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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K/A

Amendment No. 1

(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, 2010

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)

(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 o No x

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes o 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 definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

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, 2010, there were 33,710,902 shares of the Registrant’s Class A Common Stock (par value $0.01 per share), 4,002,290 shares of the Registrant’s Class B Common Stock (par value $0.01 per share) and 16,438,669 shares of the Registrant’s Class C Common Stock (par value $0.01 per share) outstanding.

Documents incorporated by reference: None

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EXPLANATORY NOTE

This Amendment No. 1 on Form 10-K/A (“Amendment”) