recognize and measure in its financial statements the identifiable assets acquired, liabilities assumed, goodwill acquired, any gain from a bargain purchase, and any noncontrolling interest in an acquired company.  In addition, SFAS No. 141(R) provides guidance for disclosures relating to business combinations.  SFAS No. 141(R) applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008.  Early adoption is not permitted.

In addition, also in December 2007, the FASB issued Statement of Financial Accounting Standards No. 160, “Noncontrolling Interests in Consolidated Financial Statements – An Amendment of ARB No. 51” (“SFAS No. 160”).  SFAS No. 160 establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, for changes in a parent’s ownership interest while the parent retains its controlling financial interest in a subsidiary, and for any retained noncontrolling equity investment by a parent when a subsidiary is deconsolidated.  SFAS No. 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008.  Early adoption is not permitted.

The Company is currently evaluating the provisions of SFAS No. 141(R) and SFAS No. 160 to determine their likely impact on the accounting and reporting for acquisitions, if any.  The Company expects to adopt the provisions of SFAS No. 141(R) and SFAS No. 160 for acquisitions occurring on or after July 1, 2009.

In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161, “Disclosures about Derivative Instruments and Hedging Activities” (“SFAS No. 161”).  SFAS No. 161 requires companies with derivative instruments to disclose information that would enable readers of financial statements to understand: 1) how and why a company uses derivative instruments; 2) how derivative instruments and related hedged items are accounted for under U.S. GAAP; and 3) how derivative instruments and related hedged items affect a company’s financial position, financial performance and cash flows.  SFAS No. 161 must be applied prospectively for fiscal years and interim periods beginning after November 15,

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2008.  The Company intends to apply the provisions of SFAS No. 161 beginning January 1, 2009.  The Company is currently evaluating the impact that adoption of SFAS No. 161 will have, if any, on its financial statement disclosures.

In May 2008, the FASB issued Statement of Financial Accounting Standards No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS No. 162”).  SFAS No. 162 identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements that are presented in conformity with U.S. GAAP.  Any effect of applying the provisions of SFAS No. 162 shall be reported as a change of accounting principle in accordance with FASB Statement of Financial Accounting Standards No. 154, “Accounting Changes and Error Corrections.”  SFAS No. 162 will become effective 60 days following the Securities and Exchange Commission’s approval of related amendments to Public Company Accounting Oversight Board guidelines.  The adoption of SFAS No. 162 is not expected to have any impact on The Company’s financial position or results of operations.

Note 4.   Acquisitions

GasKey Division of PS Energy Group, Inc.

On January 22, 2008, the Company completed the acquisition of substantially all of the retail natural gas assets of PS Energy Group, Inc., primarily including the natural gas customer contracts of their GasKey division (the “GasKey Acquisition”).  Nearly all of the customers served under such contracts are located in Georgia.  Most of the natural gas volumes are consumed by commercial customers.  The Company acquired approximately 60,000 residential customer equivalents (“RCEs,” each representing a natural gas customer with a standard consumption of 100 MMBtus per year or an electricity customer with a standard consumption of 10 MWhrs per year).  Consistent with the Company’s experience with previous acquisitions, attrition for this portfolio is expected to be higher than that for customers acquired through organic growth.

Pursuant to the terms of the related Asset Purchase Agreement, the Company purchased the GasKey net assets for a base amount of approximately $4.3 million, plus working capital, plus contingent consideration payable for volumes consumed on customer contracts acquired for a 36-month period subsequent to the acquisition date (refer to Note 20).  The final purchase price is subject to certain adjustments in accordance with the terms and conditions of such Asset Purchase Agreement.  The Company also assumed certain liabilities related to the GasKey assets.

Regulatory approval for the GasKey Acquisition was received in January 2008.  The Company recorded the transaction as a purchase business combination as of January 1, 2008.  The initial purchase price of $12.0 million was paid from the Company’s available cash balance.  The assets acquired and related operations represent less than 10% of the Company’s consolidated assets and operations.  The operations acquired are included in the Company’s natural gas business segment.

Pursuant to the Asset Purchase Agreement, the Company assumed the economic benefit and risk associated with the GasKey net assets effective November 1, 2007.  During the period from November 1, 2007 to December 31, 2007, the Company extended $13.6 million of credit to PS Energy Group, Inc., of which $9.0 million was loaned directly to PS Energy Group, Inc. and $4.6 million represented collateral and guarantees funded by the Company to fulfill LDC requirements related to the GasKey business.  Also during this period, the Company recorded cash receipts from accounts receivable, cash payments for natural gas inventory purchases, certain operating expenditures, and other operating cash activity related to the assets acquired and liabilities assumed in the GasKey Acquisition.   The $9.0 million loan to PS Energy Group, Inc. was repaid on the closing date.

The total purchase price was adjusted to reflect the operating activity recorded during the period from November 1, 2007 through December 31, 2007 (the “adjusted purchase price”).  The Company allocated the adjusted purchase price to the net assets acquired at their fair values on January 1, 2008.  The initial allocation of the adjusted purchase price, as summarized in the following table, is considered to be preliminary, and still subject to final evaluation of the value assigned to the customer acquisition costs.  The adjusted allocation includes adjustments to customer acquisition costs resulting from incentive payments to PS Energy Group, Inc. in accordance with the agreement governing the GasKey Acquisition.

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The initial and adjusted purchase price allocations for the GasKey Acquisition are summarized in the following table.

	Initial Allocation  As of  January 1, 2008			Adjusted Allocation  As of  June 30, 2008
	(in thousands)
Accounts receivable	$	9,171		$	9,171
Natural gas inventories	1,151			1,151
Customer acquisition costs (1)	6,221			6,599
Customer contract assets (2)	750			750
Other assets	1,830			1,830
Customer contract liabilities (3)	(1,250		)	(1,250		)
Accounts payable and accrued liabilities	(5,824		)	(5,824		)
Total	$	12,049		$	12,427

(1)Customer acquisition costs are being amortized on a straight-line basis over an estimated average customer life of three years.

(2)Represents customer and supply contracts acquired that had contract terms above market rates at the date of acquisition.  Such amounts are amortized through cost of natural gas sold as the Company makes delivery under the contracts.

(3)Represents customer and supply contracts acquired that had contract terms below market rates at the date of acquisition.  Such amounts are recorded in accounts payable and accrued liabilities and amortized through cost of natural gas sold as the Company makes delivery under the contracts.

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Shell Energy Services Company L.L.C.

In August 2006, the Company completed its acquisition of substantially all of the assets of SESCo, a retail energy marketer that serves residential and small to mid-market commercial customers in Georgia and Ohio (the “SESCo Acquisition”).  The SESCo Acquisition added approximately 315,000 RCEs to the Company’s customer portfolio, and added the state of Georgia to the list of U.S. states in which the Company operates.  The total purchase price for the SESCo Acquisition was approximately $126.0 million.  The SESCo Acquisition was accounted for as a purchase business combination and the results of operations of SESCo are included in the Company’s operating results beginning on August 1, 2006.

During August 2006, the Company utilized a bridge loan from two investment banks to finance the SESCo Acquisition.  The bridge loan was repaid with proceeds from the sale of $190.0 million aggregate principal amount of the Senior Notes (refer to Note 16 of these consolidated financial statements).  Fees and interest of $0.8 million associated with the bridge loan were charged to interest expense during the fiscal year ended June 30, 2007.

At August 1, 2006, the preliminary purchase price was initially allocated based upon the estimated fair value of the net assets acquired at the date of acquisition.  The final allocations were based on independent valuations that were completed during the fourth quarter of fiscal year 2007.  As a result of changes to the purchase price allocation during the fourth quarter of fiscal 2007, the Company recorded a benefit of $0.8 million as a reduction of amortization expense related to customer acquisition costs.

The initial and final purchase price allocations for the SESCo Acquisition are summarized in the following table.

	Initial			Final
	Allocation			Allocation
	(in thousands)
Accounts receivable	$	16,392		$	17,304
Inventory	33,501			36,336
Prepaid peaking service	—			2,652
Fixed assets	15,000			15,510
Customer acquisition costs (1)	56,381			38,500
Customer contract assets (2)	6,306			15,345
Goodwill	—			3,810
Customer contract liabilities (3)	(2,050		)	(3,413		)
Total	$	125,530		$	126,044

(1)Customer acquisition costs are being amortized on a straight-line basis over an estimated average customer life of three years.

(2)Represents customer and supply contracts acquired that had contract terms above market rates at the date of acquisition.  Such amounts are amortized through cost of natural gas sold as the Company makes delivery under the contracts.

(3)Represents customer and supply contracts acquired that had contract terms below market rates at the date of acquisition.  Such amounts are recorded in accounts payable and accrued liabilities and amortized through cost of natural gas sold as the Company makes delivery under the contracts.

The goodwill, which is reflected in the Company’s natural gas segment, represents the Company’s cost of entering a new market, as well as workforce-related matters.  The Company will be deducting the entire amount of goodwill for tax purposes over 15 years.

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The following unaudited pro forma financial information for the fiscal year ended June 30, 2006 assumes the SESCo Acquisition occurred on July 1, 2005.  The pro forma information is not necessarily indicative of the results that would have been achieved had the SESCo Acquisition occurred on such date nor is it necessarily indicative of future results.

	Fiscal Year  Ended  June 30, 2006
	(in thousands)
Sales of natural gas	$	1,010,274
Net loss	(54,430		)

In August 2006, in connection with the SESCo Acquisition, the Company approved and announced its rationalization plan to move certain of its operations to Houston, Texas.  The terms of the rationalization plan, which were specific to each employee affected, included various employee benefit cost components such as severance, retention bonuses and reimbursement of relocation costs.  Certain employee benefit costs were contingent on future events, such as continued employment during defined transition periods.  The Company recorded rationalization charges of $1.2 million during the fiscal year ended June 30, 2007.   All rationalization charges were recorded to general and administrative expenses in the consolidated statements of operations.

Vantage Power Services, L.P.

On May 17, 2007, the Company acquired substantially all of the assets of Vantage Power Services, L.P. (“Vantage”) and began supplying power to approximately 12,000 former electricity RCEs of Vantage in and around Houston, Dallas/Ft. Worth and Corpus Christi, Texas (the “Vantage Acquisition”).  The Vantage Acquisition was accounted for as a purchase business combination and the results of operations of Vantage are included in the Company’s operating results beginning on May 17, 2007.  The initial purchase price of $0.7 million was allocated based upon the estimated fair value of the net assets acquired at the date of acquisition.  The final allocation includes adjustments to customer acquisition costs resulting from incentive payments to Vantage in accordance with the agreement governing the Vantage Acquisition.

The initial and final purchase price allocations for the Vantage Acquisition are summarized in the following table.

	Initial  Allocation			Final  Allocation
	(in thousands)
Other current assets	$	2		$	2
Fixed assets	10			10
Customer acquisition costs (1)	1,599			2,380
Customer contract liabilities (2)	(879		)	(879		)
Total	$	732		$	1,513

(1)Customer acquisition costs are being amortized on a straight-line basis over an estimated average customer life of three years.

(2)Represents customer and supply contracts acquired that had contract terms below market rates at the date of acquisition.  Such amounts are recorded in accounts payable and accrued liabilities and amortized through cost electricity sold as the Company makes delivery under the contracts.

The agreement governing the Vantage Acquisition includes provisions for contingent consideration payable to Vantage for volumes consumed on customer accounts acquired for an 18-month period subsequent to the acquisition date (refer to Note 20).

Subsequent Event

In October 2008, the Company received regulatory and bankruptcy court approval and entered into an agreement to purchase liquefied natural gas inventory from an insolvent Georgia-based retail gas company.  In connection therewith, the related portfolio of natural gas customers was transferred to the Company at no cost.  The total purchase price for the inventory was approximately $1.5 million.  The purchase agreement also includes transition fees of approximately $0.5 million, which will be expensed as incurred by the Company.  This acquisition is not expected to have a material impact on the Company’s financial position or results of operations for the fiscal year ended June 30, 2009.

Note 5.   Seasonality of Operations

Weather conditions have a significant impact on customer demand and on the price of natural gas and electricity.  Customer demand exposes the Company to a high degree of seasonality in sales, cost of sales, billing to and cash collections from customers, inventory requirements and cash flows.  In addition, customers who choose to be on budget billing programs and certain LDCs who pay upon delivery of natural gas can cause timing differences between the billing and collection of accounts receivable and the recording of revenues.  The Company utilizes a considerable amount of cash from operations to fund natural gas inventory purchases, accounts receivable and other working capital requirements during the months of May through November of each fiscal year.  The majority of natural gas consumption occurs during the months of November through March with collections on accounts receivable peaking in the spring.  In contrast, electricity consumption peaks during the summer months of June through September.

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Note 6.   Accounts Receivable, Net

Accounts receivable, net is summarized in the following table.

	Balances at June 30.
	2008			2007
	(in thousands)
Billed customer accounts receivable:
Guaranteed by LDCs	$	17,085		$	8,721
Non-guaranteed by LDCs	32,966			27,314
	50,051			36,035
Unbilled customer accounts receivable:
Guaranteed by LDCs	9,803			3,487
Non-guaranteed by LDCs	19,905			10,268
	29,708			13,755
Total customer accounts receivable	79,759			49,790
Less: Allowance for doubtful accounts	(5,154		)	(5,259		)
Customer accounts receivable, net	74,605			44,531
Imbalance settlements and other receivables	13,068			3,790
Accounts receivable, net	$	87,673		$	48,321

Billed customer accounts receivable represents uncollected revenues that have been billed directly to customers by the Company or on the Company’s behalf by certain LDCs.  Unbilled customer accounts receivable represent estimated revenues associated with natural gas and electricity consumed but not yet billed to customers under the LDC’s monthly cycle billing method.

The Company’s credit risk is limited as certain LDCs guarantee billed and unbilled customer accounts receivable.  As of June 30, 2008 and 2007, 100% of the Company’s billed and unbilled customer accounts receivable in these guaranteed markets was with LDCs that have an investment grade credit rating.

In the market areas where the LDC does not guarantee customer accounts receivable, the Company maintains an allowance for doubtful accounts that is based upon the credit risk of its customers, historical trends and other information.  Refer to Note 7 of these consolidated financial statements for additional analysis of the Company’s allowance for doubtful accounts.

Imbalance settlements represent differences between the natural gas delivered to LDCs for consumption by our customers and actual usage by our customers.  Such imbalances are expected to be settled in cash from the LDCs in accordance with contractual payment arrangements.

The Company operates in 39 market areas located in 14 U.S. states and two Canadian Provinces.  The Company’s diversified geographic coverage mitigates its credit exposure which could result from concentrations in a single LDC territory or a single regulatory jurisdiction, from extreme local weather patterns or from an economic downturn in any single geographic region.

In addition, the Company has limited exposure to risk associated with high concentrations of sales volumes with individual customers.  For the fiscal years ended June 30, 2008 and 2007, the Company’s largest customer accounted for approximately 2% of total sales volume.

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Note 7.   Allowance for Doubtful Accounts

An analysis of the allowance for doubtful accounts is provided in the following table.

	Fiscal Year Ended June 30,
	2008			2007			2006
	(in thousands)
Balance at beginning of period	$	5,259		$	3,285		$	1,899
Add: Provision for doubtful accounts	5,050			3,018			1,552
Less: Net charge offs of customer accounts receivable	(5,155		)	(1,044		)	(166		)
Balance at end of period	$	5,154		$	5,259		$	3,285

The provision for doubtful accounts and net charge offs of customer accounts receivable both represented less than 1% of total revenues for each of the fiscal years ended June 30, 2008, 2007 and 2006.

Reserves and discounts in the consolidated statements of operations includes the provision for doubtful accounts as disclosed in the table above as well as discounts related to customer accounts receivable that are guaranteed by LDCs.  Discounts charged by LDCs average approximately 1% of collections, which is effectively the cost to guarantee the receivables.  The components of reserves and discounts are summarized in the following table.

	Fiscal Year Ended June 30,
	2008		2007		2006
	(in thousands)
Provision for doubtful accounts	$	5,050	$	3,018	$	1,552
Discounts for guaranteed markets	2,080		1,707		1,843
Total	$	7,130	$	4,725	$	3,395

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Note 8.   Derivatives and Hedging Activities

Commodity Hedging Activities

The Company has a risk management policy that is intended to reduce its financial exposure related to changes in the price of natural gas and electricity.  Under this policy, the Company hedges all anticipated natural gas and electricity commodity purchases required to meet expected customer demand for all accounts served under fixed price contracts (up to 110% in the winter months with respect to customer demand in certain natural gas utilities with daily balancing requirements and up to 110% in the summer months with respect to customer demand in certain electricity utilities).

The Company has elected not to designate any of the derivative instruments as hedges under U.S. GAAP, and accordingly, all changes in fair value are adjusted through unrealized gains or losses from risk management activities in the consolidated statements of operations.

Although the Company engages in hedging activities with various counterparties for electricity, the Company utilizes one particular hedge facility as its primary natural gas hedge facility (the “Hedge Facility”).  Under the Hedge Facility, the Company utilizes NYMEX referenced over-the-counter swaps, basis price swaps and options to hedge the risk of variability in the cost of natural gas.  The Hedge Facility was originally entered into on August 1, 2006 and had an initial term of two years with subsequent one-year renewal terms.  In July 2008, the Company extended the Hedge Facility to the earlier of August 1, 2009 or 30 days prior to expiration of the Revolving Credit Facility.  As of June 30, 2008, all of the Company’s natural gas hedge positions were with counterparties that had investment grade credit ratings.

The Hedge Facility provides the Company with the ability to enter into NYMEX and basis swaps for a tenor of up to 39 months. Fees under the Hedge Facility include an annual management fee, a volumetric fee based on the tenor of the swap and other fees which allow the hedge provider to mitigate the potential risks arising from material declines of natural gas market prices based on the Company’s overall hedge position with the provider.

The Hedge Facility is secured by a first lien on customer contracts and a second lien on substantially all other assets of the Company.  The Company posted an initial balance of $25.0 million in cash collateral for potential negative mark-to-market changes in the value of the forward hedge position.  The Company has the flexibility to post either cash collateral or issue a letter of credit as margin for the Hedge Facility.  As of June 30, 2008, the Company posted a $25.0 million letter of credit as margin.

The agreement governing the Hedge Facility was amended in March 2008 and July 2008, as follows:

·In July 2008, the termination date was extended to the earlier of August 1, 2009 or 30 days prior to expiration of the Revolving Credit Facility. As a result of extension of the Revolving Credit Facility is currently due to expire on July 1, 2009.

·In July 2008, the collateral requirement was amended to require the Company to increase the posted amount from $25.0 million to $35.0 million if its mark-to-market exposure under the Hedge Facility exceeds $25.0 million;

·Prior to March 1, 2008, the Company was not required to post additional collateral beyond the initial margin requirements unless the amount of NYMEX referenced forward swap hedge positions exceeded 65,000,000 MMBtus.  As a result of an amendment to the agreement governing the Hedge Facility, effective March 1, 2008, the Company will not be required to post additional collateral unless its NYMEX referenced forward swap hedge positions exceed 35,000,000 MMBtus.  In July 2008, this limit was further reduced to 25,000,000 MMBtus; and

·Certain financial covenants, which are the same as those included in the agreement governing the Revolving Credit Facility (refer to Note 14 of these consolidated financial statements) were also amended.

In September 2008, the Company increased the letter of credit posted as margin to $35.0 million because its mark-to-market exposure under the Hedge Facility exceeded $25.0 million.

The Company also utilizes swaps and fixed price contracts with various counterparties to hedge the variability in the cost of electricity.  As of June 30, 2008, the Company did not have an exclusive agreement with any single hedge provider for electricity.  The Company manages its exposure to risk associated with any single electricity hedge provider through a formal credit risk management process and through daily review of exposures from open positions.  As of June 30, 2008, all of the Company’s electricity hedge positions were with counterparties with investment grade credit ratings.

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Outstanding hedging contracts, which extend through August 2011, are summarized in the following table.

	Open Contracts As Of June 30,
	2008	2007
Natural gas (under the Hedge Facility):
MMBtu(1)  NYMEX referenced over the counter swaps	13,967,000	18,703,000
MMBtu basis swaps	17,631,000	14,641,000
Electricity:
MWhrs(2) of swaps and fixed price contracts	106,000	69,000

(1)   Million British thermal units

(2)   Million watt hours

The Company has a risk management policy that defines various risk management controls and limits designed to monitor the Company’s risk position and ensure that hedging performance is in line with objectives established by its Board of Directors and management.  The Company’s risk management policy prohibits speculative trading activities.

Interest Rate Swaps

In August 2006, the Company entered into two interest rate swaps to hedge the floating rate interest expense on the Senior Notes:  (1) a $50.0 million swap that expired on August 1, 2008; and (2) an $80.0 million swap that expires on August 1, 2011.  During the three months ended March 31, 2008, the Company entered into a $30.0 million swap that expires on August 2, 2010.  All swaps are fixed-for-floating and settle against the six-month LIBOR rate.  None of these interest rate swaps have been designated as a hedge and, accordingly, changes in the market value of the interest rate swaps are charged directly to interest expense.  The additional interest expense associated with changes in the market value of interest rate swaps was $3.3 million and $0.9 million for the fiscal years ended June 30, 2008 and 2007, respectively.

The carrying value of the interest rate swaps, which is recorded as a liability in unrealized losses from risk management activities on the consolidated balance sheets, was $4.6 million and $1.3 million at June 30, 2008 and 2007, respectively.

Credit Risk Associated with Derivative Financial Instruments

The Company is exposed to credit risk associated with its hedging program and derivative financial instruments.  Credit risk relates to the loss resulting from the nonperformance of a contractual obligation by a derivative counterparty.  Historically, the Company has executed its fixed price derivative positions to include a master netting agreement that mitigates the outstanding credit exposure.  Under the Hedge Facility, the Company’s risk management activities are with a financial institution that has an AA-/Aa2 rating.  To the extent that financial hedges or physical commodities are acquired from other counterparties, the Company’s risk management policy set forth guidelines for monitoring, managing and mitigating credit risk exposures.  The risk management policy also establishes credit limits and requires ongoing financial reviews of counterparties.

Note 9.   Goodwill

The Company completed its annual impairment test of goodwill as of June 30, 2008.  At the testing date, the Company determined that the fair value of each of its reporting units exceeded its carrying value.  As a result, no impairment loss was required to be recognized.  Since the testing date, there were no material events, transactions or changes in circumstances which warranted consideration for their impact on the recorded carrying value assigned to goodwill.

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Note 10. Customer Acquisition Costs, Net

Customer acquisition costs and related accumulated amortization are summarized in the following tables.

	Balance at June 30, 2008
	Gross Book Value		Accumulated  Amortization		Net Book Value
	(in thousands)
Customer contracts acquired	$	47,515	$	26,395	$	21,120
Direct sales and advertising costs	32,287		11,714		20,573
Total customer acquisition costs	$	79,802	$	38,109	$	41,693

	Balance at June 30, 2007
	Gross Book Value		Accumulated  Amortization		Net Book Value
	(in thousands)
Customer contracts acquired	$	64,324	$	34,034	$	30,290
Direct sales and advertising costs	12,209		3,545		8,664
Total customer acquisition costs	$	76, 533	$	37,579	$	38,954

Amortization expense relating to capitalized customer acquisition costs was $23.4 million, $19.5 million and $6.2 million for the fiscal years ended June 30, 2008, 2007 and 2006, respectively.  Amortization expense associated with customer acquisition costs capitalized as of June 30, 2008 is estimated to be approximately $25.5 million, $11.8 million and $4.4 million for the fiscal years ending June 30, 2009, 2010 and 2011, respectively.

The value and recoverability of customer acquisition costs are evaluated quarterly by comparing their carrying value to their projected future cash flows on an undiscounted basis.  During the fiscal year ended June 30, 2008, no impairment was indicated as a result of these comparisons, and there were no material events or transactions which warranted consideration for their impact on the recorded book value assigned to customer acquisition costs.

As of June 30, 2008, the weighted-average amortization period for customer acquisition costs is 1.5 years.

Note 11. Fixed Assets, Net

Fixed assets, net are summarized in the following table.

							Estimated
	Balance at June 30,						Useful
	2008			2007			Lives
	(in thousands)
Computer equipment	$	5,126		$	4,476		3-5 years
Computer software and development	25,583			24,395			3 years
Office furniture and equipment	1,479			1,358			3-5 years
	32,188			30,229
Less: accumulated depreciation and amortization	(21,663		)	(12,380		)
Net	$	10,525		$	17,849

During the fiscal year ended June 30, 2008, The Company capitalized approximately $1.0 million of software development costs related to a project designed to reduce the number of software packages utilized to service customer accounts and to enhance the overall capabilities of existing software.

Depreciation expense relating to computer equipment, office furniture and other equipment was $1.6 million, $1.7 million and $1.2 million for the fiscal years ended June 30, 2008, 2007 and 2006, respectively.  Amortization expense relating to capitalized computer software costs was $7.7 million, $6.4 million and $1.1 million for the fiscal years ended June 30, 2008, 2007 and 2006, respectively.

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Note 12. Income Taxes

Income tax (expense) benefit consists of the following:

	Fiscal Years ended June 30
	2008			2007			2006
	(in thousands)
Current:
Federal	$	599		$	(4,750	)	$	(5,595	)
State	434			(1,204		)	(168		)
	1,033			(5,954		)	(5,763		)
Deferred:
Federal	(15,000		)	13,249			25,683
State	(3,188		)	1,200			7,081
	(18,188		)	14,449			32,764
Total income tax (expense) benefit	$	(17,155	)	$	8,495		$	27,001

The Company incurred a current tax loss for fiscal 2008, which it intends to carry back to the 2007 tax year.

The provision for income taxes varied from income taxes computed at the statutory U.S. federal income tax rate as a result of the following:

	2008		2007		2006
Federal statutory rate	35.0	%	35.0	%	35.0	%
State statutory rate, net of federal benefit	4.5		5.4		5.7
Total	39.5		40.4		40.7
Impact of prior year adjustments on current and deferred income taxes	(0.6	)	—		0.1
Impact of changing tax rates on prior year deferred balances	1.0		(0.1	)	—
Impact of permanent differences	1.0		(2.2	)	(0.4	)
Effective tax rate	40.9	%	38.1	%	40.4	%

The higher effective tax rate for the fiscal year ended June 30, 2008 was primarily due to changes in the mix and amounts of permanent differences.

The state statutory rate for the fiscal year ended June 30, 2008 decreased to 4.5%, as a result of income apportionment for the states in which the Company does business.

The Company adopted FIN No. 48 effective July 1, 2007 (refer to Note 3 of these consolidated financial statements).   There was no material impact on the Company’s recorded retained earnings as a result of the adoption of FIN No. 48.

Major taxing jurisdictions for the Company and tax years for each that remain subject to examination are as follows:

Taxing Jurisdiction	Open Years
U.S. Federal	2004 and later
U.S. states and cities	2004 and later
Canada	2004 and later

The Company recognizes accrued interest and penalties related to income tax liabilities as accrued liabilities in the consolidated balance sheet and interest expense in the consolidated statement of operations.  As of July 1, 2007, the Company had accrued approximately $0.2 million for potential interest and penalties for the uncertain tax position related to the settlement of derivatives described below.  Most of this amount was paid in the third quarter of the fiscal year ended June 30, 2008.

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Deferred income taxes reflect the net tax effects of temporary differences between the carrying amount of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The Company expects to fully recognize its deferred tax assets recorded at June 30, 2008.  The significant components of the Company’s deferred tax assets and liabilities are summarized in the following table.

	Balance at June 30,
	2008			2007
	(in thousands)
Deferred tax assets:
Allowance for doubtful accounts	$	2,035		$	2,125
Accrued bonuses	1,090			—
Other reserves	122			133
Depreciation and amortization	12,877			6,438
Net unrealized losses from risk management activities	—			8,327
Stock compensation expense	1,664			1,867
Total deferred tax assets	17,788			18,890
Deferred tax liabilities:
Net unrealized gains from risk management activities	(17,085		)	—
Total deferred tax liabilities	(17,085		)	—
Net deferred tax asset	$	703		$	18,890
Balance sheet classification:
Current deferred tax asset	$	—		$	9,136
Long-term deferred tax asset	10,503			9,754
Current deferred tax liability	(9,800		)	—
Net deferred tax asset	$	703		$	18,890

A summary of activity related to uncertain tax positions for the fiscal year ended June 30, 2008 follows:

	Amount
	(in millions)
Unrecognized tax benefit at July 1, 2007	$	1.7
Decreases from payments during the fiscal year	(0.8		)
Unrecognized tax benefit at June 30, 2008	$	0.9

As of July 1, 2007, the Company had an uncertain tax position of $0.8 million related to the settlement of derivatives used as commodity hedges during fiscal years ended June 30, 2005 and 2004.  During the fiscal year ended June 30, 2008, the Company filed an amended return for 2004.  The Company intends to file amended tax returns for 2005 during the fiscal year ending June 30, 2009.  The Company had previously accrued a current tax liability of $0.8 million at June 30, 2007, which was paid upon filing the amended 2004 tax return.

Also at July 1, 2007, the Company had an uncertain tax position of $0.9 million for a compensation related timing issue.  There was no change to this amount during the fiscal year ended June 30, 2008.  The Company does not expect this item to be settled within the next twelve months.  There is no change in the effective tax rate as a result of this item.

During the fiscal year ended June 30, 2008, the Company identified an uncertain tax position related to interest expense deductions.  This position relates to certain state income tax returns filed for the fiscal year ended June 30, 2007 and to the state income tax provision recorded for the nine months ended March 31, 2008.  During the fourth quarter of fiscal 2008, the Company executed agreements allowing interest expense to be deducted for state tax purposes.  Therefore, this item is no longer considered to be an uncertain tax position as of June 30, 2008.

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Note 13. Accounts Payable and Accrued Liabilities

Accounts payable and accrued liabilities are summarized in the following table.

	Balance at June 30,
	2008		2007
	(in thousands)
Interest payable	$	11,662	$	13,118
Trade accounts payable and accrued liabilities (1)	14,427		10,047
Accrued payroll and related liabilities	3,824		2,885
Sales and other taxes	1,291		1,928
Customer contracts acquired in business combinations (2)	699		1,673
Other	4,699		1,877
Total accounts payable and accrued liabilities	$	36,602	$	31,528

(1)	Includes $0.3 million and $0.6 million, respectively, due to related parties for legal services, financial advisory services and management fees. Refer to Note 18 of these consolidated financial statements for additional information.
(2)	Represents customer contracts acquired that had contract terms below market rates at the respective dates of acquisition. Such amounts are amortized through cost of natural gas and electricity sold as the Company makes delivery under the contracts.

Interest payable relates primarily to accrued interest on the Senior Notes.  Trade accounts payable and accrued expenses relate primarily to transportation and distribution charges, imbalances and other utility-related expenses.

Note 14. Revolving Credit Facility

MXenergy Inc. and MXenergy Electric Inc. are borrowers under a revolving credit facility with a syndicate of banks (the “Revolving Credit Facility”).  As of June 30, 2008, the maximum amount that could be borrowed under the Revolving Credit Facility was the lesser of: (1) $280.0 million; or (2) the amount of the then applicable borrowing base.  The expiration date of the Revolving Credit Facility was December 19, 2008, at which time any outstanding principal amounts would have become due.  Borrowings under the Revolving Credit Facility bore interest at a fluctuating rate based upon a base rate or a Eurodollar rate plus an applicable margin.  As of June 30, 2008, the applicable margin for base rate loans was 1.00% per annum and the applicable margin for Eurodollar loans was 2.00% per annum.  As of June 30, 2008, the fees associated with issuing letters of credit were 1.75% per annum.

At June 30, 2008, the total availability under the Revolving Credit Facility was $193.9 million, of which $147.9 million was utilized in the form of outstanding letters of credit.  The Company did not draw any borrowings under the Revolving Credit Facility during the fiscal year ended June 30, 2008, and there were no cash borrowings outstanding under the Revolving Credit Facility at June 30, 2008.

On September 30, 2008, the agreement that governs the Revolving Credit Facility was amended and restated.  The amended and restated agreement includes the following amendments to the previous agreement

·The maturity date of the Revolving Credit Facility was extended through July 31, 2009.

·The maximum amount that the Company is permitted to borrow was reduced to $255.0 million.  The amendment allows for new lenders to be added to the Revolving Credit Facility subsequent to closing, which could increase the maximum amount available for the Company to borrow to $280.0 million.

·The Company paid an upfront amendment closing fee of 0.75% of the aggregate commitment under the Revolving Credit Facility, which will be amortized to interest expense from October 2008 through July 2009.

·The margins for based rate loans were increased by 1.00%.

·The fee associated with issuing letters of credit was increased to 2.75% per annum.  Various other fees under the facility were also increased.

·The Company is required to borrow any available balance under the Denham Credit Facility no later than November 7, 2008.

·The Company may not acquire customer portfolios or operations of other companies without explicit approval by lenders holding a majority of the commitments under the Revolving Credit Facility.

·The maximum Average Leverage Ratio (average debt for the 12 months preceding a reporting period, divided by adjusted EBITDA for the same period) for the period from February 1, 2009 through the expiration date was lowered to 3.75 from 4.00.

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The Revolving Credit Facility contains customary covenants that restrict certain of the Company’s activities including, among others, limitation on capital expenditures, disposal of property and equipment, additional indebtedness, issuance of capital stock and dividend payments.  Financial covenants under the Revolving Credit Facility include, among others, minimum tangible net worth, minimum working capital and interest coverage, each as defined in the agreement that governs the Revolving Credit Facility.  The Revolving Credit Facility was amended during the fiscal year ended June 30, 2008 to reflect changes in the financial thresholds of certain covenants.  The Revolving Credit Facility also contains customary events of default.  The Company was in compliance with the covenants under the Revolving Credit Facility at June 30, 2008.

Note 15. Floating Rate Senior Notes due 2011

On August 4, 2006, the Company issued $190.0 million aggregate principal amount of Senior Notes that mature on August 1, 2011. The Senior Notes were issued at 97.5% of par value, and bear interest at a rate equal to LIBOR plus 7.5% per annum.  Interest is reset and payable semi-annually on February 1 and August 1 of each year.  The interest rate on the Senior Notes was 10.6863% as of June 30, 2008, and was reset to 10.6250% on August 1, 2008.  The weighted-average interest rate was 11.9462% and 12.9650% for the fiscal years ended June 30, 2008 and 2007, respectively.  The Company has entered into interest rate swap agreements to hedge the floating rate interest expense on the Senior Notes (refer to Note 8 of these consolidated financial statements).

Total interest expense associated with the Senior Notes, excluding the impact of mark-to-market adjustments related to interest rate swaps, was $21.0 million and $21.2 million for the fiscal years ended June 30, 2008 and 2007, respectively.

The original issue discount of approximately $4.8 million is being amortized to interest expense ratably over the term of the Senior Notes.  Amortization of original issue discount to interest expense for the fiscal years ended June 30, 2008 and 2007 was $1.1 million and $1.0 million, respectively.  These amounts include the impact of the early extinguishment of Senior Notes discussed in the following paragraphs.

On December 13, 2006, the Company purchased $12.0 million aggregate principal amount of Senior Notes outstanding, plus accrued interest, from a noteholder for an amount less than face value.  The Company utilized its credit facility with Denham Commodity Partners Fund LP (refer to Note 18 of these consolidated financial statements) to acquire such Senior Notes.  This transaction resulted in a gain on early extinguishment of debt of approximately $1.0 million, which was recorded as a reduction of interest expense for the fiscal year ended June 30, 2007.  The Company also recorded as additional interest expense $0.6 million of original issue discount and debt issuance costs for the fiscal year ended June 30, 2007, which represents a pro rata portion of such costs that were deferred at the issuance date of the Senior Notes.

During the fiscal year ended June 30, 2008, the Company utilized cash and cash equivalents to acquire $12.8 million aggregate principal amount of outstanding Senior Notes from noteholders, in each case, for an amount less than face value.  These transactions resulted in $0.8 million of aggregate gains on the early extinguishment of debt that was recorded as a reduction of interest expense for the fiscal year ended June 30, 2008.  The Company also recorded as additional interest expense $0.5 million of original issue discount and debt issuance costs for the fiscal year ended June 30, 2008, which represents a pro rata portion of such costs that were deferred at the issuance date of the Senior Notes.

On or before August 1, 2009, upon an equity offering, the Company may redeem up to 35% of the aggregate principal amount of the Senior Notes at a price equal to the sum of (1) 100% of the principal amount; (2) a premium equal to the rate per annum on the balance outstanding on the date notice is given to redeem the Senior Notes; and (3) accrued and unpaid interest as of the redemption date.  If a change of control, as defined in the indenture governing the Senior Notes, were to occur, the Company would be obligated to make an offer to purchase the Senior Notes, in whole or in part, at a price equal to 101% of their aggregate principal amount, plus accrued and unpaid interest, if any, as of the date of purchase.  If a change of control were to occur, the Company may not have the financial resources to repay all of its obligations under the Senior Notes.  During the fiscal year ended June 30, 2008, there was no change in control, as defined in the indenture governing the Senior Notes, which would obligate the Company to purchase the Senior Notes.

Holdings, the issuer of the Senior Notes, has no significant independent operations.  Each of Holdings’ domestic U.S. subsidiaries jointly and severally, fully and unconditionally guarantees the Senior Notes on a senior unsecured basis.  Refer to Note 22 of these consolidated financial statements for consolidating financial statements of Holdings and its guarantor and non-guarantor subsidiaries.

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The indenture governing the Senior Notes contains restrictions on Holdings and its domestic subsidiaries with regard to declaring or paying any dividend or distribution on Holdings capital stock.  As of June 30, 2008, the Company was in compliance with all provisions of the indenture governing the Senior Notes.

Note 16. Redeemable  Convertible Preferred Stock

Holdings is authorized to issue 5,000,000 shares of redeemable convertible preferred stock.   On June 30, 2004, MXenergy Inc. entered into a purchase agreement (the “Preferred Stock Purchase Agreement”) with affiliates of Charterhouse Group Inc. and Greenhill Capital Partners LLC (collectively, the “Preferred Investors”) to issue 1,451,310 shares of Preferred Stock at a purchase price of $21.36 per share.  During the fiscal year ended June 30, 2005, as part of a corporate reorganization, MXenergy Inc. merged with a subsidiary of Holdings to become a wholly owned subsidiary of Holdings and stockholders of MXenergy Inc. became stockholders of Holdings.  Total related offering expenses of approximately $1.6 million were deducted from the carrying value of the Preferred Stock, which resulted in a net carrying value of approximately $29.4 million at June 30, 2007.

The Company has determined that the Preferred Stock is redeemable at the option of the Preferred Investors as a result of the redemption provisions included in the Preferred Stock Purchase Agreement.  Therefore, the Preferred Stock is recorded outside of stockholders’ equity on the consolidated balance sheets.  As of June 30, 2008, the Company has determined that it is probable that the Preferred Stock will become redeemable at June 30, 2009, which is the earliest possible date that the Preferred Investors may cause the Company to make the redemption election described under “Redemption Rights” below.  Therefore, as of June 30, 2008, the carrying value of the Preferred Stock has been adjusted to reflect the estimated redemption value, assuming the Preferred Stock was redeemed on June 30, 2008.  Accordingly, the carrying value of Preferred Stock was increased to its estimated $48.8 million redemption value at June 30, 2008, which represents the amount that provides the Preferred Investors with a minimum annual rate of return of 12%, compounded annually through June 30, 2008, as guaranteed to the Preferred Investors under the dividend provisions of the Preferred Stock Purchase Agreement (see “Dividend Rights” below) with a corresponding charge of $19.4 million recorded to retained earnings.

Dividend Rights

The Preferred Investors are entitled to participate in any dividend paid on Holdings’ common stock on an “as converted” basis.  In addition, the Preferred Investors are entitled to dividends at a rate of 12% per annum, compounded annually, from June 30, 2004 until the occurrence of a redemption date, if any (see “Redemption Rights” below for additional information).  Such dividends are cumulative and payable when and if any dividend is declared by Holdings on any class of its outstanding capital stock.

Holdings’ ability to pay any cash dividends is limited by debt covenants and other provisions of the agreements that govern the Hedge Facility, the Revolving Credit Facility and the Senior Notes.  Therefore, Holdings did not declare or accrue any dividends during the fiscal years ended June 30, 2008 or 2007.

Conversion Rights

The Preferred Investors have the right at any time to convert their shares of Preferred Stock into shares of Holdings’ common stock.   Upon conversion, the number of shares of common stock to be issued shall be the number of shares of Preferred Stock outstanding; adjusted in accordance with conversion provisions in the Preferred Stock Purchase Agreement that guarantee the Preferred Investors a minimum annual rate of return equal to 12% per annum, compounded annually.  The conversion price is subject to certain anti-dilution provisions included in the Preferred Stock Purchase Agreement.

As of June 30, 2008, 1,451,310 shares of Holdings’ common stock were reserved for issuance upon conversion of the Preferred Stock.

Redemption Rights

At any time on or after the fifth anniversary of the issuance of the Preferred Stock, the Company may redeem all, but not less than all, of the outstanding shares of Preferred Stock with cash if, as of the date a notice of redemption is provided to the Preferred Investors, the fair market value of Holdings’ common stock is at a level that would provide an annual rate of return of not less than 40%, compounded annually, to the majority of the Preferred Investors.  The redemption price per share would be equivalent to the fair market value of Holdings’ common stock on the redemption date.

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On or after the fifth anniversary of the issuance of the Preferred Stock, if the fair market value of Holdings’ common stock is at a level that would not provide the Preferred Investors with an annual rate of return of at least 25%, compounded annually, for the five-year period ending June 30, 2009, the Preferred Investors may require that the Company make a redemption election.  If the Company elects to redeem the Preferred Stock, the redemption amount is payable in cash equal to the greater of: (1) the fair market value of the shares of common stock into which the Preferred Stock may be converted on the date of the redemption election notice; or (2) the original issue price of $21.36 per share, plus any accrual of dividends described above under “Dividend Rights”.  If the Company elects not to elect to redeem the Preferred Stock, it is required to grant the Preferred Investors effective control over Holding’s Board of Directors.  As of June 30, 2008, the Company does not expect to redeem the Preferred Stock due to limitations included in the agreements that govern the Revolving Credit Facility, the Hedge Facility and the Senior Notes.  However, since the Preferred Investors would effectively control the Company’s Board of Directors in the event that the Company does not elect to redeem the Preferred Stock, the Company has determined that the Preferred Stock is redeemable at the option of the Preferred Investors and, accordingly, has classified the Preferred Stock outside of stockholders’ equity on the consolidated balance sheets.

Liquidation Preference

If a liquidation event, as defined in the Preferred Stock Purchase Agreement, were to occur, the Preferred Investors would be entitled to receive an amount per share of Preferred Stock equal to the greater of: (1) the original purchase price per share paid by the Preferred Investors, adjusted for dividends accrued or declared and unpaid as of the liquidation date; or (2) the amount per share of Preferred Stock that the Preferred Investors would have received if it had converted its shares of Preferred Stock into shares of Holdings’ common stock immediately prior to the liquidation event.  As of June 30, 2008, no liquidation event has occurred, as defined in the Preferred Stock Purchase Agreement.

Voting Rights

Holders of the Preferred Stock are entitled to vote on all matters to be voted on by Holdings’ stockholders and shall vote on an as-converted basis as a single class with Holdings’ common stockholders.

Note 17. Common Stock

Stock-Based Compensation Plans

The purpose of the Company’s stock-based compensation plans is to attract and retain qualified employees, consultants and other service providers by providing them with additional incentives and opportunities to participate in the Company’s ownership, and to create interest in the success and increased value of the Company.  The plans are administered by the Compensation Committee of the Board of Directors.  The Compensation Committee has the authority to: (1) interpret the plans and to create or amend its rules; (2) establish award guidelines under the plans; and (3) determine, or delegate the determination to management, the persons to whom awards are to be granted, the time at which awards will be granted, the number of shares to be represented by each award, and the consideration to be received, if any.  Option awards under the plans generally are granted with an exercise price equal to the fair value of Holdings’ common stock at the grant date, vest ratably based on three years of continuous service and have ten year contractual terms.

The Company has three active stock-based compensation plans under which warrants and options (collectively referred to as “awards”) have been granted to employees, directors and other non-employees:

·2001 Incentive Stock Option Plan (the “2001 ISO Plan”) –  The 2001 ISO Plan allows for awards of stock or stock options not to exceed the 366,500 shares of Holdings’ common stock reserved as a pool for distribution to employees and non-employees.  As of June 30, 2008, there were no shares available under the 2001 ISO Plan for future award.

·2003 Incentive Stock Option Plan (the “2003 ISO Plan”) – The 2003 ISO Plan allows for awards of stock or stock options not to exceed the 400,000 shares of Holdings’ common stock reserved as a pool for distribution to employees and non-employees.  As of June 30, 2008, there were 6,946 shares available under the 2003 ISO Plan for future award.

·2006 Equity Incentive Compensation Plan (the “2006 EIC Plan”) – The 2006 EIC Plan allows for awards of options, restricted stock, phantom shares, dividend equivalent rights performance awards or stock appreciation rights, to employees, members of the Board of Directors, officers, consultants and other service providers.  Up to 750,000 shares of Holdings’ common stock have been authorized to be issued for awards under the 2006 EIC Plan.  As of June 30, 2008, 326,166 shares were available under the 2006 EIC Plan for future award.  The adoption of the 2006 EIC Plan had no impact on the 2001 ISO Plan or the 2003 ISO Plan.

The fair value of each option award granted subsequent to June 30, 2006, is estimated on the grant date using a Black-Scholes-Merton option valuation model.  Certain key assumptions used in the model included share price volatility, expected term, risk-free interest rate and expected forfeiture rate.

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Pursuant to employment contracts entered into during the fiscal year ended June 30, 2008, the Company granted options for 7,500 shares of Holdings’ common stock that vest ratably over a three-year period and that expire 10 years from the grant date.   The Company recorded less than $0.1 million of compensation expense during the fiscal year ended June 30, 2008 and expects to record less than $0.1 million of compensation expense during each of the fiscal years ending June 30, 2009, 2010 and 2011 related to this award.  The Company did not grant any other awards of options under any of its stock-based compensation plans during the fiscal year ended June 30, 2008.

As of June 30, 2008, 1,079,820 options to purchase common stock were outstanding under the Company’s three approved stock-based compensation plans, for which the Company expects to record approximately $0.9 million, $0.2 million and $0 of compensation expense in general and administrative expenses during the fiscal year ending June 30, 2009, 2008 and 2007, respectively.

As of June 30, 2008, 34,600 options to purchase common stock have been issued to two non-employee directors of the Company.  These options have a weighted average exercise price of $12.75 per share and are fully-vested as of June 30, 2008.

Warrants Issued to Employees and Related Parties

The Company has issued warrants to purchase common stock to certain employees and related parties that were not issued under any of the Company’s three approved stock-based compensation plans.  As of June 30, 2008, the Company had 41,500 warrants to purchase common stock outstanding that were granted to employees prior to June 30, 2006 and are accounted for using variable plan accounting.  For these warrants, changes in the estimated fair value of the Company’s common stock between the grant date and the exercise date result in corresponding adjustments to compensation expense during the period in which the change in the estimated fair value of common stock occurs.  Total compensation expense related to these warrants was ($0.5) million (($0.3) million net of tax), $2.3 million ($1.4 million net of tax) and $0.9 million ($0.6 million net of tax) during the fiscal years ended June 30, 2008, 2007 and 2006, respectively.

As of June 30, 2008, the Company had 1,544,736 fully-vested warrants to purchase common stock outstanding, held by Denham, with a weighted average exercise price of $9.79 per share.  These warrants are not subject to variable plan accounting because there is no future requirement to provide any services to the Company in order for Denham to exercise the warrants.  Therefore, the Company did not record any expense related to these warrants during the fiscal years ended June 30, 2008, 2007 or 2006.  In September 2008, Denham exercised these warrants in a cashless transaction, resulting in the issuance of 1,130,163 shares of the Company’s common stock.

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Outstanding awards of all options and warrants to purchase common stock are summarized in the following tables.

	Awards Outstanding at June 30,
	2008					2007				2006
	Number of Awards			Weighted- Average Exercise Price		Number of Awards		Weighted- Average Exercise Price		Number of Awards		Weighted- Average Exercise Price
Outstanding at beginning of year	2,931,406			$	16.35	2,538,106		$	10.87	2,696,706		$	10.70
Granted	7,500			50.10		508,000		42.90		4,500		32.50
Exercised	(224,417		)	4.18		(29,000	)	3.08		(132,967	)	4.23
Forfeited	(48,433		)	33.57		(40,700	)	28.73		(30,133	)	25.41
Expired	—			—		(45,000	)	4.40		—		—
Outstanding at end of year	2,666,056			17.16		2,931,406		16.35		2,538,106		10.87
Weighted average fair value of grants during the year				$	13.70			$	12.31			$	11.72
Total intrinsic value of awards outstanding at June 30, 2008 (in millions)	$	42.3

	Awards Outstanding at June 30,
	2008			2007		2006
Exercise Price	Number of Awards Outstanding	Number of Awards Exercisable	Weighted- Average Contractual Life Remaining	Number of Awards Outstanding	Number Of Awards Exercisable	Number of Awards Outstanding	Number of Awards Exercisable
$1.00	100,000	100,000	3.7 Years	110,000	110,000	120,000	120,000
$2.16	—	—	0.0 Years	132,450	132,450	132,450	132,450
$3.72 – $5.35	10,000	10,000	3.7 Years	47,500	47,500	110,000	110,000
$6.99 – $9.12	1,163,263	1,163,263	1.3 Years	1,215,863	1,215,863	1,229,663	1,199,196
$11.64 – $15.00	562,573	562,573	0.7 Years	562,573	562,573	562,573	559,573
$21.50 – $25.00	233,820	233,820	4.8 Years	234,420	162,947	239,020	89,507
$27.50 – $32.50	128,500	128,500	6.1 Years	136,300	91,200	144,400	48,967
$42.57 – $50.10	467,900	157,067	8.0 Years	492,300	5,000	—	—
	2,666,056	2,355,223		2,931,406	2,327,533	2,538,106	2,259,693

The weighted-average remaining term for all outstanding awards as of June 30, 2008 was approximately 3 years.  The weighted-average remaining term for all exercisable awards as of June 30, 2008 was approximately 2.3 years.  The weighted average exercise price of awards exercisable as of June 30, 2008 was $13.74.

During the fiscal years ended June 30, 2008, 2007 and 2006, awards were exercised for 181,511, 29,000 and 132,967 shares of Holdings’ common stock, respectively.  The aggregate proceeds of these exercises were $0.4 million, less than $0.1 million, and $0.6 million for the fiscal years ended June 30, 2008, 2007 and 2006, respectively.   The tax benefit for the Company from the exercise of warrants was approximately $0.8 million, $0.2 million and $0 for the fiscal years ended June 30, 2008, 2007 and 2006, respectively, and were recorded as a reduction of current tax liability and an increase to additional paid-in capital.

Common Stock Issued to Senior Executives

In March 2008, the Compensation Committee of the Company’s Board of Directors approved the issuance of 19,000 aggregate fully vested shares of Holdings’ common stock to the Company’s Chief Executive Officer and Executive Vice President.  Total compensation expense related to issuance of these shares was approximately $1.7 million, which included the fair value of the common stock issued and additional compensation to offset the taxable nature of the shares to the employees.

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Note 18. Related Party Transactions

Credit Agreement with Denham Commodity Partners Fund LP

Denham Commodity Partners Fund LP (“Denham”) is a significant stockholder of the Company.  Denham has extended a $12.0 million line of credit to the Company, which bears interest at 9% per annum (the “Denham Credit Facility”).  The termination date for the Denham Credit Facility is May 19, 2010, at which time any outstanding principal balance becomes due.   The Company had $0 and $11.0 million of borrowings outstanding under the Denham Credit Facility at June 30, 2008 and 2007, respectively.  In December 2007, the Denham Credit Facility agreement was amended to allow the Company to draw principal until November 14, 2008.  In January 2008, the Company repaid the entire $11.0 million principal balance outstanding under the Denham Credit Facility.  Interest expense related to the Denham Credit Facility was $0.5 million, $0.5 million and $0 for the fiscal years ended June 30, 2008, 2007 and 2006, respectively.

In accordance with the September 30, 2008 amendment and restatement of the agreement that governs the Revolving Credit Facility (refer to Note 14), the Company is required to borrow any available balance under the Denham Credit Facility prior to November 7, 2008, and to maintain such balance outstanding until the Revolving Credit Facility expires on July 31, 2009.  In October 2008, the Company borrowed the entire $12.0 million balance available under the Denham Credit Facility.

Legal Services

A director and significant stockholder of the Company is a senior partner of Paul, Hastings, Janofsky & Walker LLP (“Paul Hastings”), a law firm that provides legal services to the Company.  During the fiscal years ended June 30, 2008, 2007 and 2006, Paul Hastings provided the Company with legal services totaling $0.6 million, $1.2 million and $1.4 million, respectively, of which $0.6 million, $0.8 million and $1.4 million, respectively, were for general legal services recorded as general and administrative expenses.  The remaining $0.4 million of fees for the fiscal year ended June 30, 2007, primarily related to issuance of debt and acquisitions and were deferred on the consolidated balance sheets, to be amortized over the estimated useful lives associated with the related transactions.  The Company expects that Paul Hastings will continue to provide legal services to the Company in future periods.

Financial Advisory Services

In fiscal 2005, the Company entered into a consulting agreement with Greenhill Capital Partners (“GCP”), a significant stockholder of the Company, to serve as a financial advisor. The agreement provided for payment of quarterly retainer fees that totaled $0.3 million annually and additional fees contingent upon the successful completion of certain transactions specified in the agreement. The Company recorded general and administrative expenses of $0.1 million and $0.3 million for the fiscal years ended June 30, 2007 and 2006, respectively, pertaining to this agreement. The retainer arrangement with GCP expired on September 30, 2006.

In May 2007, the Company entered into a financial advisory services agreement with Greenhill & Co., LLC, an affiliate of GCP, pursuant to which the Company pays Greenhill & Co., LLC quarterly fees that total $0.3 million annually, and may incur other charges based on the occurrence of a transaction, as defined in such agreement.  The Company recorded $0.3 million of general and administrative expenses during the fiscal year ended June 30, 2008 related to this agreement.

Management Fees

Effective for the three months ended September 30, 2007, the Company agreed to pay Denham, Daniel Bergstein and Charter Mx LLC, another significant stockholder of the Company, an aggregate annual fee of $0.9 million, payable in equal quarterly amounts, for management consulting services provided to the Company.  These fees are recorded as general and administrative expenses on the Company’s consolidated statements of operations.

Note 19. Employee Benefits

The Company sponsors an employee savings plan under Section 401(k) of the Internal Revenue Code for all full-time employees with at least three months of continuous service.  Eligible employees may make pre-tax contributions up to 20% of their annual compensation, not to exceed the annual limitation set forth in Section 402 (g) for any plan year. The Company makes a matching contribution of up to 10% of each participating employee’s compensation up to the maximum allowable under the plan.  Employees whose employment date is prior to July 1, 2007, are immediately 100% vested in all contributions.  Employer contributions for employees whose employment date is on or after July 1, 2007 will vest in increments of 25%

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per year.  The Company made contributions of $1.3 million, $1.0 million and $0.6 million for the fiscal years ended June 30, 2008, 2007 and 2006, respectively.  The increase in expense from fiscal year 2007 to fiscal year 2008 was primarily due to increased staffing levels.

Note 20. Commitments and Contingencies

Operating Leases

The Company leases office space under non-cancelable operating leases, which contain escalation clauses, have terms that expire between July 2009 and October 2017 and are subject to extension at the option of the Company.  The Company takes into account all escalation clauses when determining the amount of future minimum lease payments.  All future minimum lease payments are recognized on a straight-line basis over the minimum lease term.  Rental expense related to the above leased spaces was $1.3 million, $1.6 million and $0.5 million for the fiscal years ended June 30, 2008, 2007 and 2006, respectively.  Future annual minimum lease payments under operating leases are summarized in the following table.

Fiscal year:	Amount
	(in thousands)
2009	$	973
2010	760
2011	232
2012	209
2013	234
Thereafter	1,077
Total	$	3,485

Energy Trading & Risk Management System

In June 2005, the Company entered into an agreement to acquire an energy trading and risk management (“ETRM”) system.  Total licensing fees paid to acquire the system, including fees paid to expand the number of users in June 2007, were $1.0 million.  Total capitalized costs to acquire and develop the ETRM system, which are included in fixed assets, were $2.2 million at both June 30, 2008 and 2007.  The Company is required to pay annual maintenance fees of approximately $0.2 million for as long as it uses the ETRM system.  The Company is currently utilizing the ETRM system and will continue to make enhancements to the system as necessary in future periods.

Capacity Charge Commitments

The Company enters into agreements to transport and store natural gas.  Since the demand for natural gas in the winter is high, the Company agrees to pay for certain capacity for the transportation systems utilized for up to a twelve-month period.  These agreements are take-or-pay in that if the Company does not use the capacity, it still must pay for capacity committed.  For contracts outstanding, as of June 30, 2008, the total committed capacity charges were approximately $3.6 million.  These agreements will expire during various months in the fiscal year ending June 30, 2009, and will be replaced with new contracts as necessary.

Physical Commodity Purchase Commitments

The Company has forward physical contracts to acquire natural gas and electricity in specified future periods.   The contracts to acquire natural gas generally have a fixed basis component and a variable component determined based on market prices at purchase date.  Contracts to acquire electricity generally are on a fixed basis.  All such contracts are considered normal purchases under U.S. GAAP.

As of June 30, 2008 the Company had forward physical contracts to purchase a total of 7,092,000 MMBtus of natural gas beginning in July 2008 and ending in December 2009.  The amount of the fixed basis and variable components of these contracts were $1.8 million and $94.4 million, respectively, at June 30, 2008.

As of June 30, 2008, the Company had forward physical contracts to purchase a total of 170,000 MWhrs of electricity beginning in July 2008 and ending in March 2011.  These contracts, which are all on a fixed basis, amounted to $14.4 million at June 30, 2008.

As of June 30, 2008, total forward commitments to purchase natural gas and electricity were $103.3 million for fiscal year 2009, $6.4 million for fiscal year 2010 and $0.9 million for fiscal year 2011.

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Contingent Consideration Related to the GasKey Acquisition

Pursuant to the agreement that governs the GasKey Acquisition (refer to Note 4 of these consolidated financial statements), contingent consideration is payable to PS Energy Group, Inc. on a quarterly basis in arrears for volumes consumed and billed under certain customer contracts for a 36-month period subsequent to the acquisition date.  The payment will be determined for activity during each three-month period subsequent to the January 2008 closing of the GasKey Acquisition, and capitalized as part of customer acquisition costs.   The contingent consideration payable to PS Energy Group, Inc. for the six months ended June 30, 2008 was approximately $0.2 million.

Contingent Consideration Related to the Vantage Acquisition

In connection with the Vantage Acquisition (refer to Note 4 of these consolidated financial statements), the Company made an escrow deposit of $0.9 million, which Vantage is eligible to receive as additional consideration, subject to actual customer attrition and bad debt experience associated with customer accounts acquired from Vantage (the “Vantage Contingent Consideration”).  The funds in escrow are included in restricted cash on the Company’s consolidated balance sheet.  The Vantage Contingent Consideration will be evaluated at the end of each six-month period during the 18-month period following the May 17, 2007 closing date for the Vantage Acquisition.  As a result of the evaluations conducted during the fiscal year ended June 30, 2008, approximately $0.5 million of additional consideration was payable to Vantage from restricted cash.

The Company will also pay to Vantage an established percentage of the realized net margin associated with the purchased contracts for the original contract term up to a maximum of two years after the closing of the Vantage Acquisition.  These margin-sharing payments are not expected to be material.

Contingent Consideration Related to the Acquisition of Castle Power LLC

On November 1, 2005, the Company acquired certain natural gas customer contracts of Castle Power LLC (“Castle”).  Pursuant to an ongoing agreement, contingent consideration is payable to Castle on a quarterly basis in arrears for volumes consumed and paid for on certain customer contracts acquired from Castle.  The payment is determined at the end of each quarter and capitalized as part of customer acquisition costs.  The contingent consideration payable to Castle for activity during the fiscal year ended June 30, 2008 was approximately $0.1 million.

Litigation

From time to time, the Company is a party to claims and legal proceedings that arise in the ordinary course of business, including investigations of product pricing and billing practices by various governmental or other regulatory agencies.  Management does not believe that any such proceedings to which the Company is currently a party will have a material impact on the Company’s results of operations or financial position.

The Company does not have physical custody or control of any of the natural gas that is ultimately provided to its customers, and does not have physical custody or control over any facilities used to transport natural gas to its customers.  Title to the natural gas sold to the Company’s customers is passed at the same point at which the Company accepts title from its natural gas suppliers.  Therefore, management does not believe that the Company has significant exposure to legal claims or other liabilities associated with environmental concerns.

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Note 21.  Business Segments

The Company’s core business is the retail sale of natural gas and electricity to end-use customers in deregulated markets.  Accordingly, the Company’s business is classified into two business segments: natural gas and electricity.  Through these business units, natural gas and electricity are sold at contracted prices based on the demand or usage of customers.

Prior to the fourth quarter of the fiscal year ended June 30, 2007, the Company had reported three business segments: residential and small commercial natural gas (mass market); mid-market commercial natural gas; and electricity.  Effective in the fourth quarter of fiscal 2007, the Company no longer considered the mass market and mid-market natural gas markets to be separate reportable segments, based on the following rationale:

·Management does not evaluate or manage the mid-market commercial natural gas business in a manner distinct from the mass market;

·Natural gas and electricity are each managed as overall portfolios;

·Supply of natural gas is handled consistently for both mass markets and mid-markets;

·In assessing risk for the natural gas business, no separation is made for mass market and mid-market risk exposures; and

·The mid-market commercial natural gas is not a significant component of the overall gas business.

As a result, the Company has revised financial information for the fiscal year ended June 30, 2006 to conform to the presentation for the fiscal years ended June 30, 2008 and 2007.

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Financial information for the Company’s business segments is summarized in the following tables.

Fiscal year ended June 30	Natural Gas			Electricity			Total
	(in thousands)
2008:
Sales	$	669,522		$	82,761		$	752,283
Cost of goods sold (1)	(564,219		)	(72,534		)	(636,753		)
Gross profit (1)	$	105,303		$	10,227		115,530
Items to reconcile total segment gross profit to income before income tax expense
Unrealized gains (losses) from risk management activities							67,168
Operating expenses							(106,645		)
Interest expense, net of interest income							(34,105		)
Income before income tax expense							$	41,948
Assets and liabilities allocated to business segments at period end:
Accounts receivable, net	$	65,897		$	21,776		$	87,673
Natural gas inventories	65,006			—			65,006
Goodwill	3,810			—			3,810
Customer acquisition costs, net	34,439			7,254			41,693
Total Assets	$	169,152		$	29,030		$	198,182
2007:
Sales	$	680,811		$	23,115		$	703,926
Cost of goods sold (1)	(565,531		)	(19,536		)	(585,067		)
Gross profit (1)	$	115,280		$	3,579		118,859
Items to reconcile total segment gross profit to loss before income tax benefit:
Unrealized gains (losses) from risk management activities							(17,079		)
Operating expenses							(91,015		)
Interest expense, net of interest income							(33,058		)
Loss before income tax benefit							$	(22,293	)
Assets and liabilities allocated to business segments at period end:
Accounts receivable	$	42,069		$	6,252		$	48,321
Natural gas inventories	56,547			—			56,547
Goodwill	3,810			—			3,810
Customer acquisition costs, net	36,626			2,328			38,954
Total Assets	$	139,052		$	8,580		$	147,632
2006:
Sales	$	345,629		$	16,932		$	362,561
Cost of goods sold (1)	(296,607		)	(13,022		)	(309,629		)
Gross profit (1)	$	49,022		$	3,910		52,932
Items to reconcile total segment gross profit to loss before income tax benefit:
Unrealized gains (losses) from risk management activities							(79,897		)
Operating expenses							(36,618		)
Interest expense, net of interest income							(3,200		)
Loss before income tax benefit							$	(66,783	)

(1) Includes realized losses from risk management activities, but excludes unrealized gains (losses) from risk management activities. As the underlying customer contracts are not marked to market, the unrealized gains (losses) from risk management activities do not offer an accurate indication of the ultimate cash impact to the business, as the ultimate cash impact to the business is not determinable until delivery of natural gas under the customer contracts and the associated gain (loss) on risk management activity is realized.

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Note 22.  Condensed Consolidating Financial Information

The Senior Notes were issued by Holdings in August 2006.  Each of the following wholly owned domestic subsidiaries of Holdings (the “Guarantor Subsidiaries”) jointly, severally and unconditionally guarantees the Senior Notes on a senior unsecured basis:

· MXenergy Capital Holdings Corp.

· MXenergy Capital Corp.

· Online Choice Inc.

· MXenergy Gas Capital Holdings Corp.

· MXenergy Gas Capital Corp.

· MXenergy Inc.

· MXenergy Electric Capital Holdings Corp.

· MXenergy Electric Capital Corp.

· MXenergy Electric Inc.

· Total Gas & Electric, Inc. (effective in August 2006, Total Gas & Electric, Inc. was merged with and into MXenergy Inc.)

· Total Gas & Electricity (PA) Inc., d/b/a/ MXenergy Electric (PA) (effective in May 2007, Total Gas & Electricity (PA) Inc. was merged with and into MXenergy Electric Inc.)

· MXenergy Services Inc.

· Infometer.com Inc.

The only wholly owned subsidiary that is not a guarantor for the Senior Notes (the “Non-guarantor Subsidiary”) is MXenergy (Canada) Ltd.

Consolidating balance sheets, consolidating statements of operations and consolidating statements of cash flows for Holdings, the combined Guarantor Subsidiaries and the Non-guarantor Subsidiary are provided in the following tables.  Elimination entries necessary to consolidate the entities are also presented.  Prior to the three months ended March 31, 2008, the Company’s Senior Notes and related interest expense were reported as a liability and expense, respectively, for Holdings in the Company’s consolidating financial statements.  During the three months ended March 31, 2008, the Company revised its consolidation methodology to allocate the Senior Notes and the related interest expense to its Guarantor Subsidiaries.  Consolidating financial information reflected in the consolidating balance sheets as of June 30, 2007 and 2006 and the consolidating statements of operations and cash flows for the fiscal years ended June 30,  2007 and 2006 has been conformed to the current year’s presentation.

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MXenergy Holdings Inc.

Consolidating Balance Sheet

June 30, 2008

(dollars in thousands)

	MXenergy Holdings Inc.			Non-guarantor Subsidiary			Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	—		$	970		$	70,988	$	—		$	71,958
Restricted cash	—			—			587					587
Due from intercompany	184,200			—			—		(184,200		)	—
Accounts receivable, net	—			28			87,645					87,673
Natural gas inventories	—			—			65,006					65,006
Current portion of unrealized gains from risk management activities	183			—			35,681					35,864
Income taxes receivable	7,524			—			—					7,524
Other current assets	—			302			3,059					3,361
Total current assets	191,907			1,300			262,966		(184,200		)	271,973
Unrealized gains from risk management activities	234						12,987					13,221
Goodwill	—						3,810					3,810
Customer acquisition costs, net	—			68			41,625					41,693
Fixed assets, net	—			—			10,525					10,525
Deferred income taxes	10,503			—			10,503		(10,503		)	10,503
Long-term investments	45,820			—			—		(45,820		)	—
Other assets	3,134			—			893					4,027
Total assets	$	251,598		$	1,368		$	343,309	$	(240,523	)	$	355,752
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	8,816		$	306		$	27,480	$	—		$	36,602
Accrued commodity purchases	—			612			50,849					51,461
Due to intercompany	—			1,912			185,590		(187,502		)	—
Current portion of unrealized losses from risk management activities	2,187			—			791					2,978
Deferred revenue	—			—			7,435					7,435
Deferred income taxes	9,800			—			9,800		(9,800		)	9,800
Total current liabilities	20,803			2,830			281,945		(197,302		)	108,276
Unrealized losses from risk management activities	2,839			—			—					2,839
Long-term debt:
Floating Rate Senior Note Due 2011	162,648			—			—					162,648
Total long term debt	162,648			—			—		—			162,648
Total liabilities	186,290			2,830			281,945		(197,302		)	273,763
Redeemable Convertible Preferred Stock	48,779			—			—					48,779
Commitments and contingencies	—			—			—		—			—
Stockholders’ equity
Common stock	36			1			—		(1		)	36
Additional paid-in-capital	23,635			—			—					23,635
Contributed capital	819			—			42,401		(43,220		)	—
Unearned stock compensation	(4		)	—			—					(4		)
Accumulated other comprehensive loss				(189		)	—					(189		)
Retained earnings	(7,957		)	(1,274		)	18,963					9,732
Total stockholders’ equity	16,529			(1,462		)	61,364		(43,221		)	33,210
Total liabilities and stockholders’ equity	$	251,598		$	1,368		$	343,309	$	(240,523	)	$	355,752

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MXenergy Holdings Inc.

Consolidating Balance Sheet

June 30, 2007

(dollars in thousands)

	MXenergy			Non-guarantor			Guarantor
	Holdings Inc.			Subsidiary			Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	—		$	138		$	136,804		$	—		$	136,942
Restricted cash	—			—			1,050						1,050
Due from intercompany	174,655			—			—			(174,655		)	—
Accounts receivable, net	—			121			48,200						48,321
Natural gas inventories	—			—			56,547						56,547
Current portion of unrealized gains from risk management activities	—			—			50						50
Income taxes receivable	351			—			—						351
Deferred income taxes	9,136			—			9,136			(9,136		)	9,136
Other current assets	—			152			5,159						5,311
Total current assets	184,142			411			256,946			(183,791		)	257,708
Goodwill	—			—			3,810						3,810
Customer acquisition costs, net	—			73			38,881						38,954
Fixed assets, net	—			—			17,849						17,849
Deferred income taxes	9,754			—			9,754			(9,754		)	9,754
Long-term investments	43,112			—			—			(43,112		)	—
Other assets	4,477			—			3,092						7,569
Total assets	$	241,485		$	484		$	330,332		$	(236,657	)	$	335,644
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	9,846		$	163		$	21,519		$	—		$	31,528
Accrued commodity purchases	—			105			31,192						31,297
Due to intercompany	—			1,581			186,703			(188,284		)	—
Current Portion of unrealized losses from risk management activities	544			—			16,530						17,074
Deferred Revenue	—			—			11,787						11,787
Total current liabilities	10,390			1,849			267,731			(188,284		)	91,686
Unrealized losses from risk management activities	775			—			2,811						3,586
Long-term debt:
Floating Rate Senior Note due 2011	174,404			—			(40		)				174,364
Denham Credit Facility	—			—			11,040						11,040
Total long term debt	174,404			—			11,000			—			185,404
Total liabilities	185,569			1,849			281,542			(188,284		)	280,676
Redeemable Convertible Preferred Stock	29,357			—			—						29,357
Commitments and Contingencies	—			—			—			—			—
Stockholders’ Equity (Deficit)
Common stock	34			1			—			(1		)	34
Additional paid-in-capital	21,367			—			—						21,367
Contributed capital	819			—			42,401			(43,220		)	—
Unearned stock compensation	(22		)	—			—						(22		)
Accumulated other comprehensive loss	—			(129		)	—						(129		)
Retained earnings (deficit)	4,361			(1,237		)	6,389			(5,152		)	4,361
Total stockholders’ equity (deficit)	26,559			(1,365		)	48,790			(48,373		)	25,611
Total liabilities and stockholders’ equity (deficit)	$	241,485		$	484		$	330,332		$	(236,657	)	$	335,644

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MXenergy Holdings Inc.

Consolidating Statement of Operations

Year Ended June 30, 2008

(dollars in thousands)

	MXenergy			Non-guarantor			Guarantor
	Holdings Inc.			Subsidiary			Subsidiaries			Eliminations			Consolidated
Sales of natural gas and electricity	$	—		$	1,481		$	750,802		$	—		$	752,283
Cost of goods sold (excluding depreciation and amortization):
Cost of natural gas and electricity sold	—			1,402			628,604						630,006
Realized losses from risk management activities	—			—			6,747						6,747
Unrealized losses from risk management Activities	—			—			(67,168		)				(67,168		)
	—			1,402			568,183			—			569,585
Gross profit	—			79			182,619			—			182,698
Operating expenses:
General and administrative expenses	117			505			61,649						62,271
Advertising and marketing expenses	—			(426		)	4,972						4,546
Reserves and discounts	—			—			7,130						7,130
Depreciation and amortization	—			36			32,662						32,698
Equity in operations of consolidated subsidiaries	(27,584		)	—			—			27,584			—
Total operating expenses	(27,467		)	115			106,413			27,584			106,645
Operating profit (loss)	27,467			(36		)	76,206			(27,584		)	76,053
Interest expense, net	3,290			—			30,815			—			34,105
Income (loss) before income tax (expense) benefit	24,177			(36		)	45,391			(27,584		)	41,948
Income tax (expense) benefit	(17,155		)				(17,771		)	17,771			(17,155		)
Net income (loss)	$	7,022		$	(36	)	$	27,620		$	(9,813	)	$	24,793

98

MXenergy Holdings Inc.

Consolidating Statement of Operations

Year Ended June 30, 2007

(dollars in thousands)

	MXenergy			Non-guarantor			Guarantor
	Holdings Inc.			Subsidiary			Subsidiaries			Eliminations			Consolidated
Sales of natural gas and electricity	$	—		$	1,292		$	702,634		$	—		$	703,926
Cost of goods sold (excluding depreciation and amortization):
Cost of natural gas and electricity sold	—			1,267			550,761						552,028
Realized losses from risk management activities	—			—			33,039						33,039
Unrealized losses from risk management Activities	—			—			17,079						17,079
	—			1,267			600,879			—			602,146
Gross profit	—			25			101,755			—			101,780
Operating expenses:
General and administrative expenses	—			339			54,177						54,516
Advertising and marketing expenses	—			4			4,040						4,044
Reserves and discounts	—			—			4,725						4,725
Depreciation and amortization	—			91			27,639						27,730
Equity in operations of consolidated subsidiaries	15,326			—			—			(15,326		)	—
Total operating expenses	15,326			434			90,581			(15,326		)	91,015
Operating (loss) profit	(15,326		)	(409		)	11,174			15,326			10,765
Interest expense, net	(3,144		)	—			36,202			—			33,058
(Loss) income before income tax benefit (expense)	(12,182		)	(409		)	(25,028		)	15,326			(22,293		)
Income tax (expense) benefit	8,495						10,111			(10,111		)	8,495
Net (loss) income	$	(3,687	)	$	(409	)	$	(14,917	)	$	5,214		$	(13,798	)

99

MXenergy Holdings Inc.

Consolidating Statement of Operations

Year Ended June 30, 2006

(dollars in thousands)

	MXenergy			Non-
	Holdings Inc.			guarantor Subsidiary			Guarantor Subsidiaries			Eliminations			Consolidated
Sales of natural gas and electricity	$	—		$	1,271		$	361,290		$	—		$	362,561
Cost of goods sold (excluding depreciation and amortization)
Cost of natural gas and electricity sold	—			1,697			390,915						392,612
Realized losses from risk management activities	—			—			(82,983		)				(82,983		)
Unrealized losses from risk management activities	—			—			79,897						79,897
	—			1,697			387,829			—			389,526
Gross loss	—			(426		)	(26,539		)	—			(26,965		)
Operating expenses:
General and administrative expenses	911			107			21,605						22,623
Advertising and marketing expenses	—			1			2,095						2,096
Reserves and discounts	—			—			3,395						3,395
Depreciation and amortization	—			107			8,397						8,504
Equity in operations of consolidated subsidiaries	38,686			—			—			(38,686		)	—
Total operating expenses	39,597			215			35,492			(38,686		)	36,618
Operating (loss) profit	(39,597		)	(641		)	(62,031		)	38,686			(63,583		)
Interest expense, net	641			—			2,559			—			3,200
(Loss) income before income tax benefit (expense)	(40,238		)	(641		)	(64,590			38,686			(66,783		)
Income tax benefit (expense)	27,001			192			26,353			(26,545		)	27,001
Net (loss) income	$	(13,237	)	$	(449	)	$	(38,237	)	$	12,141		$	(39,782	)

100

MXenergy Holdings Inc.

Consolidating Statement of Cash Flows

Year Ended June 30, 2008

(dollars in thousands)

	MXenergy			Non-guarantor			Guarantor
	Holdings Inc.			Subsidiary			Subsidiaries			Eliminations			Consolidated
Operating activities:
Net income (loss)	$	7,022		$	(36	)	$	27,620		$	(9,813	)	$	24,793
Adjustments to reconcile net income (loss) to net cash (used in) provided by operating activities:
Unrealized losses (gains) from risk management activities	—			—			(67,168		)				(67,168		)
Stock compensation expense	—			—			1,704						1,704
Depreciation and amortization	—			36			32,662						32,698
Deferred income tax expense (benefit)	18,187			—			18,187			(18,187		)	18,187
Unrealized losses on interest rate swaps and amortization of deferred financing fees	3,290			—			7,546						10,836
Amortization of customer contracts acquired	—			—			(762		)				(762		)
Equity in operations of consolidated subsidiaries	(27,584		)	—			—			27,584			—
Changes in assets and liabilities, net of effects of acquisition:
Restricted cash	—			—			463						463
Accounts receivable	(1,787		)	93			(30,274		)	1,787			(30,181		)
Natural gas inventories	—			—			(7,308		)				(7,308		)
Income taxes receivable	(7,173		)	—			(7,173		)	7,173			(7,173		)
Option premiums	—			—			1,191						1,191
Other assets	1,344			(194		)	(541		)				609
Accounts payable, accrued commodity purchases and accrued liabilities	758			981			(3,718		)	19,861			17,882
Deferred revenue	—			—			(4,352		)				(4,352		)
Net cash (used in) provided by operating activities	(5,943		)	880			(31,923		)	28,405			(8,581		)
Investing activities:
Long-term investments	28,405			—			—			(28,405		)	—
Loan to PS Energy Group Inc. related to purchase of GasKey assets	—			—			(8,983		)				(8,983		)
Cash received from to PS Energy Group, Inc. for repayment of loan	—			—			8,983						8,983
Purchase of GasKey assets	—			—			(12,427		)				(12,427		)
Customer acquisition costs	—			(47		)	(19,508		)				(19,555		)
Purchases of fixed assets	—			—			(1,959		)				(1,959		)
Net cash (used in) provided by investing activities	28,405			(47		)	(33,894		)	(28,405		)	(33,941		)
Financing activities:
Repayment of Denham Credit facility	(11,040		)	—			—						(11,040		)
Repurchase of senior notes	(12,006		)	—			—						(12,006		)
Issuance of common stock and exercise of warrants and options	387			—			—						387
Issuance of common stock from other executive compensation	952			—			—						952
Purchase and cancellation of treasury shares, net of tax benefit	(755		)	—			—						(755		)
Net cash used in financing activities	(22,462		)	—			—			—			(22,462		)
Net increase (decrease) in cash	—			833			(65,817		)	—			(64,984		)
Cash and cash equivalents at beginning of year	—			137			136,805			—			136,942
Cash and cash equivalents at end of year	$	—		$	970		$	70,988		$	—		$	71,958

101

MXenergy Holdings Inc.

Consolidating Statement of Cash Flows

Year Ended June 30, 2007

(dollars in thousands)

	MXenergy			Non-guarantor			Guarantor
	Holdings Inc.			Subsidiary			Subsidiaries			Eliminations			Consolidated
Operating activities:
Net income (loss)	$	(3,687	)	$	(409	)	$	(14,917	)	$	5,214		$	(13,798	)
Adjustments to reconcile net loss to net cash (used in) provided by operating activities:
Unrealized losses from risk management activities	—			—			17,079						17,079
Stock compensation expense	—			—			4,539						4,539
Depreciation and amortization	—			91			27,639						27,730
Deferred income tax benefit	(14,449		)	—			(14,449		)	14,449			(14,449		)
Unrealized losses on interest rate swaps and amortization of deferred financing fees	1,187			—			6,719						7,906
Amortization of customer contracts acquired	—			—			11,891						11,891
Equity in operations of consolidated subsidiaries	15,326			—			—			(15,326		)	—
Changes in assets and liabilities, net of effects of acquisition:
Restricted cash							(623		)				(623		)
Accounts receivable, net	(199,765		)	(147		)	3,600			199,765			3,453
Natural gas inventories	—			—			(1,712		)				(1,712		)
Income taxes receivable	5,184			—			—						5,184
Option premiums	—			—			1,835						1,835
Other assets				(69		)	(924		)				(993		)
Accounts payable, accrued commodity purchases and accrued liabilities	9,846			620			84,349			(63,260		)	31,555
Deferred revenue	—			—			9,384						9,384
Net cash (used in) provided by operating activities	(186,358		)	86			134,410			140,842			88,981
Investing activities:
Long-term investments	140,842			—			—			(140,842		)	—
Purchase of SESCo assets	(126,044		)	—			—						(126,044		)
Deposit and capitalized costs related to purchase of SESCo assets	3,348			—			—						3,348
Purchase of Vantage assets	(732		)	—			—						(732		)
Customer acquisition costs	—			(95		)	(7,515		)				(7,610		)
Purchases of fixed assets	—			—			(1,882		)				(1,882		)
Net cash used in investing activities	17,414			(95		)	(9,397		)	(140,842		)	(132,920		)
Financing activities:
Proceeds from loans	—			—			6,000						6,000
Repayments of loans	—			—			(6,000		)				(6,000		)
Debt financing costs	(4,149		)	—			(5,196		)				(9,345		)
Proceeds from Denham Credit Facility	—			—			23,040						23,040
Repayment of Denham Credit Facility	—			—			(12,000		)				(12,000		)
Proceeds from bridge loan	190,000			—			—						190,000
Repayment of bridge loan	(190,000		)	—			—						(190,000		)
Proceeds from Senior Notes	185,250			—			—						185,250
Repurchase of Senior Notes	(11,723		)	—			—						(11,723		)
Issuance of common stock and exercise of warrants and options	22			—			—						22
Purchase and cancellation of treasury shares, net of tax benefit	(456		)	—			—						(456		)
Net cash provided by financing activities	168,944			—			5,844			—			174,788
Net (decrease) increase in cash and cash equivalents	—			(9		)	130,857			—			130,849
Cash and cash equivalents at beginning of year	—			146			5,947			—			6,093
Cash and cash equivalents at end of year	$	—		$	137		$	136,805		$	—		$	136,942

102

MXenergy Holdings Inc.

Consolidating Statement of Cash Flows

Year Ended June 30, 2006

(dollars in thousands)

	MXenergy			Non-Guarantor			Guarantor
	Holdings Inc.			Subsidiary			Subsidiaries			Eliminations			Consolidated
Operating activities:
Net income (loss)	$	(13,237	)	$	(449	)	$	(38,238	)	$	12,142		$	(39,782	)
Adjustments to reconcile net (loss) income to net cash (used in) provided by operating activities:
Unrealized losses from risk management activities	—			—			79,897						79,897
Stock compensation expense	911			—			—						911
Depreciation and amortization	—			107			8,397						8,504
Deferred income tax benefit	(32,764		)	—			(32,764		)	32,764			(32,764		)
Unrealized losses on interest rate swaps and amortization of deferred financing fees	641			—			416						1,057
Amortization of customer contracts acquired	—			—			(3,276		)				(3,276		)
Equity in operations of consolidated subsidiaries	38,686			—			—			(38,686		)	—
Changes in assets and liabilities, net of effects of acquisition:
Restricted cash	—			—			6,953						6,953
Accounts receivable, net	—			88			(13,091		)				(13,003		)
Natural gas inventories	—			—			(2,685		)				(2,685		)
Income taxes receivable	(5,535		)	—			—						(5,535		)
Option premiums	—			—			(1,834		)				(1,834		)
Other assets	(505		)	(72		)	3,222						2,645
Accounts payable, accrued commodity purchases and accrued liabilities	(27,675		)	176			(42,922		)	65,101			(5,320		)
Deferred Revenue	—			—			865						865
Net cash (used in) provided by operating activities	(39,478		)	(150		)	(35,060		)	71,321			(3,367		)
Investing activities:
Long-term investments	71,321			—			—			(71,321		)	—
Deposit and capitalized costs related to purchase of SESCo assets	(3,348		)	—			—						(3,348		)
Purchase of Castle customer portfolio	(3,150		)	—			—						(3,150		)
Customer acquisition costs	—			—			(6,149		)				(6,149		)
Purchases of fixed assets	—			—			(6,178		)				(6,178		)
Net cash provided by (used in) investing activities	64,823			—			(12,327		)	(71,321		)	(18,825		)
Financing activities:													—
Proceeds from loans	210,123			—			—						210,123
Repayments of loans	(226,502		)	—			—						(226,502		)
Debt Financing costs	(2,347		)	—			—						(2,347		)
Repayments of long term borrowings	(5,000		)	—			—						(5,000		)
Issuance of common stock and exercise of warrants	532			—			—						532
Purchase and cancellation of treasury shares, net of tax benefit	(2,151		)	—			—						(2,151		)
Net cash used in by financing activities	(25,345		)	—			—			—			(25,345		)
Net decrease in cash	—			(150		)	(47,387		)	—			(47,537		)
Cash and cash equivalents at beginning of year	—			296			53,334						53,630
Cash and cash equivalents at end of year	$	—		$	146		$	5,947		$	—		$	6,093

103

ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A(T).  CONTROLS AND PROCEDURES

We maintain a system of internal and disclosure controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Securities and Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported on a timely basis. Our Board of Directors, operating through its Audit Committee, provides oversight to the financial reporting process.

An evaluation was conducted, with the participation of the Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Annual Report Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of the end of the period covered by this Annual Report so as to alert them in a timely fashion to material information required to be disclosed in our reports filed pursuant to the Exchange Act.

There were no changes in our internal controls over financial reporting during the fourth quarter of our fiscal year ended June 30, 2008.

Section 404 of the Sarbanes-Oxley Act of 2002 (“Section 404”) requires management to report on, and external auditors to attest to, the effectiveness of our internal control structure and procedures for financial reporting.  As a non-accelerated filer under Rule 12b-2 of the Exchange Act, the first report of our management under Section 404 is included in this Annual Report.  Management’s report on internal control over financial reporting is included on the following page of this Annual Report.

This Annual Report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting.  Management’s report was not subject to attestation by our registered public accounting firm pursuant to temporary rules of the SEC that permit us to provide only management’s report in this Annual Report.

104

Report of Management on Internal Control over Financial Reporting

October 14, 2008

Management is responsible for establishing and maintaining an adequate internal control structure and procedures over financial reporting as defined in Rule 13a-15f of the Securities and Exchange Act of 1934, as amended, and has completed an assessment of the effectiveness of MXenergy Holdings Inc.’s (the “Company’s”) internal control over financial reporting as of June 30, 2008.  In making this assessment, management used the criteria related to internal control over financial reporting described in “Internal Control – Integrated Framework” established by the Committee of Sponsoring Organizations of the Treadway Commission.

Based on the assessment performed, management concluded that, as of June 30, 2008, the Company’s internal control over financial reporting was effective.

/s/ JEFFREY A. MAYER

Jeffrey A. Mayer

President and
Chief Executive Officer

(Principal executive officer)

/s/ CHAITU PARIKH

Chaitu Parikh

Chief Financial Officer

(Principal financial officer and principal accounting officer)

105

ITEM 9B. OTHER INFORMATION

On June 9, 2008, Holdings entered into the First Amendment to Third Amended and Restated Stockholders’ Agreement (The “Stockholders’ Agreement Amendment”) with Charter MX LLC, Denham Commodity Partners Fund L.P. and other stockholders holding a majority of the outstanding shares of our voting stock.  Pursuant to the Stockholders’ Agreement Amendment, transfers of stock for no consideration to certain not-for-profit entities were added as transfers permitted by the Third Amended and Restated Stockholder’s Agreement.  The Stockholders’ Agreement Amendment is included in as Exhibit 10.23 of this Annual Report.

On September 30, 2008, MXenergy Inc. into the Fifth Amendment to Master Transaction Agreement with Holdings and certain of its subsidiaries, as guarantors, and Société Générale, as hedge provider.  This amendment revised the termination date of the Company’s Hedge Agreement to be the earlier of: (a) 30 days prior to the maturity date of the Revolving Credit Agreement; of (b) July 1, 2009. The Fifth Amendment to Master Transaction Agreement is included as Exhibit 10.21 of this Annual Report.

106

PART III.

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Executive Officers and Directors

Our Board of Directors consists of eight members.  Refer to “Item 13.  Certain Relationships and Related Transactions, and Director Independence” for commentary regarding director independence.  All of our executive officers serve at the discretion of our Board of Directors, subject to their employment agreements described under “Item 11.  Executive Compensation.”

The names and positions of our current executive officers and directors are presented in the following table.  Descriptions of the business experience of our executive officers and directors follow the table.

Name	Age	Position
Jeffrey A. Mayer	56	President, Chief Executive Officer and Director
Steven Murray	48	Chief Operating Officer and Director
Carole R. (“Robi”) Artman-Hodge	57	Executive Vice President and Director
Chaitu Parikh	39	Vice President and Chief Financial Officer
Robert Blake	52	Vice President, Electricity Operations & Regulatory Affairs
Gina Goldberg	50	Vice President, Marketing
Robert Werner	52	Vice President, Supply
Daniel Bergstein	65	Director
Michael J. Hamilton	61	Director
William Landuyt	52	Director
Stuart Porter	42	Director
John Stewart	66	Director

Jeffrey A. Mayer is a co-founder of the Company and has been its President and Chief Executive Officer since 1999.  He has served as a director of Holdings since 2005. From 1992 to 1999, Mr. Mayer worked for Sempra Trading Corporation, a subsidiary of Sempra Energy (prior to 1997, known as AIG Trading Corporation, a subsidiary of AIG), and served as its Managing Director in charge of natural gas derivatives marketing.  While at Sempra, he worked on the launch of a retail energy marketing joint venture.  Prior to joining AIG, Mr. Mayer worked at Goldman, Sachs & Co. where he managed the Energy Futures Department from 1989 to 1992, worked in the Futures Services Department from 1987 to 1989 and served as Chief Counsel of its J. Aron Commodities Division from 1984 to 1987.  Mr. Mayer developed the Energy Traders Institute, a seminar on risk management sponsored by Infocast and heard by dozens of utilities and energy producers in North America.  Mr. Mayer has provided consulting services to Northeast Utilities and the Chicago Board of Trade Clearing Corporation.  Mr. Mayer serves as Chairman of the Board of Finance of Westport, CT, an elected office in which he serves as chairman of the town’s municipal pension plans, reviews budgets and votes on the tax rate.  Mr. Mayer served as Chairman of AIG Clearing Corporation, the futures clearing arm of AIG Trading, and Chairman of AIG Securities Corporation, the securities affiliate of AIG Trading.

107

Steven Murray has been Chief Operating Officer of the Company since August 2006  and has served as a director of Holdings since 2006.  Previously, Mr. Murray had a 25-year career with the Royal Dutch Shell group of companies, where he most recently served as Chief Executive Officer of SESCo from 2001 to August 2006 and as First President and Chief Executive Officer of Shell Trading US Co. from 1998 to 2001.  He served as General Manager of Higher Olefins and Derivatives Businesses of Shell Chemical LP since December 2005, where he oversaw marketing activity in over 50 countries, operations for plants located in the United States, the United Kingdom, New Zealand and South Africa, as well as research and development activities in North America and The Netherlands.  Mr. Murray has previously served as Vice Chairman of the National Energy Marketers Association as well as a member of the board of the Soapers and Detergents Association.

Carole R. (“Robi”) Artman-Hodge has been Executive Vice President of the Company since 1999 and served as Chief Operating Officer from 1999 to August 2006.  She has served as a director of Holdings since 2005. Prior to co-founding the Company, Ms. Artman-Hodge worked as senior managing director of the Project Finance unit of Bank of Ireland from 1997 to 1998, senior managing director of Risk Management and Origination for the Natural Resources unit of ING from 1989 to 1996, senior managing director of the Commodity Finance and Treasury Marketing unit of Banque Paribas from 1981 to 1989 and Assistant Treasurer of the international banking unit of Harris Bank from 1977 to 1981.

Chaitu Parikh has been Chief Financial Officer and Vice President of Finance of the Company since July 2004 and serves as its Principal Accounting Officer and Assistant Treasurer.  Mr. Parikh served as Vice President of Finance of the Company from December 2002 to July 2004.  Prior to joining the Company, Mr. Parikh served as Vice President and Controller of The New Power Company from October 2001 to December 2002 and as the Chief Financial Officer of Alliance Energy Services from December 1996 to July 2001.  Previously, Mr. Parikh served in public accounting with KPMG from 1991 to 1996.  Mr. Parikh holds a CA designation from the Canadian Institute of Chartered Accountants.

Robert Blake has been Vice President of Electricity Operations & Regulatory Affairs of the Company since June 2004.  Mr. Blake served as Vice President of Customer Operations for the Company from April 2001 to May 2004.  Prior to joining the Company, Mr. Blake served as Manager of United Energy from January 2000 to March 2001, and served as Regional Sales Director for Conectiv Energy from April 1998 to January 2000.  From 1980 to March 1998, Mr. Blake worked for United Illuminating, an electric utility in Connecticut, where he served as Director of Commercial & Industrial Energy Services.  He has been involved with numerous national and regional electricity and energy committees and has held leadership positions with several regional energy groups, including chairing a NEPOOL task force.

Gina Goldberg has served as Vice President of Sales and Marketing of the Company since February 2004.  Prior to joining the Company as a consultant in November 2003, Ms. Goldberg held various marketing positions at Showtime Networks Inc. from 1984 to 2003, including the position of Senior Vice President of Marketing from 1998 to 2003.  Ms. Goldberg also served as a member of the Viacom Inc. Marketing Board Council from 1998 to 2003.  Previously, Ms. Goldberg worked in the Marketing Department of The Dallas Morning News from 1981 to 1984.

Robert Werner has been Vice President of Supply of the Company since August 2006.  Prior to joining the Company, Mr. Werner had a 28-year career with Royal Dutch Shell in energy trading, supply chain management, and pipeline engineering and operations.  From 2002 to 2006, Mr. Werner served as Vice President of Supply for SESCo, responsible for natural gas supply, commodity price exposure management and pricing.  Prior to completing a two-year assignment in trading process and systems redesign in 2002, Mr. Werner spent 14 years in a variety of roles trading crude oil in the United States, Africa, Europe and South America.  Mr. Werner has an M.B.A. from the University of Houston and a B.S. in Mechanical and Aerospace Engineering from Princeton University.  Mr. Werner is a retired professional engineer in the State of California.

108

Daniel Bergstein currently serves as a director of Holdings and has served as a director of the Company since 2000.  Mr. Bergstein currently serves as Chairman of the Compensation Committee, and also serves as a member of the Audit and Nominating and Governance Committees.  Since 1988, Mr. Bergstein has been a senior partner in the New York office of the international law firm Paul, Hastings, Janofsky & Walker LLP, where he is the Chairman of the firm’s global Telecommunications and Media practice.  Mr. Bergstein is also a co-founder of Cequel III LLC and a director of Cequel Communications, LLC, the 8th largest cable company in the United States.  He is also an advisory board member of Catalyst Investors I and II, L.P., two private equity investment funds specializing in telecom and media investments, a board member of SR. Teleperformance, S.A., a Paris stock exchange listed company, and a trustee and board member of The Foundation Fighting Blindness.

Michael J. Hamilton was elected as a director of Holdings on March 27, 2008, and currently serves as the Chairman of the Audit Committee and as a member of the Risk Oversight Committee.  Mr. Hamilton currently is Chairman and Chief Executive Officer of MMC Energy, Inc. a publicly traded merchant electricity generator that owns several generating units in California.  Prior to his current experience, Mr. Hamilton was the partner in charge of utility audit and tax at PricewaterhouseCoopers until he retired in 2003.  He served as a senior managing director at FTI Consulting where he specialized in bankruptcy and restructuring work, primarily in the merchant power industry.  Mr. Hamilton is a certified public accountant with an additional certification in business valuation and is a certified turnaround professional.

William Landuyt currently serves as a director of Holdings and has served as a director of the Company since 2004.  Mr. Landuyt currently serves as a member of the Audit, Compensation and Nominating and Governance Committees.  Mr. Landuyt is a senior partner at Charterhouse Group, Inc., a position he has held since December 2003.  From October 1996 until July 2003, Mr. Landuyt served as the Chief Executive Officer and Chairman of the Board of Millennium Chemicals, Inc.  Mr. Landuyt was previously employed by Hanson Industries where he served as President and Chief Executive Officer from June 1995 until October 1996.  Mr. Landuyt held the positions of Finance Director of Hanson Plc from 1992 until May 1995 and Director of Hanson Plc from 1992 until October 1996.  Mr. Landuyt served as Vice President and Chief Financial Officer of Hanson Industries from 1988 to 1992.

Stuart Porter currently serves as a director of Holdings and has served as a director of the Company since 2000.   Mr. Porter currently serves as Chairman of the Risk Oversight and Nominating and Governance Committees, and serves as a member of the Compensation Committee.  Since June 2007, Mr. Porter has been a principal of Denham Capital Management LP, and serves as Chief Investment Officer for the Denham Commodity Partners Funds.  From 2004 until 2007, Mr. Porter was a managing director at Sowood Capital Management LP and, during that period, managed the Sowood Commodity Partners Funds.  From 1996 to July 2004, Mr. Porter was employed as a Vice President and Portfolio Manager at Harvard Management Company, Inc. where he focused on relative value transactions in commodities and structured private transactions in the commodity sector.

John Stewart currently serves as a director of Holdings and has served as a director of the Company since 2000.  Mr. Stewart has been an attorney in private practice since 1981.  Mr. Stewart serves on the board of directors of P&B Woodworking and the Amity Art Foundation.  In addition, Mr. Stewart serves as the chairman of the Library Commission of Woodbridge, Connecticut.

Committees of the Board of Directors

Our Board of Directors has appointed four committees to help carry out its duties: the Audit Committee, the Compensation Committee, the Risk Oversight Committee and the Nominating and Governance Committee.

The Audit Committee consists of Mr. Michael J. Hamilton (Chair) and Messrs. Daniel Bergstein and William Landuyt.  The Board of Directors has determined that Messrs. Hamilton and Landuyt qualify as Audit Committee financial experts within the meaning of the SEC rules.  The Audit Committee makes recommendations to the Board of Directors regarding the selection of independent accountants, reviews the results and scope of audit and other services provided by our independent accountants and reviews and evaluates our internal audit and control functions.

The Compensation Committee consists of Mr. Daniel Bergstein (Chair) and Messrs. William Landuyt and Stuart Porter. The Compensation Committee administers our employee stock and other benefit plans and makes decisions concerning salaries and incentive compensation for our employees.

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The Risk Oversight Committee consists of Mr. Stuart Porter (Chair), Mr. Michael J. Hamilton, Ms. Carole R. Artman-Hodge and Messrs. Jeffrey Mayer, Steven Murray and Chaitu Parikh.  The Risk Oversight Committee establishes and oversees the Company’s risk management policies.

The Nominating and Governance Committee consists of Mr. Stuart Porter (Chair) and Messrs. Daniel Bergstein and William Landuyt.  The Nominating and Governance Committee identifies and recommends qualified individuals to serve as board and committee members, monitors the effectiveness of the Board of Directors and its committees and establishes the corporate governance guidelines for the Company.

Code of Ethics

We have adopted a Code of Business Conduct and Ethics (the “Code of Ethics”), which applies to our directors, officers and employees that meets the definition of a “code of ethics” required by Item 406 of Regulation S-K promulgated under the Exchange Act.  The purpose of the Code of Ethics is to promote a culture of honesty, integrity and respect for the law and the people who work at and with the Company.  A copy of the Code of Ethics is available on our website at www.mxholdings.com under the Corporate Governance link.  We intend to timely disclose any amendments to or waivers of certain provisions of the Code of Ethics applicable to our directors, executive officers, including our principal executive officer, principal financial officer and principal accounting officer on our website.

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ITEM 11. EXECUTIVE COMPENSATION

Compensation Committee Report

The Compensation Committee has reviewed and discussed with management the “Compensation Discussion and Analysis,” or CD&A, section required by Item 402(b) of Regulation S-K promulgated under the Exchange Act, which follows. Based on the Compensation Committee’s review and discussion with management, the Compensation Committee recommended to the Board of Directors that the CD&A be included in the Company’s Annual Report.

THE COMPENSATION COMMITTEE:

Daniel Bergstein (Chair)

William Landuyt

Stuart Porter

The information contained in the Compensation Committee Report shall not be deemed to be “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filings under the Securities Act or the Exchange Act, except to the extent that we specifically incorporate it by reference in such filing.

Compensation Discussion and Analysis for Named Executive Officers

As used herein, “named executive officers” refers to the Company’s principal executive officer (the “CEO”), the Company’s principal financial officer (the “CFO”) and the three executive officers of the Company, other than the CEO and CFO, who were the most highly compensated executive officers of the Company.

Overview of Compensation Program

The Compensation Committee is appointed by the Board of Directors to discharge the board’s responsibilities relating to:

·compensation of the Company’s executives;

·equity-based compensation plans, including, without limitation, stock option plans, in which officers or employees may participate; and

·arrangements with executive officers relating to their employment relationships with the Company, including, without limitation, provisions of formal employment agreements.

The Compensation Committee has overall responsibility for approving and evaluating executive officer compensation plans, policies and programs of the Company, as well as all equity-based compensation plans and policies. In addition, the Compensation Committee oversees, reviews and approves all of the Company’s ERISA and other significant employee benefit plans.

Overview of Compensation Philosophy and Objectives

The compensation of our named executive officers is based in part on the terms of our employment agreements with them and in part on our “pay-for-performance” philosophy on both an individual and corporate level.  We have adopted an approach to compensation that includes a mix of short-term and long-term components that are designed to provide proper incentives and to reward our senior management team for individual and corporate performance.

Our intent regarding the compensation of our executive officers is to provide salary and incentives that:

·attract and retain talented and experienced executives;

·motivate our executives to manage our business to meet our short-term and long-term business objectives;

·motivate the executives to increase stockholder value; and

·associate compensation with the achievement of certain short-term and long-term individual and corporate objectives.

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Role of Our Compensation Committee

Our Compensation Committee is responsible for administering our compensation practices. Our Compensation Committee consists of three directors who are “outside directors” for purposes of Section 162(m) of the Internal Revenue Code, as amended (the “Code”).

The Compensation Committee reviews and approves all employment agreements and administers all aspects of compensation for our executive officers, including:

·annual base salary level;

·participation in incentive-based compensation plans;

·participation in equity-based compensation plans; and

·awards of any special or supplemental benefits.

The Compensation Committee considers compensation recommendations from our CEO in determining executive compensation for all of the named executive officers, except in the case of the CEO.  The Compensation Committee, at its sole discretion, may accept or deny, in whole or in part, the recommendations of the CEO.  The Board of Directors is not required to approve the decisions of the Compensation Committee regarding compensation of executive officers.  The activities of the Compensation Committee are formally reported to the Board of Directors, and board members are encouraged to ask questions and review specific details regarding the decisions of the Compensation Committee.

Elements of Compensation

The compensation of our named executive officers consists primarily of five components:

·base salary;

·annual cash incentives;

·equity-based incentives;

·other benefits; and

·severance and termination protection.

We use a mix of short-term compensation (annual base salaries and cash incentives) and long-term compensation (equity-based incentives) to provide a total compensation structure that is designed to achieve our pay-for-performance philosophy and other compensation objectives.  Although the Compensation Committee has not adopted any formal guidelines for allocating total compensation between short-term and long-term portions, we believe it is important for our executive officers to have some actual or potential equity ownership in the Company to provide them with long-term incentives to improve corporate performance.

During fiscal year 2008, the Compensation Committee completed a formal benchmarking initiative to review our executive compensation levels in relation to a peer group of companies.  In addition, our Compensation Committee members are involved with a portfolio of small to mid-sized companies from which they can assess the appropriateness of executive compensation levels.

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Annual Cash Compensation

Annual Base Salary

We believe that a competitive base salary is a necessary element of any compensation program designed to attract and retain talented and experienced executives, and to motivate and reward executives for their overall performance.  In general, the base salaries of our named executive officers reflect:

·the initial base salaries that we negotiated with each of them at the time of their initial employment or promotion;

·consideration of  individual performance and increased experience;

·any changes in their appointed roles and responsibilities;

·consideration of the individuals contribution toward overall business performance;

·annual cost of living adjustment factors;

·results of any benchmarking initiatives to compare executive salaries to peer group companies;

·experience of the members of the Compensation Committee with executive salaries at other companies; and

·recommendations of the CEO, except in the case of the CEO.

The base salaries of our executive officers are reviewed and adjusted annually after their performance evaluations are completed.

Base salaries for our named executive officers are provided in the following table.

Name	Fiscal Year 2008		Fiscal Year 2007
Jeffrey Mayer	$	566,500	$	550,000
Chaitu Parikh	401,700		390,000
Steven Murray	463,500		450,000
Carole R. Artman-Hodge	390,000		390,000
Robert Werner	250,000		250,000

For fiscal year 2008, the Compensation Committee approved a 3% cost of living increase for Messrs. Mayer, Parikh and Murray to keep their salaries within targeted market levels.  Ms. Artman-Hodge and Mr. Werner did not receive a base salary increase for fiscal year 2008 because their base salary already exceeded targeted market levels for their respective positions with the Company.

Annual Cash Incentive Compensation

Our named executive officers have the opportunity to receive cash incentive awards tied to our overall performance and their individual performances.

The Compensation Committee establishes specific performance goals for the payment of annual bonuses which are based on specific business and individual performance factors, which are described in greater detail below.  The establishment of business and individual goals for each named executive officer reinforces two of our compensation goals: (1) to motivate our named executive officers toward even higher achievement and business results; and (2) to enable us to attract and retain highly qualified individuals.

Individual Performance Factors (“IPFs”) represent ratings assigned to the named executive officers that are based on accomplishment of individual goals.  IPFs are calculated after a systematic review of each named executive officer, which results in assessment of specific accomplishments and job skills that generally fall within the following categories: (1) leadership, team management and organizational skills; (2) primary job responsibilities; (3) judgment and decision-making; (4) individual attributes; (5) peer relationships; and (6) industry, departmental and company knowledge.  Mr. Mayer is graded by the Compensation Committee, while the other named executive officers are graded by his or her manager.  For Messrs. Mayer, Parikh and Murray and Ms. Artman-Hodge, the overall IPF rating is applied to 25% of their target bonus.  For Mr. Werner, the IPF rating is applied to 50% of his target bonus.  The Compensation Committee reviews proposed IPFs for the named executive officers.

Business Performance Factors (“BPFs”) represent corporate operational goals that are considered to be essential to

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the Company’s success for the fiscal year.  BPFs are used by the Company to assign an overall corporate rating from 0% to 100%, which is generally assigned to all employees of the Company.  For Messrs. Mayer, Parikh and Murray and Ms. Artman-Hodge, the overall BPF rating is applied to 75% of their target bonus.  For Mr. Werner, the BPF rating is applied to 50% of his target bonus.  The BPFs established by the Compensation Committee for the fiscal year ended June 30, 2008 were as follows:

·0% to 35% weighting for achievement of targeted levels of RCEs at June 30, 2008, including minimum profitability levels related to RCE additions;

·0% to 40% weighting for operational excellence, which is measured by accomplishment of key business performance factors including: (i) Sarbanes-Oxley compliance; (ii) successful completion of specific information system conversion and upgrade projects; (iii) successful integration of the GasKey Acquisition; and (iv) keeping actual operating expenses below forecasted amounts for fiscal year 2008; and

·0% to 25% weighting for achievement of forecasted Adjusted EBITDA for fiscal year 2008;

The cumulative result of the approved weightings is applied to that portion of the named executive officer’s bonus that is subject to the BPF weighting.  That cumulative result is then further adjusted for the named executive officer’s IPF rating.

Individual bonus amounts accrued for the named executive officers for the fiscal year ended June 30, 2008, subject to final approval by the Compensation Commitee and the Board of Directors, are summarized in the following table.

			Actual Payout
	Target% of		% of
Name	Salary (1)		Salary	Amount
Jeffrey Mayer	100	%	31	$	175,615
Chaitu Parikh	100	%	39	155,659
Steven Murray	100	%	39	179,606
Carole R. Artman-Hodge	100	%	39	151,125
Robert Werner	50	%	16	38,750

(1)Based upon employment agreements in place as of June 30, 2008.

All of the named executive officers were awarded lower IPF portions of their total bonus for fiscal year 2008, as compared to the prior fiscal year, due to unsatisfactory operating results in relation to the forecasted Adjusted EBITDA for fiscal year 2008.

Equity Incentive Compensation

The Company has adopted, by a vote of its shareholders, three separate stock-based compensation plans pursuant to which stock options and warrants have been granted to named executive officers and to other employees of the Company.  These stock-based compensation plans are described in Note 17 of the consolidated financial statements included elsewhere in this Annual Report.  Stock-based awards provide our executive officers, employees and other individuals who have provided services to the Company with the right to purchase shares of our common stock at a fixed exercise price typically for a period of up to ten years, subject to continued employment with the Company.  The incentive compensation plans do not allow the Company to establish an exercise price that is below fair market value of our common stock on the award date.  We have granted stock options as incentive stock options in accordance with Section 422 of the Code, as well as non-qualified stock options.  In general, options granted are service-based stock options that have a three year vesting schedule and a ten year term.  The exercise price for options awarded to employees who own greater than 10% of our common stock as of the date of grant is 110% of the fair market value of our common stock and the term of the option is reduced to 5 years instead of 10 years.

Stock options are an important component in our executive compensation program because the Company has benefited from dedicated employees who take ownership pride in its business.  Decisions regarding the amount and timing of stock option awards are made: (1) at the time of the executive’s employment; (2) at the time of annual review, which is undertaken after completion of the fiscal year; or (3) on rare occasions, following a significant event such as an acquisition.

We typically consider grants of equity incentive awards to our named executive officers on an annual basis.  The date of grant and the fair market value of the awards are established by the Compensation Committee.  The fair

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value of the options awarded are equivalent to the fair value of our stock, which may be determined by: (1) an external valuation from a third party, which generally is solicited for June 30 of each fiscal year; (2) an internal valuation based on the valuation process used for the third party valuation, which generally is performed by us at September 30, December 31 and March 31 of each fiscal year; or (3) arm’s-length transactions during the fiscal quarter preceding the grant.

The Board of Directors has delegated responsibility to the Compensation Committee to approve all policies and programs related to the award of stock options.  The Compensation Committee reviews and approves all stock equity-based compensation plans.  The CEO makes recommendations to the Compensation Committee regarding the award of stock options to all named executive officers, which are based on the following considerations:  (1) current value of the officer to the Company; (2) future responsibilities and expectations of the officer during the vesting period for the awards; (3) retention concerns, if any; (4) impression of the officer as a “top performer”; and (5) comparisons with peers within the Company.  Grants are generally approved by the Compensation Committee based on the recommendations, after giving additional consideration for its members’ knowledge of market practice, actual performance of the Company for the current fiscal year and expectations of future performance of the Company.  We do not make decisions regarding equity awards based on the gains or losses from prior equity awards. In addition, we do not have any formal security ownership requirements.  Generally, stock awards granted to the named executive officers vest over a three-year period with the first vesting period ending on the first anniversary of the date of grant.

During the fiscal year ended June 30, 2008, we did not grant any stock option awards to named executive officers.  The CEO and the Compensation Committee are currently considering whether any stock compensation awards will be recommended for the named executive officers, pending final review of operating and financial results for fiscal year 2008 and a review of compensation awards for industry peers.

In March 2008, the Compensation Committee approved the issuance of 9,500 fully vested shares of common stock to Mr. Mayer.  Total compensation expense related to issuance of these shares was approximately $0.8 million, which included the fair value of the common stock issued ($0.5 million) and additional compensation in the form of a tax gross-up to offset the taxable nature of the shares to Mr. Mayer ($0.3 million).  Also in March 2008, the Compensation Committee approved the issuance of 9,500 fully vested shares of common stock to Ms. Artman-Hodge.  Total compensation expense related to issuance of these shares was approximately $0.9 million, which included the fair value of the common stock issued ($0.5 million) and additional compensation in the form of a tax gross-up to offset the taxable nature of the shares to Ms. Artman-Hodge ($0.4 million).  These shares were issued to Mr. Mayer and Ms. Artman-Hodge to replace fully vested options that had unintentionally expired.

Because our common stock is not publicly traded, we obtain an independent valuation of its fair value at June 30 of each fiscal year and we calculate its fair value at September 30, December 31 and March 31 of each fiscal year using an internally developed model that approximates the independent model.

Other Compensation

All of our executive officers are eligible for benefits offered to employees generally, including life, health, disability and dental insurance and participation in our 401(k) plan.  We intend to continue to maintain our current benefits for our executive officers, as well as for all of our full-time employees.  The Compensation Committee may, at its sole discretion revise, amend or add to the named executive officer’s benefits and perquisites if deemed advisable. We do not believe it is necessary for the attraction or retention of management talent to provide the officers with a substantial amount of compensation in the form of perquisites.  During fiscal year 2008, in addition to matching the 401(k) contributions of all of the named executive officers, we made reimbursement payments to Mr. Mayer for legal fees in connection with preparation of his employment agreement and reimbursement payments to Messrs. Mayer and Murray for club fees.

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Accounting and Tax Considerations

Effective July 1, 2006, we adopted, on a prospective basis, the fair market value provisions of SFAS No. 123R.  Under SFAS No. 123R, the estimated fair value of options granted, net of forfeitures expected to occur, is amortized as compensation expense over the vesting period of the options based on the accelerated attribution method as specified in FASB Interpretation No. 28.  For additional information, see Notes 2 and 17 of our audited consolidated financial statements included elsewhere in this Annual Report.

We have granted stock options as incentive stock options in accordance with Section 422 of the Code subject to the volume limitations contained in the Code.  Generally, the exercise of an incentive stock option does not trigger any recognition of income or gain to the holder.  If the stock is held until at least one year after the date of exercise (or two years from the date the option is granted, whichever is later), all of the gain on the sale of the stock will be capital gain when recognized for income tax purposes, rather than ordinary income to the recipient. Consequently, we do not receive a tax deduction.  For stock options that do not qualify as incentive stock options, we are entitled to a tax deduction in the year in which the stock options are exercised equal to the spread between the exercise price and the fair market value of the stock for which the stock option was exercised. The holders of the non-qualified stock options are generally taxed on this same amount in the year of exercise.

Post Fiscal Year 2008 Actions

Fiscal Year 2009 Salary Actions

The Compensation Committee has approved the following base salaries for the named executive officers for the fiscal year ended June 30, 2009:

Name	Fiscal Year 2009
Jeffrey Mayer	$	594,825
Chaitu Parikh	421,785
Steven Murray	486,675
Robi Artman-Hodge	390,000
Robert Werner	250,000

For fiscal year 2009, the Compensation Committee approved a 5% cost of living increase for Messrs. Mayer, Parikh and Murray to keep their salaries within targeted market levels.  Ms. Artman-Hodge and Mr. Werner did not receive a base salary increase for fiscal year 2008 because their base salary already exceeded targeted market levels for their respective positions with the Company.

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Summary Compensation Table

Compensation for the named executive officers is summarized in the following table.

Name and Principal Position	Year	Salary		Stock Awards (1)		Bonus (2)		Option Awards (3)		Non-equity Incentive Plan (4)		All Other (5)		Total
Jeffrey Mayer	2008	$	566,183	$	475,950	$	—	$	92,019	$	236,115	$	366,564	$	1,736,831
President and Chief Executive Officer	2007	547,745		—		250,000		87,260		324,500		13,702		1,223,207
Chaitu Parikh	2008	401,475		—		—		202,261		202,859		16,189		822,784
Vice President and Chief Financial Officer	2007	389,098		—		200,000		191,799		253,100		16,500		1,050,497
Steven Murray	2008	463,180		—		—		777,925		222,406		37,539		1,478,415
Chief Operating Officer	2007	389,423		—		150,000		737,688		229,800		43,128		1,550,039
Carole R. Artman-Hodge	2008	390,000		475,950		—		202,261		180,925		390,086		1,639,222
Executive Vice President	2007	389,662		—		150,000		191,799		159,600		20,249		911,310
Robert Werner	2008	250,000		—		—		230,103		47,050		—		527,153
Vice President, Supply	2007	216,346		—		—		317,388		44,700		19,250		597,684

(1)In March 2008, the Compensation Committee approved the issuance of 9,500 shares to both Mr. Mayer and Ms. Artman-Hodge.  The fair value of these awards was $475,950 for both Mr. Mayer and Ms. Artman-Hodge.

(2)For Messrs. Mayer and Parikh and Ms. Artman-Hodge, the 2007 amount represents a cash bonus paid in recognition of their work in the SESCo Acquisition.  For Mr. Murray, the 2007 amount represents a sign-on bonus paid in accordance with his employment agreement.

(3)This column reflects the compensation cost of stock options over the requisite service period as defined by SFAS No. 123R and reflects expense recognized in earnings for financial statement reporting purposes for the fiscal years ended June 30, 2008 and 2007.

(4)Amounts include performance bonuses for fiscal year 2008, as accrued at June 30, 2008 (Mr. Mayer: $175,615; Mr. Parikh: $155,659; Mr. Murray: $179,606; Ms. Artman-Hodge: $151,125; Mr. Werner: $38,750), as well as adjustments to performance bonuses for fiscal year 2007, as originally accrued at June 30, 2007 (Mr. Mayer: $60,500; Mr. Parikh: $47,200; Mr. Murray: $42,800; Ms. Artman-Hodge: $29,800; Mr. Werner: $8,300).  Amounts reflected are exclusively cash awards.

(5)This column reflects: (1) contributions to the Company-sponsored employee savings plan under Section 401(k) of the Code (Mr. Mayer: $10,894; Mr. Parikh: $16,189; Mr. Murray: $14,904; Ms. Artman-Hodge: $20,750; and Mr. Werner: $19,730); (2) reimbursement for legal fees in connection with the preparation of employment agreements (Mr. Mayer: $10,621);  and (3) club fees (Mr. Mayer:  $12,000; Mr. Murray: $22,635); and (4) additional compensation in the form of a tax gross-up paid by the Company on behalf of named executive officers to offset the tax consequences of awards of common stock granted during fiscal 2008 (Mr. Mayer; $333,049; Ms. Artman-Hodge: $369,336).

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2008 Grants of Plan-Based Awards

The Company did not grant any share-based compensation awards during the fiscal year ended June 30, 2008.  Information with respect to grants of non-equity plan-based awards granted to the named executive officers for fiscal year 2008 is presented in the following table.

	Estimated Future Payouts Under Incentive Plan Awards (1)						All Other Stock Awards: Number of Shares	Grant Date Fair Value of Stock
Name	Threshold		Target		Maximum		of Stock	Awards (2)
Jeffrey Mayer	$	0	$	566,500	$	679,800	9,500	$	475,950
Chaitu Parikh	0		401,700		482,040		—	—
Steven Murray	0		463,500		463,500		—	—
Carole R. Artman-Hodge	0		390,000		390,000		9,500	$	475,950
Robert Werner	0		125,000		250,000		—	—

(1)Amounts reflect the range of potential short-term incentive payouts under the Company’s cash incentive bonus program.  For fiscal year 2008 performance, the actual payout, as well as the business objectives and percentage of target achieved, are disclosed above under “Annual Cash Incentive Compensation”.

(2)Represents the fair market value of the Company’s common stock on the award grant date.

Outstanding Equity Awards at June 30, 2008

Outstanding equity awards for the named executive officers are summarized in the following table.

	Option Awards
Name	Number of Securities Underlying Unexercised Options Exercisable	Number of Securities Underlying Unexercised Options Unexercisable	Option Exercise Price		Option Expiration Date
Jeffrey Mayer	16,550	—	$	8.80	1/21/2009
Jeffrey Mayer	48,000	—	23.65		10/19/2009
Jeffrey Mayer	21,000	—	30.25		6/26/2010
Jeffrey Mayer	13,000	26,000	46.83		11/13/2011
Chaitu Parikh	7,500	—	8.00		3/19/2013
Chaitu Parikh	17,700	—	8.00		1/21/2014
Chaitu Parikh	36,000	—	21.50		10/19/2014
Chaitu Parikh	18,000	—	27.50		6/26/2015
Chaitu Parikh	13,000	26,000	42.57		11/13/2016
Steven Murray	50,000	100,000	42.57		11/13/2016
Carole R. Artman-Hodge	16,550	—	8.00		1/21/2014
Carole R. Artman-Hodge	48,000	—	21.50		10/19/2014
Carole R. Artman-Hodge	21,000	—	27.50		6/26/2015
Carole R. Artman-Hodge	13,000	26,000	42.57		11/13/2016
Robert Werner	16,667	33,333	42.57		11/13/2016

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Option Exercises

Options or warrants exercised by named executive officers during the fiscal year ended June 30, 2008 are summarized in the following table.

Name	Number of Shares Acquired on Exercise	Value Realized on Exercise
Jeffrey Mayer	18,700	$	772,310
Chaitu Parikh	20,000	892,200
Carole R. Artman-Hodge	18,700	772,310

Pension Benefits

The Company does not provide any post-retirement pension benefits to any of its named executive officers.

Nonqualified Deferred Compensation Plans

The Company does not provide any nonqualified deferred compensation programs for any of its named executive officers.

Agreements with Named Executive Officers

Jeffrey Mayer Employment Agreement

On February 13, 2008, the Company entered into a new employment agreement with Mr. Mayer (the “Mayer Agreement”).  The Mayer Agreement replaces a previous employment agreement dated April 1, 1999.  The material differences in the Mayer Agreement include the following:  (i) reducing both the initial and automatic renewal terms of the agreement; (ii) providing increased severance upon a termination without business reasons (and including the concept of a constructive termination); (iii) providing for severance upon a change in control in connection with a qualifying termination; and (iv) including a Code Section 280G provision, which provides for either a reduction of payments or a tax gross-up.  In each case, the Company included these revised terms to reflect market practices, and Mr. Mayer’s increased responsibilities and authority.

The initial term of the Mayer Agreement is four years and is automatically renewed for successive one-year terms unless either party gives the other 180 days’ notice that the Mayer Agreement will not be extended or if the Mayer Agreement is otherwise terminated.  Pursuant to the Mayer Agreement, Mr. Mayer’s office will be located in the Company’s headquarters in Stamford, Connecticut, and he will report to the Company’s Board of Directors.  In addition to his position as CEO, the Company agrees to use its best efforts to ensure that Mr. Mayer will continue to serve as a member of the Board of Directors.

Pursuant to the Mayer Agreement, Mr. Mayer will receive an annual base salary of $566,500, which may be increased from time to time by the Company, at its discretion.  In addition, Mr. Mayer’s annual target bonus shall be equal to 100% of his then current base salary, 75% of which is payable based on achievement of Company and/or individual objectives specified by the Compensation Committee and 25% of which may be awarded solely at the discretion of the Compensation Committee.  In addition, the Compensation Committee may, in its sole discretion, award Mr. Mayer an additional bonus of up to 20% of his base salary then in effect for extraordinary performance in connection with a significant business event affecting the Company.

In the event that Mr. Mayer is terminated involuntarily and without “business reasons” (as such term is defined in the Mayer Agreement, which generally includes “cause” events such as felony conviction, fraud or insubordination) or a “constructive termination” (as such term is defined in the Mayer Agreement, such as a material reduction in salary or authority or a relocation) occurs, Mr. Mayer will be entitled to receive (i) his then current base salary, any paid time off and any earned and unpaid target bonus accrued through the date of termination; (ii) a lump sum payment equal to the greater of (a) his then current base salary for a period of twelve months following the date of

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termination, or (b) his then current base salary for the remainder of the then current employment term; and (iii) a lump sum payment equal to (a) 100% of the target bonus for the fiscal year in which the date of termination occurs, (b) 100% of the target bonus for any full fiscal year remaining during the then applicable employment term, and (c) a pro rata portion of 100% of the target bonus being paid for the final fiscal year that begins during the then applicable employment term.  In addition, all of Mr. Mayer’s unvested stock options, restricted stock, and other equity awards shall become fully vested and all stock options that are vested and outstanding (but unexercised) on the date of termination will be cancelled and the Company will pay to Mr. Mayer, with respect to each option, an amount equal to the excess of the fair market value per share of the shares underlying such option over the exercise price of such option multiplied by the number of shares underlying such option.  In addition, Mr. Mayer’s benefits will continue for the duration of the then current employment term.

If there is a change in control (as such term is defined in the Mayer Agreement) and either a constructive termination occurs or the Company terminates Mr. Mayer’s employment without business reasons prior to the expiration of the then current employment term, Mr. Mayer will be entitled to receive (i) his then current base salary, any paid time off, and any earned and unpaid target bonus accrued through the date of termination; (ii) a lump sum payment equal to the greater of (a) two times his then current base salary or (b) his then current base salary for the remainder of the then current employment term; (iii) a lump sum payment equal to the greater of (a) 200% of the target bonus for the fiscal year in which the termination occurs, or (b) 100% of the target bonus for the fiscal year in which the termination occurs times the number of years for the remainder of the then current employment term.  In addition, all of Mr. Mayer’s unvested stock options, restricted stock, and other equity awards shall become fully vested.

If Mr. Mayer is terminated as a result of death or disability (as such term is defined in the Mayer Agreement), he or his representative, as the case may be, is entitled to receive (i) any accrued and unpaid salary; (ii) any accrued and unpaid target bonus for the prior fiscal year; (iii) a pro rata portion of any target bonus that he would have otherwise earned during the fiscal year in which the termination occurs; and (iv) any accrued and unpaid time off.  Mr. Mayer’s outstanding stock options, restricted stock, and other equity arrangements shall expire in accordance with the terms of the applicable award agreements.

If Mr. Mayer voluntarily terminates his employment (other than in the case of a constructive termination), or he is terminated involuntarily for business reasons, he will be entitled to receive (i) all accrued and unpaid salary, all accrued and unpaid target bonus for the prior fiscal year, and a pro rata portion of any target bonus that he would have otherwise earned during the fiscal year in which such termination occurs and (ii) all accrued but unpaid time off and other benefits due to him through his termination date under any Company-provided or paid plans, policies, and arrangements.  Mr. Mayer’s stock options, restricted stock, and other equity arrangements will cease vesting immediately and such awards will expire in accordance with the terms of the applicable award agreements.

If Mr. Mayer’s employment is terminated for any reason, the Company has the initial right to purchase all (but not less than all) of the common stock of the Company held by Mr. Mayer by making a written offer within 60 days of termination.  If Mr. Mayer is involuntarily terminated for any reason (including a constructive termination) other than for business reasons, but the Company does not offer to purchase his shares of common stock of the Company within 60 days of termination, Mr. Mayer has the right to cause the Company to repurchase all (but not less than all) of his common stock of the Company.  The foregoing rights terminate upon an initial public offering of the Company’s common stock.

The Mayer Agreement provides that in the event that Mr. Mayer becomes entitled to payments or benefits that would constitute an “excess parachute payment” within the meaning of Section 280G of the Code, the payment and/or benefits will be reduced to the extent that such payments will not be subject to the excise tax or any interest or penalties imposed by Section 4999 of the Code, referred to herein as the 280G Reduction. The 280G Reduction will only take place if Mr. Mayer’s “net after tax benefit” (as defined in the Mayer Agreement) exceeds the net after tax benefit he would realize if the 280G Reduction were not made. To the extent, the 280G Reduction is unavailable because Mr. Mayer’s net after tax benefit would be greater if the 280G Reduction were not made, the Company will pay Mr. Mayer a gross up payment in an amount such that after the payment by Mr. Mayer of all taxes (including any income taxes, interest, penalties or any excise taxes), Mr. Mayer would retain an amount of the gross-up payment equal to seventy-five (75%) of any excise tax imposed upon the payments received by Mr. Mayer.

The Mayer Agreement also contains restrictive covenants, which apply for the remainder of the then-current agreement term.  Pursuant to the restrictive covenants, Mr. Mayer is generally prohibited from (1) owning or

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providing services for any business competing with that of the Company for the remainder of the agreement term; (2) inducing employees to leave the employ of the Company or hiring them (unless the employee contacts Mr. Mayer on an unsolicited basis); (3) soliciting any customer, supplier, licensee or other business relation of the Company or (4) disparaging the Company, its executive officers, or its directors.  In the event that Mr. Mayer violates the provisions of the restrictive covenants, he will not be entitled to any severance benefits upon a termination without business reasons or upon a constructive termination.  Additionally, upon any such violation, all of Mr. Mayer’s unexercised options, whether vested or unvested, shall be cancelled.

Chaitu Parikh Employment Agreement

On February 13, 2008, the Company entered into a new employment agreement with Mr. Parikh, as the Chief Financial Officer and Senior Vice President of the Company (the “Parikh Agreement”).  The Parikh Agreement replaces a previous employment agreement dated November 1, 2002.  The material differences in the Parikh Agreement include the following:  (i) providing for a specified term; (ii) providing increased severance upon a termination without business reasons (and including the concept of a constructive termination), or upon a change in control in connection with a qualifying termination; and (iii) including a Code Section 280G provision, which provides for either a reduction of payments or a tax gross-up.  In each case, the Company included these revised terms to reflect market practices, and Mr. Parikh’s increased responsibilities and authority.

The initial term of the Parikh Agreement is three years and is automatically renewed for successive one-year terms unless either party gives the other 180 days’ notice that the Parikh Agreement will not be extended or if the Parikh Agreement is otherwise terminated.  Pursuant to the Parikh Agreement, Mr. Parikh’s office will be located in the Company’s headquarters in Stamford, Connecticut, and he will report to the Company’s Board of Directors.

Pursuant to the Parikh Agreement, Mr. Parikh will receive an annual base salary of $401,700, which may be increased from time to time by the Company, at its discretion.  In addition, Mr. Parikh’s annual target bonus shall be equal to 100% of his then current base salary, 75% of which is payable based on achievement of Company and/or individual objectives specified by the Compensation Committee and 25% of which may be awarded solely at the discretion of the Compensation Committee.  In addition, the Compensation Committee may, in its sole discretion, award Mr. Parikh an additional bonus of up to 20% of his base salary then in effect for extraordinary performance in connection with a significant business event affecting the Company.

In the event that Mr. Parikh is terminated involuntarily and without “business reasons” (as such term is defined in the Parikh Agreement, which generally includes “cause” events such as felony conviction, fraud or insubordination) or a “constructively termination” (as such term is defined in the Parikh Agreement, such as a material reduction in salary or authority or a relocation) occurs, Mr. Parikh will be entitled to receive (i) his then current base salary, any unpaid time off and any earned and unpaid target bonus accrued through the date of termination; (ii) a lump sum payment equal to the greater of (a) his then current base salary for a period of twelve months following the date of termination, or (b) his then current base salary for the remainder of the then current employment term; and (iii) a lump sum payment equal to (a) 100% of the target bonus for the fiscal year in which the date of termination occurs, (b) 100% of the target bonus for any full fiscal year remaining during the then applicable employment term, and (c) a pro rata portion of 100% of the target bonus being paid for the final fiscal year that begins during the then applicable employment term.  In addition, all of Mr. Parikh’s unvested stock options, restricted stock, and other equity awards shall become fully vested and all stock options that are vested and outstanding (but unexercised) on the date of termination will be cancelled and the Company will pay to Mr. Parikh, with respect to each option, an amount equal to the excess of the fair market value per share of the shares underlying such option over the exercise price of such option multiplied by the number of shares underlying such option.  In addition, Mr. Parikh’s benefits will continue for the duration of the then current employment term.

If there is a change in control (as such term is defined in the employment agreement) and either a constructive termination occurs or the Company terminates Mr. Parikh’s employment without business reasons prior to the expiration of the then current employment term, he will be entitled to receive (i) his then current base salary, any paid time off, and any earned and unpaid target bonus accrued through the date of termination; (ii) a lump sum payment equal to the greater of (a) two times his then current base salary or (b) his then current base salary for the remainder of the then current employment term; (iii) a lump sum payment equal to the greater of (a) 200% of the target bonus for the fiscal year in which the termination occurs, or (b) 100% of the target bonus for the fiscal year in which the termination occurs times the number of years for the remainder of the then current employment term.  In

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addition, all of Mr. Parikh’s unvested stock options, restricted stock, and other equity awards shall become fully vested.

If Mr. Parikh is terminated as a result of death or disability (as such term is defined in the Parikh Agreement), he or his representative, as the case may be, will be entitled to receive (i) any accrued and unpaid salary; (ii) any accrued and unpaid target bonus for a prior fiscal year; (iii) a pro rata portion of any target bonus that he would have otherwise earned during the fiscal year in which the termination occurs; and (iv) any accrued and unpaid paid time off.  Mr. Parikh’s outstanding stock options, restricted stock, and other equity arrangements shall expire in accordance with the terms of the applicable award agreements.

If Mr. Parikh voluntarily terminates his employment (other than in the case of a constructive termination), or he is terminated involuntarily for business reasons, he will be entitled to receive (i) all accrued and unpaid salary, all accrued and unpaid target bonus for a prior fiscal year, and a pro rata portion of any target bonus that he would have otherwise earned during the fiscal year in which such termination occurs and (ii) all accrued but unpaid paid time off and other benefits due to him through his termination date under any Company-provided or paid plans, policies, and arrangements.  Mr. Parikh’s stock options, restricted stock, and other equity arrangements will cease vesting immediately and such awards will expire in accordance with the terms of the applicable award agreements.

If Mr. Parikh’s employment is terminated for any reason, the Company has the initial right to purchase all (but not less than all) of the common stock of the Company held by Mr. Parikh by making a written offer within 60 days of termination.  If Mr. Parikh is involuntarily terminated for any reason (including a constructive termination) other than for business reasons, but the Company does not offer to purchase his shares of common stock of the Company within 60 days of termination, Mr. Parikh has the right to cause the Company to repurchase all (but not less than all) of his common stock of the Company.  The foregoing rights terminate upon an initial public offering of the Company’s common stock.

The Parikh Agreement provides that in the event that Mr. Parikh becomes entitled to payments or benefits that would constitute an “excess parachute payment” within the meaning of Section 280G of the Code, the payment and/or benefits will be reduced to the extent that such payments will not be subject to the excise tax or any interest or penalties imposed by Section 4999 of the Code, referred to herein as the 280G Reduction. The 280G Reduction will only take place if Mr. Parikh’s “net after tax benefit” (as defined in the Parikh Agreement) exceeds the net after tax benefit he would realize if the 280G Reduction were not made. To the extent, the 280G Reduction is unavailable because Mr. Parikh’s net after tax benefit would be greater if the 280G Reduction were not made, the Company will pay Mr. Parikh a gross up payment in an amount such that after the payment by Mr. Parikh of all taxes (including any income taxes, interest, penalties or any excise taxes), Mr. Parikh would retain an amount of the gross-up payment equal to seventy-five (75%) of any excise tax imposed upon the payments received by Mr. Parikh.

The Parikh Agreement also contains restrictive covenants, which apply for the remainder of the then-current agreement term.  Pursuant to the restrictive covenants, Mr. Parikh is generally prohibited from (1) owning or providing services for any business competing with that of the Company for the remainder of the agreement term; (2) inducing employees to leave the employ of the Company or hiring them (unless the employee contacts Mr. Parikh on an unsolicited basis); (3) soliciting any customer, supplier, licensee or other business relation of the Company or (4) disparaging the Company, its executive officers, or its directors.  In the event that Mr. Parikh violates the provisions of the restrictive covenants, he will not be entitled to any severance benefits upon a termination without business reasons or upon a constructive termination.  Additionally, upon any such violation, all of Mr. Parikh’s unexercised options, whether vested or unvested, shall be cancelled.

Steven Murray Employment Agreement

We entered into an employment agreement with Mr. Murray dated August 4, 2006 (the “Murray Agreement”), in connection with Mr. Murray’s employment as our COO.  The initial term of the Murray Agreement is three years and is automatically extended for one year at the end of the initial term, unless we or Mr. Murray gives the other party at least 180 days’ advance notice to the contrary. Pursuant to the Murray Agreement, Mr. Murray’s office will be located in the Company’s Houston, Texas offices and he will report to the CEO of the Company. In addition to his position as COO, the Murray Agreement provides that Mr. Murray will be a member of the Board of Directors of the Company.

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The Murray Agreement provides that Mr. Murray will receive an annual base salary of $450,000, which may be increased at the Company’s discretion. The Murray Agreement also provides that Mr. Murray is eligible for an executive bonus, which may be 100% of Mr. Murray’s base salary. The target bonus is based on the following: (1) 75% is based on the performance of the Company or Mr. Murray and (2) 25% is based on the Company’s discretion. Additionally, the Company may award Mr. Murray up to 20% of his base salary in connection with his extraordinary performance with respect to a significant business event affecting the Company; provided that the maximum actual bonus will not exceed 120% of base salary. The Murray Agreement also provides that the Company will grant to Mr. Murray an option to purchase 150,000 shares of common stock which will vest in three equal installments over three years commencing with the first anniversary of the initial term.

In the event Mr. Murray’s employment is terminated prior to an initial public offering of the common stock of the Company, the Company shall have the right to purchase all of the common stock owned by Mr. Murray and Mr. Murray shall have the right to require the Company to purchase all of such stock, both based upon the fair market value of the common stock.

In the event that we terminate Mr. Murray’s employment without a “business reason” (as defined in the Murray Employment Agreement, which generally includes “cause” events such as felony conviction, fraud or insubordination) or a “constructive termination” (as defined in the Murray Agreement, such as a material reduction in salary or authority or a relocation) occurs Mr. Murray will be entitled to: (1) a lump sum payment equal to the greater of (a) base salary for a period of 12 months following the date of termination or (b) base salary for the remainder of the then-current agreement term; (2) a lump sum payment equal to (a) 100% of the target bonus for the fiscal year in which the termination occurs; (b) 100% of the target bonus for any full fiscal year remaining during the initial term of the agreement; and (c) a pro rata portion of 100% of the target bonus for the final fiscal year that begins during the applicable agreement term; (3) Mr. Murray’s unvested stock options, restricted stock and other equity awards shall become fully vested, and all vested but outstanding stock options shall be cancelled in consideration of the Company’s payment to Mr. Murray of an amount equal to (x) the fair market value for the shares underlying the option, (y) over the exercise price of such option, (z) multiplied by the number of shares subject to the option; and (4) any accrued, but unpaid, compensation.

If there is a change of control during the initial term of the Murray Agreement and the Company terminates Mr. Murray’s employment without business reasons prior to the end of the initial term of the agreement (or within a year following a change of control) prior to the end of the initial term of the agreement (or within a year following a change of control) or a constructive termination occurs, Mr. Murray will be entitled to receive the following: (1) a lump sum payment equal to the greater of (a) base salary for a period of two years following the date of termination or (b) base salary for the remainder of the then-current agreement term and (2) a lump sum payment equal to the greater of (a) 200% of the target bonus for the fiscal year in which the termination occurs; (b) 100% of the target bonus for any full fiscal year remaining during the initial term of the agreement times the number of years for the remainder of the then-current agreement term; (3) Mr. Murray’s unvested stock option, restricted stock and other equity awards shall become fully vested and (4) any accrued, but unpaid, compensation.

In the event of termination due to disability, Mr. Murray will be entitled to all earned, but unpaid compensation, payments and benefits in accordance with the disability policy of the Company, the “in the money” value of all vested options, a pro rata portion of any target bonus Mr. Murray would have otherwise earned during the fiscal year in which the disability occurs, and any accrued, but unpaid, compensation.

If Mr. Murray voluntarily terminates his employment or the Company involuntarily terminates his employment for business reasons, all equity awards will expire according to the terms of the award agreement, Mr. Murray will receive any accrued, but unpaid, compensation, and Mr. Murray will receive a pro rata portion of any target bonus that he would have otherwise earned during the fiscal year in which his termination occurs.

If Mr. Murray’s employment terminates due to death, Mr. Murray’s representative will receive payments and benefits in accordance with the then applicable plans, policies, or arrangements, all equity awards will expire according to the terms of the award agreement (provided Mr. Murray will be entitled to the “in the money” value of all vested options), Mr. Murray will receive any accrued, but unpaid, compensation, and Mr. Murray will be entitled to receive a pro rata portion of any target bonus that he would have otherwise earned during the fiscal year in which his termination occurs.

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The Murray Agreement also contains restrictive covenants, which apply for the remainder of the then-current agreement term. Pursuant to the restrictive covenants, Mr. Murray is generally prohibited from (1) owning or providing services for any business competing with that of the Company for the remainder of the agreement term; (2) inducing employees to leave the employ of the Company or hiring them; (3) soliciting any customer, supplier, licensee or other business relation of the Company or (4) disparaging the Company, its executive officers, or its directors.  In the event that Mr. Murray violates the provisions of the restrictive covenants, he will not be entitled to any severance benefits upon a termination without business reasons or upon a constructive termination.  Additionally, upon any such violation, all of Mr. Murray’s unexercised options, whether vested or unvested, shall be cancelled.

Carole R. Artman-Hodge Employment Agreement

We entered into an employment agreement with Ms. Artman-Hodge dated April 1, 1999 (the “Artman-Hodge Agreement”).  The Artman-Hodge Agreement commenced on the date of the closing of the Company’s equity capital transaction in connection with Ms. Artman-Hodge’s employment as our Executive Vice President and Chief Financial Officer.  The initial term of the agreement was five years and is automatically extended for successive five-year terms, unless we or Ms. Artman-Hodge gives the other party at least six months’ advance notice to the contrary.

The Artman-Hodge Agreement provides that Ms. Artman-Hodge’s base salary may be increased from time to time.  In fiscal year 2007, Mr. Artman-Hodge’s base salary was $389,662.  The Artman-Hodge Agreement also provides that Ms. Artman-Hodge is eligible for an annual year-end bonus and to participate in the Company’s incentive stock option plans. Under a provision of the Artman-Hodge Agreement, Ms. Artman-Hodge also acknowledges and agrees that as a founder and owner of a substantial equity interest in the Company that she is subject to the Shareholders Agreement, dated as of May 1, 1999, between the Company and certain shareholders.

In the event that we terminate Ms. Artman-Hodge’s employment relationship without “cause” (as defined in the Artman-Hodge Agreement, which generally means felony conviction, fraud or a material breach of the agreement), Ms. Artman-Hodge will be entitled to a lump sum severance payment of 36 months of her base salary in effect at the time of her termination plus any unvested warrants, options or other securities awarded to her pursuant to the incentive stock option plans by us. Additionally, she will vest in the pro rata portion of any warrants or options that are scheduled to vest on the vesting date next succeeding the effective date of her termination and forfeit the right to receive all remaining unvested warrants or options. In the event that Ms. Artman-Hodge terminates her employment or we terminate her employment with cause, Ms. Artman-Hodge will forfeit her right to receive any unvested options or warrants.

The Artman-Hodge Agreement also contains a non-compete provision, which applies during the term of Ms. Artman-Hodge’s employment and for a period of one year thereafter, whether her termination of employment is with or without cause or whether the termination is initiated by Ms. Artman-Hodge or the Company. Pursuant to the non-compete provision, Ms. Artman-Hodge is prohibited from (1) working with, or providing services to, any person or entity which was a customer of the Company at the date of cessation of her consulting or employment relationship, as the case may be or within the twelve-month period preceding such date, or which was contracted as a client prospect by any representative of the Company within 90 days prior to such date of cessation; or (2) soliciting or inducing any employee of the Company to leave its employ or to hire or attempt to hire any such employee.

For purposes of the Artman-Hodge Agreement, cause means: (i) conviction of, or pleading guilty to, a felony-class crime; (ii) any action taken in bad faith by Ms. Artman-Hodge that has, or is likely to have, in the Company’s reasonable judgment, a material, detrimental effect on the reputation of the Company or its business; (iii) an act of fraud, dishonesty or gross misconduct by Ms. Artman-Hodge; (iv) a material breach by Ms. Artman-Hodge of any provision of the Artman-Hodge Agreement that has not been cured within 30 days after written notice of such breach by the Company.

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Robert Werner Employment Agreement

We entered into an employment agreement with Mr. Werner dated August 14, 2006 (the “Werner Agreement”), in connection with Mr. Werner’s employment as our Vice President of Supply. Under the Werner Agreement, the parties may terminate the Werner Agreement at any time provided either party gives the other at least 60 days’ advance notice of termination.  Mr. Werner’s office will be located in the Company’s Houston, Texas executive offices and he will report to the COO of the Company.

The Werner Agreement provides that Mr. Werner will receive an annual base salary of $250,000, which may be increased at the Company’s discretion.  The Werner Agreement also provides that Mr. Werner is eligible for an executive bonus, which is expected to range from 50 to 100% of Mr. Werner’s base salary.

The agreement also provides that the Company will grant to Mr. Werner an option to purchase 50,000 shares of common stock which will vest in three equal installments over three years commencing with the first anniversary of the date of grant. In the event Mr. Werner’s employment is terminated for any reason, any unvested stock option will terminate. If the Company terminates Mr. Werner’s employment for business reasons (as defined below) all vested stock options will be forfeited. In the event, Mr. Werner’s employment is terminated for any reason that does not constitute a business reason, stock options will expire in accordance with the terms of the award agreement.

Additionally, if Mr. Werner’s employment is terminated for any reason, the Company shall have the right to purchase all of the Company’s common stock owned by Mr. Werner, provided that if the amount payable to Mr. Werner exceeds $200,000, the Company may pay the excess to Mr. Werner in quarterly installments with 5% interest over a period of three years and the Company’s obligation to make such payment shall be suspended during any period that the payment would cause the Company to violate a loan or similar financial covenant.

In the event that the Company terminates Mr. Werner’s employment without a “business reason” (as defined below) or Mr. Werner terminates his employment for any reason that constitutes a constructive termination (as defined below), Mr. Werner will be entitled to a lump sum payment equal to his base salary for the remainder of the employment term. For purposes of severance, Mr. Werner’s employment term will be deemed to be three years. If the Company terminates Mr. Werner’s employment for business reasons or Mr. Werner terminates his employment for any reason that does not constitute a constructive termination, he will be entitled to any accrued and unpaid salary.

In the event that the Company terminates Mr. Werner’s employment without a “business reason” (as defined in the Werner Agreement, which generally includes a felony conviction, fraud or insubordination) or Mr. Werner terminates his employment for any reason that constitutes a “constructive termination” (as defined in the Werner Agreement, such as such as a material reduction in salary or authority or a relocation), Mr. Werner will be entitled to a lump sum payment equal to his base salary for the remainder of the employment term.  For purposes of severance, Mr. Werner’s employment term will be deemed to be three years. If the Company terminates Mr. Werner’s employment for business reasons or Mr. Werner terminates his employment for any reason that does not constitute a constructive termination, he will be entitled to any accrued and unpaid salary.

The Werner Agreement also contains a non-compete provision, which applies for three years commencing upon the effective date of the agreement. Pursuant to the non-compete provision, Mr. Werner is generally prohibited from (1) owning or providing services for any business competing with that of the Company for the remainder of the agreement term; (2) inducing employees to leave the employ of the Company or hiring them; (3) soliciting any customer, supplier, licensee or other business relation of the Company or (5) disparaging the Company, its executive officers, or its directors.  In the event that Mr. Werner violates the provisions of the restrictive covenants, he will not be entitled to any severance benefits upon a termination without business reasons or upon a constructive termination.  Additionally, upon any such violation, all of Mr. Werner’s unexercised options, whether vested or unvested, shall be cancelled.

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Post-Employment Payments

The following table summarizes the payments that the Company would have been required to make to the named executive officers as of June 30, 2008 as a result of their termination, retirement, disability or death or a change in control of the Company as of that date.  The specific circumstances identified in the table that would trigger such payments are described in the employment agreement for each executive.

	Termination Event
	Involuntary Without Cause or For Constructive Termination		Involuntary With Cause or Without Constructive Termination		Change in Control		Disability		Death
Jeffrey Mayer:
Cash severance payment	$	4,836,336	$	186,509	$	4,269,836	$	186,509	$	186,509
Acceleration of stock options	725,694		—		725,694		725,694		725,694
Health and life insurance	35,706		—		—		—		—
Continuation of perquisites	36,000		—		—		—		—
Value of tax gross-up payments	—		—		2,151,010		—		—
Total termination benefits	$	5,633,736	$	186,509	$	7,146,540	$	912,203	$	912,203
Chaitu Parikh:
Cash severance payment	2,660,224		166,474		2,258,524		166,474		166,474
Acceleration of stock options	975,096		—		975,096		975,096		975,096
Health and life insurance	24,524		—		—		—		—
Value of tax gross-up payments	—		—		1,407,406		—		—
Total termination benefits	$	3,659,844	$	166,474	$	4,641,026	$	1,141,570	$	1,141,570
Steven Murray:
Cash severance payment	$	1,426,923	$	194,759	$	1,426,923	$	194,759	$	194,759
Total termination benefits	$	1,426,923	$	194,759	$	1,426,923	$	194,759	$	194,759
Carole Artman-Hodge:
Cash severance payment	$	1,183,500	$	13,500	$	13,500	$	13,500	$	13,500
Total termination benefits	$	1,183,500	$	13,500	$	13,500	$	13,500	$	13,500
Robert Werner:
Cash severance payment	$	284,187	$	3,365	$	3,365	$	3,365	$	3,365
Total Termination benefits	$	284,187	$	3,365	$	3,365	$	3,365	$	3,365

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Director Compensation

For the fiscal year ended June 30, 2008, we did not pay any retainer, committee membership or committee chairman fees to any of our directors as compensation for their membership on our Board of Directors.  In addition, we do not provide any defined benefit or defined contribution plan benefits to any of our directors.  During the fiscal year ended June 30, 2008, we did not grant any stock awards, stock option awards, non-equity incentive compensation or other deferred compensation to any of our directors, nor did we recognize any compensation expense for such awards granted in prior fiscal years.

In October 2008, our Board of Directors approved the following fees payable to Michael Hamilton 2008: (1) $40,000 annually for his membership and participation on the Board of Directors, effective retroactively to April 1, 2008 and (2) $10,000 annually for his role as Chairman of the Audit Committee, effective July 1, 2008.

Director Compensation earned or paid during fiscal year 2008 is summarized in the following table.

	Fees Earned or Paid in Cash (1)
Michael Hamilton	$	10,000

During the fiscal year ended June 30, 2008, Daniel Bergstein provided management consulting services to the Company, for which we recorded $260,000 of expense during the year.  Refer to “Item 13.  Certain Relationships and Related Transactions and Director Independence” for additional information.

Compensation Committee Interlocks and Insider Participation

The following directors served on the Compensation Committee during the fiscal year ended June 30, 2008: Messrs. Daniel Bergstein (Chair), William Landuyt and Stuart Porter.  Messrs. Bergstein, Landuyt and Porter were not, during fiscal year 2008 or previously, officers or employees of Holdings.  The Board of Directors has determined that Messrs. Bergstein and Landuyt were not independent directors based on the definition of independence of the New York Stock Exchange.  For more information, refer to “Item 13. Certain Relationships and Related Transactions, and Director Independence — Independence of Directors.”  During the fiscal year ended June 30, 2008, we had no Compensation Committee “interlocks”, meaning that no executive officer of the Company served as a director or member of the Compensation Committee of another entity of which an executive officer served as a director or a member of the Compensation Committee of the Company.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The following table sets forth, as of August 31, 2008, information with respect to shares of common stock beneficially owned by: (1) each of the named executive officers; (2) each director; (3) all executive officers and directors as a group; and (4) each person known to be the beneficial owner of more than five percent of our outstanding shares of common stock.

The percentages of common stock and Preferred Stock beneficially owned are reported on the basis of SEC regulations governing the determination of beneficial ownership of securities.  Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security.  A person is also deemed to be a beneficial owner of any securities for which that person has a right to acquire beneficial ownership within 60 days.  All persons listed have sole voting and investment power with respect to their shares (subject to community property laws where applicable) unless otherwise indicated.

	Common Stock (1)
Name or Description	Number	Percentage of Class
Executive Officers and Directors:
Jeffrey Mayer (2)	735,361	15.2	%
Chaitu Parikh (3)	112,975	2.3
Steven Murray (4)	50,000	1.0
Carole R. (“Robi”) Artman-Hodge (5)	443,565	9.2
Robert Werner (6)	33,333	0.7
Daniel Bergstein (7)	344,613	7.2
John Stewart (8)	65,641	1.4
William Landuyt (9)	1,274,931	21.4
Stuart Porter (10)	2, 427,151	51.3
Michael J. Hamilton	—	—
All directors and executive officers as a group (12 persons) (11)	5,590,670	86.5
5% Stockholders:
Denham Commodity Partners Fund LP (10) 200 Clarendon Street, 25th Floor, Boston, MA 02116	2,427,151	51.3
Charter Mx LLC (9) 1105 Market Street, Suite 1300, Wilmington, DE 19899	1,274,931	21.4
Greenhill Capital Partners, L.P. and its affiliated funds (12) 300 Park Avenue, 23rd Floor, New York, NY 10022	245,179	4.9
Pequot Enterprises LLC (13) 26 Pequot Trail, Westport, CT 06880	594,000	12.5
JED Communications Associates, Inc. (14) c/o Paul, Hastings, Janofsky & Walker LLP, 75 E. 55th Street, New York, NY 10022	320,313	6.8
Carole R. Artman Hodge 2005 7 Yr. GRAT (15) c/o Carole R. Artman Hodge, 61 Rye Road, Rye, NY 10580	285,514	6.0

(1)	The percentage of beneficial ownership is based on 3,604,788 shares of our common stock outstanding as of August 31, 2008, plus 1,130,163 shares of common stock issued within 60 days subsequent to August 31, 2008.
(2)	Includes: (1) 98,550 shares of our common stock issuable upon the exercise of stock options that are either currently exercisable or are expected to become exercisable during the 60 days subsequent to August 31, 2008; and (2) 594,000 shares of common stock held by Pequot Enterprises LLC, a limited liability company owned 23% by Mr. Mayer and for which Mr. Mayer, as manager, has both voting and disposition power. Does not include 26,000 shares of our common stock issuable upon the exercise of options that are currently not exercisable and will not become exercisable within the 60 days subsequent to August 31, 2008.
(3)	Includes 92,200 shares of our common stock issuable upon the exercise of stock options that are either currently exercisable or expected to become exercisable during the 60 days subsequent to August 31, 2008. Does not include 26,000 shares of our common stock issuable upon the exercise of options that are currently not exercisable and will not become exercisable within the 60 days subsequent to August 31, 2008.
(4)	Includes 50,000 shares of our common stock issuable upon the exercise of stock options that are either currently exercisable or expected to become exercisable during the 60 days subsequent to August 31, 2008. Does not include 100,000 shares of our common stock issuable upon the exercise of options that are currently not exercisable and will not become exercisable within the 60 days subsequent to August 31, 2008.
(5)	Includes: (1) 98,550 shares of our common stock issuable upon the exercise of stock options that are either currently exercisable or expected to become exercisable during the 60 days subsequent to August 31, 2008; and (2)  285,514 shares of our common stock owned by the Carole R. Artman-Hodge 2005 7 Yr. GRAT for which Ms. Artman-Hodge has both voting and disposition power. Does not include 26,000 shares of our common stock issuable upon the exercise of options that are currently not exercisable and will not become exercisable within the 60 days subsequent to August 31, 2008.

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(6)	Includes 16,667 shares of our common stock issuable upon the exercise of stock options that are either currently exercisable or expected to become exercisable during the 60 days subsequent to August 31, 2008. Does not include 33,333 shares of our common stock issuable upon the exercise of options that are currently not exercisable and will not become exercisable within the 60 days subsequent to August 31, 2008.
(7)	Includes: (1) 21,800 shares of our common stock issuable upon the exercise of stock options that are either currently exercisable or are expected to become exercisable during the 60 days subsequent to August 31, 2008; and (2) 320,313 shares of our common stock owned by JED Communications Associates, Inc., a corporation 100% owned by Mr. Bergstein and members of his immediate family.
(8)	Includes: (1) 12,800 shares of our common stock issuable upon the exercise of stock options that are either currently exercisable or are expected to become exercisable during the 60 days subsequent to August 31, 2008; (2) 42,341 shares of our common stock held by the Stewart Family Trust, of which Mr. Stewart is the beneficiary, and for which Mr. Stewart may be deemed to have beneficial ownership; (3) 2,500 shares of our common stock held in an IRA for Mr. Stewart for which he has both voting and disposition power; (4) 3,000 shares of our common stock held by Mr. Stewart’s spouse, for which Mr. Stewart may be deemed to have indirect beneficial ownership; and (5) 2,500 shares of our common stock held in an IRA account belonging to Mr. Stewart’s spouse, for which Mr. Stewart may be deemed to have indirect beneficial ownership. Mr. Stewart disclaims beneficial ownership of the shares held by his spouse and by his spouse’s IRA account except to the extent of his pecuniary interest therein. Does not include 1,000 shares of our common stock issuable upon the exercise of options that are currently not exercisable and will not become exercisable within the 60 days subsequent to August 31, 2008.
(9)	Includes shares of our common stock issuable upon the conversion of 1,217,228 shares of Preferred Stock. Charter Mx LLC is wholly owned by Charterhouse Equity Partners IV, L.P. The general partner of Charterhouse Equity Partners IV, L.P. is CHUSA Equity Investors IV, L.P., whose general partner is Charterhouse Equity IV, LLC, a wholly owned subsidiary of Charterhouse Group, Inc. As a result of the foregoing, all of the shares held by Charter Mx LLC would be deemed to be beneficially owned by Charterhouse Group, Inc. We have been advised by Charterhouse Group, Inc. that all decisions regarding investments by Charterhouse Equity Partners IV, L.P. (the “Fund”) are made by an investment committee whose composition may change. No individual has authority to make any such decisions without the approval of the Fund’s investment committee. William Landuyt is an executive officer of Charterhouse Group, Inc. and a member of the Fund’s investment committee, the members of which, including Mr. Landuyt, each disclaim beneficial ownership of the shares held by Charter Mx LLC except to the extent of his or her pecuniary interest therein.
(10)	Includes 1,130,163 shares of our common stock issued upon the exercise of warrants in September 2008. The shares of our common stock are held by Denham Commodity Partners Fund LP. Mr. Porter is a principal of Denham Capital Management LP and is Chief Investment Officer for Denham Commodity Partners Fund LP.
(11)	Represents beneficial ownership as a group for all directors and executive officers as listed in the table under “Item 10. Directors, Executive Officers and Corporate Governance — Directors and Executive Officers.”
(12)	Includes: (1) 6,848 shares of our common stock held by Greenhill Capital Partners, L.P.; (2) 978 shares of our common stock held by Greenhill Capital Partners (Cayman), L.P.; (3) 1,081 shares of our common stock held by Greenhill Capital Partners (Executives), L.P.; (4) 2,190 shares of our common stock held by Greenhill Capital, L.P.; (5) 144,440 shares of our common stock issuable upon the conversion of 144,440 shares of our Preferred Stock held by Greenhill Capital Partners, L.P.; (6) 20,639 shares of our common stock issuable upon the conversion of 20,639 shares of our Preferred Stock held by Greenhill Capital Partners (Cayman), L.P.; (7) 22,797 shares of our common stock issuable upon the conversion of 22,797 shares of our Preferred Stock held by Greenhill Capital Partners (Executives), L.P.; and (8) 46,206 shares of our common stock issuable upon the conversion of 46,206 shares of our redeemable convertible preferred stock held by Greenhill Capital, L.P. GCP Managing Partner, L.P., the managing general partner of Greenhill Capital Partners, L.P., Greenhill Capital Partners (Cayman), L.P., Greenhill Capital Partners (Executives), L.P. and Greenhill Capital, L.P. (the “Funds”), as well as Greenhill Capital Partners, LLC, which controls the managing general partner, and Greenhill & Co., Inc., the sole member of Greenhill Capital Partners, LLC, may be deemed to beneficially own the shares held by the Funds. We have been advised by the Funds that all decisions regarding investments by the Funds are made by an investment committee whose composition may change. No individual has authority to make any such decisions without the approval of the Funds’ investment committee. The current members of the investment committee are Robert H. Niehaus, Scott L. Bok, Robert F. Greenhill, Simon A. Borrows, Kevin Bousquette and V. Frank Pottow, each of whom disclaims beneficial ownership in the shares held by the Funds except to the extent of his pecuniary interest therein.
(13)	Pequot Enterprises LLC is a limited liability company owned 23% by Jeffrey Mayer and for which Mr. Mayer, as manager, has both voting and disposition power.
(14)	JED Communications Associates, Inc. is a corporation owned 100% by Daniel Bergstein and members of his immediate family and for which Mr. Bergstein has both voting and disposition power.
(15)	The Carole R. Artman-Hodge 2005 7 Yr. GRAT is a grantor retained annuity trust of which Carole R. “Robi” Artman-Hodge is the beneficiary and the trustee and for which Ms. Artman-Hodge has both voting and disposition power.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Our Code of Business Conduct and Ethics, which is posted on our website at www.mxholdings.com, prohibits directors and executive officers from engaging in transactions on behalf of the Company with a family member, or with a company with which they or any family member are a significant owner or associated or employed in a significant role.  Our Audit Committee must review and approve in advance all related party transactions or business or professional relationships.  All instances involving potential related party transactions or business or professional relationships must be reported to the Company’s Associate General Counsel, who is responsible to assess the materiality of the transaction or relationship and elevate the matter to the Audit Committee as appropriate.

Stockholders’ Agreement

We have entered into a Third Amended and Restated Stockholders’ Agreement with holders of our common stock and Preferred Stock. The stockholders’ agreement contains, among other things, the agreement among our stockholders to restrict their ability to transfer our stock as well as rights of first refusal, tag-along rights and drag-along rights. Pursuant to the stockholders’ agreement, certain of our stockholders have, subject to certain exceptions, preemptive rights on future offerings of equity securities by us. In addition, if we issue or sell shares of our common stock below a certain price, we must offer to sell such common stock to certain of our existing stockholders at a similarly low price.

Pursuant to the stockholders’ agreement, the consent of Jeffrey Mayer and the holders of 10% of more of our common stock on a fully diluted basis are required for various transactions including our liquidation, dissolution, merger, sale of all or substantially all of our assets as well as the issuance of our securities in connection with certain acquisitions and joint ventures. The consent of our Board of Directors (including the consent of the director appointed by the holders of our outstanding Preferred Stock) is required for certain actions, including our incurrence of debt in excess of $2.0 million.

Denham Credit Facility

Denham is a significant stockholder of the Company.  Denham has extended a $12.0 million line of credit to the Company, which bears interest at 9% per annum.  The termination date of the Denham Credit Facility is May 19, 2010, at which time any outstanding principal balance becomes due.  The Company had $0 and $11.0 million of borrowings outstanding under the Denham Credit Facility at June 30, 2008 and 2007, respectively.  In December 2007, the agreement governing the Denham Credit Facility was amended to allow the Company to draw principal until November 14, 2008.  In January 2008, the Company repaid the entire $11.0 million principal balance outstanding under the Denham Credit Facility.  Interest expense related to the Denham Credit Facility was $0.5 million for the fiscal year ended June 30, 2008.  Stuart Porter, a principal of Denham Capital Management LP and Chief Investment Officer for the Denham Commodity Partners Fund, is a director of Holdings.

We believe that the terms of the Denham Credit Facility are comparable to those we would have received in a similar transaction with an unrelated third party.

Legal Services

Daniel Bergstein, a director of Holdings and significant stockholder of the Company, is a senior partner of Paul, Hastings, Janofsky & Walker LLP a law firm that provides legal services to the Company.  During the fiscal year ended June 30, 2008,  Paul Hastings provided the Company with legal services totaling $0.6 million.  The Company expects that Paul Hastings will continue to provide legal services to the Company in future periods.

We believe that the legal services provided to us by Paul Hastings were on terms that were comparable to those that Paul Hastings provides to their other clients.

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Financial Advisory Services

In May 2007, the Company entered into a financial advisory services agreement with Greenhill & Co., LLC, an affiliate of GCP, pursuant to which the Company pays Greenhill & Co., LLC quarterly retainer fees that total $0.3 million annually, and may incur other charges based on the occurrence of a transaction, as defined in such agreement.  The Company paid approximately $0.3 million to Greenhill & Co., LLC during the fiscal year ended June 30, 2008 related to this agreement.

We believe that these financial advisory services were provided on terms comparable to those we would have received in a similar transaction with an unrelated third party.

Management Fees

Effective for the three months ended September 30, 2007, the Company agreed to pay Denham, Daniel Bergstein and Charter Mx LLC, another significant stockholder of the Company, an aggregate annual fee of $0.9 million, payable in equal quarterly amounts, for management consulting services provided to the Company.  Stuart Porter, a principal of Denham Capital Management LP and Chief Investment Officer for Denham Commodity Partners Fund, is a director of Holdings.  Daniel Bergstein is a director of Holdings and a significant stockholder of the Company.  William Landuyt, a Senior Partner of Charterhouse Group, Inc., an affiliate of Charter Mx LLC, is a director of Holdings.

Options and Warrants Issued to Related Parties

There were no options or warrants to purchase the Company’s common stock granted to or exercised by any related parties during fiscal year 2008.  In September 2008, Denham exercised 1,544,736 warrants to purchase common stock with a weighted average exercise price of $9.79 per share.  The cashless transaction resulted in issuance of 1,130,163 shares of the Company’s common stock.

Independence of Directors

The Company is a closely held corporation and does not have a class of equity securities listed on a national securities exchange.  The Company has adopted the definition of independence of the New York Stock Exchange.  However, because our securities are not listed on a national securities exchange, none of our directors are required to qualify as an independent director.

The Board of Directors has determined that under such standard, John Stewart and Michael J. Hamilton are independent directors.  None of Messrs. Mayer or Murray or Ms. Artman-Hodge is independent because they are currently employed by the Company.  Stuart Porter is not an independent director as a result of his affiliation with Denham, a significant stockholder of the Company. Daniel Bergstein is not an independent director because: (1) he is a partner in the New York office of Paul, Hastings, Janofsky & Walker LLP, a law firm that performs substantial legal services to the Company on a regular basis; and (2) in June 2004, he received a finder’s fee in connection with our issuance of Preferred Stock.  William Landuyt is not an independent director as a result of his affiliation with Charterhouse, a significant stockholder of the Company.

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ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The total fees and expenses for professional services provided by our independent registered public accounting firm, Ernst & Young LLP, for the fiscal years ended June 30, 2008 and 2007 are presented in the table below:

	Year ended June 30,
	2008		2007
	(in thousands)
Audit fees	$	1,596	$	2,321
Tax fees	38		29
Total	$	1,634	$	2,350

Audit Fees consist primarily of: (1) fees billed for the audit of the consolidated financial statements and review of other financial information included in our Annual Report on Form 10-K for fiscal years 2008 and 2007; (2) reviews of our Quarterly Reports on Form 10-Q; (3) review of our compliance with new U.S. GAAP pronouncements, including SEC regulations; and (4) review our accounting and reporting methodology for certain specific transactions.

Tax Fees consist of fees for tax compliance, tax advice and tax planning.

The Audit Committee has the responsibility to consider the compatibility of non-audit services provided by its independent auditors with maintaining the auditors’ independence.  There were no such non-audit services performed by the independent auditors during the fiscal years ended June 30, 2008 or 2007.

Pre-Approval Policy

The services performed by the independent registered public accounting firm during the fiscal year ended June 30, 2008 were pre-approved by the Audit Committee, in accordance with the Audit Committee’s independent auditor pre-approval policy.  This policy describes the permitted audit, audit-related and tax services (collectively, referred to as the disclosure categories) that the independent registered public accounting firm may perform up to a pre-determined dollar limit per project. The policy requires a description of the material services (referred to as the standard services list) expected to be performed by the independent registered public accounting firm in each of the disclosure categories presented to the audit committee for approval.

Any requests for audit, audit-related and tax services not contemplated on the standard services list or exceeding the pre-determined dollar limit per project must be submitted to the Audit Committee for specific pre-approval and cannot commence until such approval has been granted.  Normally, pre-approval is provided on an informal, as-needed basis.  The Audit Committee may delegate pre-approval authority to one of its members, who shall initially be the chairman of the Audit Committee.  The decisions of any Audit Committee member to whom pre-approval authority is delegated must be presented to the full Audit Committee at its next scheduled meeting.

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PART IV

ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

The following documents are filed as part of this Annual Report:

(1)	Financial Statements.  See Index to Financial Statements under “Item 8. Financial Statements and Supplementary Data.”
(2)	Financial Statement Schedules.  Schedules are omitted as the required information is inapplicable or the information is presented in the consolidated financial statements or related notes under “Item 8. Financial Statements and Supplementary Data.”
(3)	Exhibits. The exhibits filed as part of this Annual Report are listed in the exhibit index immediately preceding such exhibits.  Such index is incorporated herein by reference.

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SIGNATURES

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.

	MXENERGY HOLDINGS INC.
Date: October 14, 2008
	By:	/s/ JEFFREY A. MAYER
		Jeffrey A. Mayer
		President and Chief Executive Officer

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.

Signatures	Title	Date
/s/ JEFFREY A. MAYER	Director, President and Chief Executive	October 14, 2008
Jeffrey A. Mayer	Officer (Principal Executive Officer)
/s/ CHAITU PARIKH	Vice President of Finance and Chief
Chaitu Parikh	Financial Officer (Principal Financial	October 14, 2008
	Officer and Principal Accounting Officer)
/s/ STEVEN MURRAY	Director	October 14, 2008
Steven Murray
/s/ CAROLE R. ARTMAN-HODGE	Director	October 14, 2008
Carole R. Artman-Hodge
/s/ DANIEL BERGSTEIN	Director	October 14, 2008
Daniel Bergstein
/s/ MICHAEL J. HAMILTON	Director	October 14, 2008
Michael J. Hamilton
/s/ WILLIAM LANDUYT	Director	October 14, 2008
William Landuyt
/s/ STUART PORTER	Director	October 14, 2008
Stuart Porter
/s/ JOHN STEWART	Director	October 14, 2008
John Stewart

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Index to Exhibits

Exhibit Number	Title
2.1	Asset Purchase Agreement, dated as of May 12, 2006, by and between MXenergy Inc. and Shell Energy Services Company L.L.C. (1)
2.2	First Amendment to Asset Purchase Agreement and Acknowledgement, dated as of July 28, 2006, by and between MXenergy Inc. and Shell Energy Services Company L.L.C. (1)
2.3	Asset Purchase Agreement, dated November 9, 2007 by and between PS Energy Group, Inc. and MXenergy Inc. (2)
2.4	First Amendment to Asset Purchase Agreement and Determination Date Loan Documents, dated as of December 31, 2007, by and between PS Energy Group, Inc. and MXenergy Inc. (5)
2.5	Second Amendment to Asset Purchase Agreement and Determination Date Loan Documents, dated as of January 10, 2008, by and between PS Energy Group, Inc. and MXenergy Inc. (5)
2.6	Third Amendment to Asset Purchase Agreement and Determination Date Loan Documents, dated as of December 31, 2007, by and between PS Energy Group, Inc. and MXenergy Inc. (5)
2.7	Fourth Amendment to Asset Purchase Agreement and Determination Date Loan Documents, dated as of January 14, 2008, by and between PS Energy Group, Inc. and MXenergy Inc. (5)
2.8	Fifth Amendment to Asset Purchase Agreement and Determination Date Loan Documents, dated as of January 15, 2008, by and between PS Energy Group, Inc. and MXenergy Inc. (5)
2.9	Sixth Amendment to Asset Purchase Agreement and Determination Date Loan Documents, dated as of January 22, 2008, by and between PS Energy Group, Inc. and MXenergy Inc. (5)
3.1	Amended and Restated Certificate of Incorporation of MXenergy Holdings Inc. (1)
3.2	Second Amended and Restated Bylaws of MXenergy Holdings Inc. (5)
4.1	Indenture dated as of August 4, 2006 by and among MXenergy Holdings Inc., Law Debenture Trust Company of New York, as trustee, and Deutsche Bank Trust Company Americas, as registrar and paying agent, related to MXenergy Floating Rate Senior Notes due 2011 (1)
4.2	Supplemental Indenture, dated as of August 1, 2007, by and among MXenergy Holdings Inc., Law Debenture Trust Company of New York, as trustee, and Deutsche Bank Trust Company Americas, as registrar and paying agent, related to MXenergy’s Floating Rate Senior Notes due 2011 (3)
4.3	Form of Senior Floating Rate Note due 2011 (included in Exhibit 4.1) (1)
4.4	Registration Rights Agreement, dated as of August 4, 2006, by and among MXenergy Holdings Inc., the guarantors named therein and Deutsche Bank Securities Inc. and Morgan Stanley & Co. Incorporated, as initial purchasers(1)
10.1	First Amended and Restated Credit Agreement, dated as of August 1, 2006, by and among MXenergy Inc. and MXenergy Electric Inc., as borrowers, MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, lenders party thereto and Société Générale, as administrative agent, syndication agent, lead arranger and sole bookrunner (1)
10.2	First Amendment to First Amended and Restated Credit Agreement, dated as of April 6, 2007, by and among MXenergy Inc. and MXenergy Electric Inc., as borrowers, MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, and lenders party thereto (1)
10.3	Second Amendment to First Amended and Restated Credit Agreement, dated as of December 17, 2007, by and among MXenergy Inc. and MXenergy Electric Inc., as borrowers, MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, and lenders party thereto (5)
10.4	Third Amendment to First Amended and Restated Credit Agreement, dated as of May 12, 2008 but effective as of March 1, 2008, by and among MXenergy Inc. and MXenergy Electric Inc., as borrowers, MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, and lenders party thereto (6)
10.5	Second Amended and Restated Credit Agreement, dated as of September 30, 2008, by and among MXenergy Inc. and MXenergy Electric Inc., as borrowers, MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, and lenders party thereto. (8)
10.6	First Amended and Restated Pledge Agreement, dated as of August 1, 2006, by and among MXenergy Inc. and MXenergy Electric Inc., as borrowers, MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, and Société Générale (1)
10.7	First Amended and Restated Security Agreement, dated as of August 1, 2006, by and among MXenergy Inc. and MXenergy Electric Inc., as borrowers, MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, and Société Générale (1)
10.8	Amended and Restated Loan Agreement, dated as of November 14, 2003, by and between Denham Commodity Partners Fund LP (formerly known as Sowood Commodity Partners Fund LP) (as successor to Lathi LLC) and MXenergy Inc. (1)
10.9	Amended and Restated Security Agreement, dated as of November 14, 2003, by and between Denham Commodity Partners Fund LP (formerly known as Sowood Commodity Partners Fund LP) (as successor to Lathi LLC) and MXenergy Inc. (1)
10.10	Amendment No. 1 to Amended and Restated Loan Agreement, dated as of March 22, 2004, by and between Denham Commodity Partners Fund LP (formerly known as Sowood Commodity Partners Fund LP) (as successor to Lathi LLC) and MXenergy Inc. (1)
10.11	Amendment No. 2 to Amended and Restated Loan Agreement and Amendment No. 1 to Amended and Restated Security Agreement, dated as of December 19, 2005, by and between Denham Commodity Partners Fund LP (formerly known as Sowood Commodity Partners Fund LP) (as successor to Lathi LLC) and MXenergy Inc. (1)
10.12	Amendment No. 3 to Amended and Restated Loan Agreement and Amendment No. 2 to Amended and Restated Security Agreement, dated as of August 1, 2006, by and between Denham Commodity Partners Fund LP (formerly known as Sowood Commodity Partners Fund LP) (as successor to Lathi LLC) and MXenergy Inc. (1)
10.13	Amendment No. 4 to Amended and Restated Loan Agreement, dated as of January 9, 2008, by and between Denham Commodity Partners Fund LP and MXenergy Inc. (5)

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10.14	Subordination and Intercreditor Agreement, dated as of December 19, 2005, by and among Société Générale and certain counterparties, Denham Commodity Partners Fund LP (formerly known as Sowood Commodity Partners Fund LP), MXenergy Holdings Inc., MXenergy Inc., MXenergy Electric Inc. and certain of their respective subsidiaries and Virginia Power Energy Marketing, Inc. (1)
10.15	Amendment No. 1 to Subordination and Intercreditor Agreement, dated as of August 1, 2006, by and among Société Générale and certain counterparties, Denham Commodity Partners Fund LP (formerly known as Sowood Commodity Partners Fund LP), MXenergy Holdings Inc., MXenergy Inc. and certain of their respective subsidiaries (1)
10.16	Master Transaction Agreement, dated as of August 1, 2006, by and among MXenergy Inc., MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, and Société Générale (1)
10.17	First Amendment to Master Transaction Agreement, dated as of April 6, 2007, by and among MXenergy Inc., MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, and Société Générale (1)
10.18	Second Amendment to Master Transaction Agreement, dated as of December 17, 2007, by and among MXenergy Inc., MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, and Société Générale (5)
10.19	Third Amendment to Master Transaction Agreement, dated as of May 12, 2008, by and among MXenergy, Inc. MXenergy Holdings, Inc, and certain subsidiaries thereof, as guarantors, and Société Générale (6)
10.20	Fourth Amendment to Master Transaction Agreement, dated as of July 31, 2008, by and among MXenergy, Inc. MXenergy Holdings, Inc, and certain subsidiaries thereof, as guarantors, and Société Générale (7)
10.21	Fifth Amendment to Master Transaction Agreement, dated as of September 30, 2008, by and among MXenergy, Inc. MXenergy Holdings, Inc, and certain subsidiaries thereof, as guarantors, and Société Générale *
10.22	Third Amended and Restated Stockholders’ Agreement, dated as of June 25, 2004, by and among MXenergy Inc., Charter Mx LLC, Denham Commodity Partners Fund LP (formerly known as Sowood Commodity Partners Fund LP) (as successor to Lathi LLC), Jeffrey A. Mayer, Carole R. Artman-Hodge, Daniel P. Burke and certain other investors party thereto (1)
10.23	First Amendment to Third Amended and Restated Stockholders’ Agreement, dated as of June 9, 2008, by and among MXenergy Inc., Charter Mx LLC, Denham Commodity Partners Fund LP (formerly known as Sowood Commodity Partners Fund LP) (as successor to Lathi LLC), and stockholders holding a majority of the outstanding shares of Voting Stock as of the effective date *
10.24	Registration Rights Agreement dated as of June 25, 2004 by and among MXenergy Inc., Denham Commodity Partners Fund LP (formerly known as Sowood Commodity Partners Fund LP) (as successor to Lathi LLC), Charter Mx LLC, Greenhill Capital Partners, L.P., Greenhill Capital Partners (Cayman), L.P., Greenhill Capital Partners (Executives), L.P., Greenhill Capital, L.P., Jeffrey A. Mayer, Carole R. Artman-Hodge and Daniel P. Burke, Sr. (1)
10.25	Transition Services Agreement, dated as of August 1, 2006, by and between MXenergy Inc. and Shell Energy Services Company L.L.C. (1)
10.26	Employment Agreement, dated as of April 1, 1999, by and between MXenergy Inc. and Jeffrey Mayer (1)
10.27	Employment Agreement, dated as of February 13, 2008, by and between MXenergy Inc. and Jeffrey Mayer (5)
10.28	Employment Agreement, dated as of August 4, 2006, by and between MXenergy Inc. and Steven Murray (1)
10.29	Employment Agreement, dated as of April 1, 1999, by and between MXenergy Inc. and Carole R. (“Robi”) Artman- Hodge (1)
10.30	Employment Agreement, dated as of November 11, 2002, by and between MXenergy Inc. and Chaitu Parikh (1)
10.31	Employment Agreement, dated as of February 13, 2008, by and between MXenergy Inc. and Chaitu Parikh (5)
10.32	Employment Agreement, dated as of May 1, 2000, by and between MXenergy Inc. and Emmett Capanna (1)
10.33	Employment Agreement, dated as of December 24, 2004, by and between MXenergy Inc. and Thomas Hartmann (1)
10.34	Employment Agreement, dated as of June 13, 2007, by and between MXenergy Inc. and Gina Goldberg (4)
10.35	Employment Agreement, dated as of August 14, 2006, by and between MXenergy Inc. and Robert Werner (4)
10.36	2001 Stock Option Plan, as amended (1)
10.37	2003 Stock Option Plan, as amended (1)
10.38	2006 Equity Incentive Compensation Plan (1)
10.39	Form of Award Agreement under 2001 Stock Option Plan (1)
10.40	Form of Award Agreement under 2003 Stock Option Plan (1)
10.41	Form of Stock Option Award Agreement under 2006 Equity Incentive Compensation Plan (1)
10.42	Financial Advisory Agreement, dated as of May 1, 2007, by and between MXenergy Inc. and Greenhill & Co., LLC (1)
21	Subsidiaries of MXenergy Holdings Inc. *
31.1	Certification as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 *
31.2	Certification as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 *
32	Certification required by 18 United States Code Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 *†

*	Filed herewith.
†	Pursuant to Securities and Exchange Commission Release No. 33-8238, this certification will be treated as “accompanying” this Annual Report on Form 10-K and not “filed” as part of such report for purposes of Section 18 of the Securities Exchange Act of 1934, or otherwise subject to the liability of Section 18 of the Securities Exchange Act of 1934 and this certification will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that the registrant specifically incorporates it by reference.
(1)	Incorporated by reference to the Company’s Registration Statement on Form S-4 (File No. 333-138425) declared effective on April 30, 2007.
(2)	Incorporated by reference to the Company’s Current Report on Form 8-K filed on November 14, 2007.
(3)	Incorporated by reference to the Company’s Current Report on Form 8-K filed on August 7, 2007.
(4)	Incorporated by reference to the Company’s Annual Report on Form 10-K for the fiscal year ended June 30, 2007.
(5)	Incorporated by reference to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended December 31, 2007.
(6)	Incorporated by reference to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2008.

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(7)	Incorporated by reference to the Company’s Current Report on Form 8-K filed on August 1, 2008.
(8)	Incorporated by reference to the Company’s Current Report on Form 8-K filed on October 2, 2008.

137

EX-10.21

Exhibit 10.21

EXECUTION COPY

FIFTH AMENDMENT TO
MASTER TRANSACTION AGREEMENT

This Fifth Amendment to Master Transaction Agreement (this “Amendment”), dated as of September 30, 2008 (the “Amendment Date”), by and among MXenergy Inc., a Delaware corporation (the “Counterparty”), MXenergy Holdings Inc. and certain Subsidiaries thereof, as guarantors (collectively, the “Guarantors”), and Société Générale, as hedge provider (the “Hedge Provider”).

PRELIMINARY STATEMENTS

A.Reference is made to the Master Transaction Agreement, dated as of August 1, 2006 (as amended by (i) the First Amendment to Master Transaction Agreement dated as of April 6, 2007, (ii) the Second Amendment to Master Transaction Agreement dated as of December 17, 2007, (iii) the Third Amendment to Master Transaction Agreement dated as of May 12, 2008, and (iv) the Fourth Amendment to Master Transaction Agreement dated as of July 31, 2008, collectively, the “Agreement”), among the Counterparty, the Guarantors and the Hedge Provider (unless otherwise expressly provided herein, capitalized terms used but not otherwise defined herein shall have the meanings assigned to such terms in the Agreement);

B.The Counterparty and the Guarantors have requested that the Hedge Provider amend the Agreement as hereinafter provided; and

C.The Hedge Provider is willing to amend the Agreement on the terms and conditions set forth herein.

NOW THEREFORE, in consideration of the premises and the covenants and agreements contained herein, the parties hereto agree as follows:

AGREEMENT

Section 1.Amendments to Agreement.  The Agreement is hereby amended, effective as of the Amendment Date,  as follows:

(a)Amendment to Section 1.01.  The definition of “Credit Agreement” in Section 1.01 of the Agreement is hereby amended and restated, effective as of the Amendment Date, in its entirety to read as follows:

““Credit Agreement” means the Second Amended and Restated Credit Agreement dated as of September 30, 2008 among the Borrowers, the Guarantors, the Lenders, and the Administrative Agent.”

(b)Amendment to Section 6.01.  Section 6.01 of the Agreement is hereby amended and restated, effective as of the Amendment Date, in its entirety to read as follows:

“Section 6.01Credit Agreement Negative and Financial Covenants.  Take or fail to take any action which causes a violation of any of the negative covenants or

financial covenants set forth in Article VI of the Credit Agreement, each as in effect on the Closing Date (as defined in the Credit Agreement), each such negative covenant and financial covenant, and all defined terms set forth in the Credit Agreement and referenced therein in their respective entireties (in each case as in effect on the Closing Date (as defined in the Credit Agreement)) being hereby incorporated herein by reference as if fully set forth herein (all such negative covenants, financial covenants and related defined terms being collectively referred to herein as the “First Lien Negative Covenants”).”

Section 2.Consent to Risk Management Policy.  The Hedge Provider hereby consents, effective as of the Amendment Date, to the revised Risk Management Policy dated September [    ], 2008 and delivered by the Counterparty to the Hedge Provider before the Amendment Date.

Section 3.Conditions to Effectiveness.  This Amendment shall be effective on the date when the Hedge Provider shall have received each of the following, in form and substance satisfactory to the Hedge Provider (such date, the “Amendment Effective Date”):

(a)counterparts of this Amendment, duly executed and delivered by the Counterparty and the Guarantors;

(b)a fully executed copy of the Second Amended and Restated Credit Agreement, dated as of September 30, 2008 (the “Credit Agreement”), duly executed and delivered by Transaction Parties, the Administrative Agent and the Majority Lenders;

(c)a complete revised Risk Management Policy of the Counterparty, in form and substance satisfactory to the Hedge Provider in its sole discretion;

(d)evidence reasonably acceptable to the Hedge Provider that all conditions to effectiveness of the Credit Agreement shall have been satisfied; and

(e)evidence satisfactory to the Hedge Provider that the Counterparty has paid all accrued and unpaid costs, expenses, fees and other amounts (including, without limitation, Management Fees and attorneys’ fees) due and payable to the Hedge Provider as of the Amendment Date pursuant to the Agreement or any other Transaction Document.

Section 4.Representations and Warranties.  Each Transaction Party hereby jointly and severally represents and warrants to the Hedge Provider that, as of the Amendment Date and the Amendment Effective Date:

(a)all representations and warranties of such Transaction Party contained in the Agreement and any other Transaction Document are true and correct in all material respects with the same effect as if such representations and warranties had been made on the Amendment Date (it being understood and agreed that any representation which by its terms is made as of a specified date shall be required to be true and correct only as of such specified date); and

(b)no Specified Event has occurred and is continuing.

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Section 5.Consent of Guarantors; Confirmation of Guarantees and Transaction Documents.  Each Guarantor hereby consents to the execution, delivery and performance of this Amendment and hereby confirms and agrees that, notwithstanding the effectiveness of this Amendment, the Guarantee contained in Article VIII of the Agreement and the terms and provisions of each other Transaction Document are, and each of the same shall continue to be, in full force and effect and are hereby ratified and confirmed in all respects.

Section 6.Governing Law.  This Amendment shall be governed by, and construed and enforced in accordance with, the internal laws of the State of New York without regard to conflict of laws principles.

Section 7.Entire Agreement; Transaction Document.  This Amendment, the Agreement and the other Transaction Documents constitute the entire agreement and understanding among the parties and supersede all prior agreements and understandings, whether written or oral, among the parties hereto concerning the transactions provided herein and therein.  This Amendment is and shall be deemed to be a Transaction Document in all respects and for all purposes.

Section 8.Execution in Counterparts.  This Amendment may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which when so executed shall be deemed to be an original and all of which taken together shall constitute one and the same agreement.  Delivery of an executed counterpart of a signature page to this Amendment by facsimile shall be as effective as delivery of a manually executed counterpart of this Amendment.

Section 9.Headings.  The headings set forth in this Amendment are and shall be without substantive meaning or content of any kind whatsoever and are not a part of the agreement between the parties hereto.

Section 10.Severability.  In case any provision in or obligation under this Amendment shall be invalid, illegal or unenforceable in any jurisdiction, the validity, legality and enforceability of the remaining provisions or obligations, or of such provision or obligation in any other jurisdiction, shall not in any way be affected or impaired thereby.

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IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed and delivered by their respective duly authorized officers as of the Amendment Date.

COUNTERPARTY:
MXENERGY INC.
By:	/s/ CHAITU PARIKH
	Chaitu Parikh
	Vice President and Chief Financial Officer
GUARANTORS:
MXENERGY ELECTRIC INC.
MXENERGY HOLDINGS INC.
ONLINE CHOICE INC.
MXENERGY GAS CAPITAL HOLDINGS CORP.
MXENERGY ELECTRIC CAPITAL HOLDINGS CORP.
MXENERGY GAS CAPITAL CORP.
MXENERGY ELECTRIC CAPITAL CORP.
MXENERGY CAPITAL HOLDINGS CORP.
MXENERGY CAPITAL CORP.
MXENERGY SERVICES INC.
INFOMETER.COM INC.
By:			/s/ CHAITU PARIKH
			Chaitu Parikh
			Vice President and Chief Financial Officer
HEDGE PROVIDER:
SOCIÉTÉ GÉNÉRALE
By:		/s/ GONZAGUE BATAILLE
		Name:		Gonzague Bataille
		Title:		Head of Commodities Market – Americas

Fifth Amendment to Master Transaction Agreement

EX-10.23

Exhibit 10.23

FIRST AMENDMENT TO

THIRD AMENDED AND RESTATED STOCKHOLDERS’ AGREEMENT

This First Amendment (this “Amendment”), dated as of June 9, 2008 (the “Amendment Effective Date”), to the Third Amended and Restated Stockholders’ Agreement dated June 25, 2004 (the “Stockholders’ Agreement”; terms not otherwise defined herein are used herein as therein defined), is by and among MXenergy Holdings Inc., a Delaware corporation (the “Company”), Charter Mx LLC, a Delaware limited liability company (“Charter Mx”), Denham Commodity Partners Fund L.P. f/k/a Lathi LLC, a Delaware limited partnership (“Denham”), and Stockholders holding a majority of the outstanding shares of Voting Stock as of the Effective Date.

PRELIMINARY STATEMENTS

A.Certain of the Stockholders desire to amend the Stockholders’ Agreement as hereinafter provided; and

B.The Stockholders party hereto, constituting the Company, Charter Mx, Denham and Stockholders holding a majority of the outstanding shares of Voting Stock as of the Effective Date, are willing to amend the Stockholders’ Agreement on the terms and conditions set forth herein.

NOW THEREFORE, in consideration of the premises and the covenants and agreements contained herein, the parties hereto agree as follows:

AGREEMENT

Section 1.Amendments to Stockholders’ Agreement.

(a)Amendment to Section 3.4.  Section 3.4 of the Stockholders’ Agreement is hereby amended by:

(i)deleting the word “and” contained at the end of clause (d) thereof; and

(ii)deleting the period contained at the end of clause (e) thereof and inserting in its place the following:  “and;”; and

(iii)inserting a new clause (f) to read as follows:  “without consideration by a Stockholder who is a natural person to a university or college, trust, foundation, unincorporated association or other not-for-profit entity established for charitable purposes that is exempt from federal income taxes pursuant to Section 501(c)(3) of the United States Internal Revenue Code (26 U.S.C. §501(c)).”; and

(iv)deleting in its entirety the reference to “cases (b), (c) and (d)” contained in the proviso following the end of clause (f), and replacing it with the following reference:  “cases (b), (c), (d) and (f)”; and

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(v)adding a further proviso to the end of the proviso following the end of clause (f) to read as follows:  “provided further, however, that in the case of clause (f) above, it shall be a condition to such transfer that the Board of Directors shall have approved such transfer (such approval to be within the complete discretion of the Board of Directors).

Section 2.Amendment Binding.  This Amendment shall be binding upon each holder of any securities outstanding (including securities into which such securities are convertible), each future holder of all such securities, and the Company.

Section 3.Governing Law.  This Amendment shall be governed by, and construed and enforced in accordance with, the laws of the State of Delaware as applied to agreements among New York residents entered into and to be performed entirely within New York.

Section 4.Entire Agreement.  This Amendment and the Stockholders’ Agreement constitute the entire agreement and understanding among the parties and supersede all prior agreements and understandings, whether written or oral, among the parties hereto concerning the transactions provided herein and therein.

Section 5.Execution in Counterparts.  This Amendment may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which when so executed shall be deemed to be an original and all of which taken together shall constitute one and the same agreement.  Delivery of an executed counterpart of a signature page to this Amendment by facsimile shall be as effective as delivery of a manually executed counterpart of this Amendment.

Section 6.Headings.  The headings set forth in this Amendment are and shall be without substantive meaning or content of any kind whatsoever and are not a part of the agreement between the parties hereto.

Section 7.Severability.  In case any provision in or obligation under this Amendment shall be invalid, illegal or unenforceable in any jurisdiction, the validity, legality and enforceability of the remaining provisions or obligations, or of such provision or obligation in any other jurisdiction, shall not in any way be affected or impaired thereby.

[Signature page follows]

2

IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed and delivered by their respective duly authorized officers as of the Amendment Effective Date.

MXENERGY HOLDINGS INC.
By:	/s/ CHAITU PARIKH
		Name: Chaitu Parikh
		Title: Vice President and CFO
CHARTER MX LLC
		By:	Charterhouse Equity Partners IV,
			L.P., its Managing Member
		By:	CHUSA Equity Investors IV, L.P.,
			its General Partner
		By:	Charterhouse Equity IV, LLC,
			its General Partner
By:	/s/ WILLIAM M. LANDUYT
		Name: William M Landuyt
		Title: Senior Partner
STOCKHOLDERS HOLDING A MAJORITY OF THE OUTSTANDING STOCK AS OF THE EFFECTIVE DATE
By:	/s/ JEFFREY A. MAYER
		Name: Jeffrey A. Mayer
DENHAM COMMODITY PARTNERS FUND L.P.
		By:	Denham Commodity Partners GP
			LP, its General Partner
		By:	Denham GP LLC,
			its General Partner
By:	/s/ STUART D. PORTER
		Name: Stuart D. Porter
		Title: Managing Member

3

EX-21

Exhibit 21

Subsidiaries of MXenergy Holdings Inc.

Subsidiary Name	Jurisdiction of Incorporation
MXenergy Capital Holdings Corp.	Delaware
MXenergy Capital Corp.	Delaware
MXenergy Gas Capital Holdings Corp.	Delaware
MXenergy Electric Capital Holdings Corp.	Delaware
MXenergy Gas Capital Corp.	Delaware
MXenergy Electric Capital Corp.	Delaware
MXenergy Inc.	Delaware
MXenergy Electric Inc.	Delaware
Online Choice Inc.	Delaware
MXenergy Services Inc.	Delaware
Infometer.com Inc.	Delaware
MXenergy (Canada) Ltd.	Nova Scotia

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EX-31.1

Exhibit 31.1

CERTIFICATION

BY THE CHIEF EXECUTIVE OFFICER

PURSUANT TO SECTION 302 OF THE

SARBANES-OXLEY ACT OF 2002

I, Jeffrey A. Mayer, certify that:

1.I have reviewed this Annual Report on Form 10-K of MXenergy Holdings Inc. (the “registrant”);

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

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5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s Board of Directors (or persons performing the equivalent functions):

a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 14, 2008	/s/ JEFFREY A. MAYER
	Jeffrey A. Mayer
	President and Chief Executive Officer
	(Principal executive officer)

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EX-31.2

Exhibit 31.2

CERTIFICATION

BY THE CHIEF FINANCIAL OFFICER

PURSUANT TO SECTION 302 OF THE

SARBANES-OXLEY ACT OF 2002

I, Chaitu Parikh, certify that:

I have reviewed this Annual Report on Form 10-K of MXenergy Holdings Inc. (the “registrant”);

1.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

2.Bas ed on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

3.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange A ct Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

4.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

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5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s Board of Directors (or persons performing the equivalent functions):

a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.  & #160;  Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 14, 2008	/s/ CHAITU PARIKH
	Chaitu Parikh
	Chief Financial Officer
	(Principal financial officer)

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EX-32

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report on Form 10-K of MXenergy Holdings Inc. (the “Company”) for the year ended June 30, 2008, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), we, Jeffrey A. Mayer, Chief Executive Officer of the Company, and Chaitu Parikh, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

Date:  October 14, 2008	/s/ JEFFREY A. MAYER
	Jeffrey A. Mayer
	President and Chief Executive Officer
	(Principal executive officer)
Date:  October 14, 2008	/s/ CHAITU PARIKH
	Chaitu Parikh
	Chief Financial Officer
	(Principal financial officer)

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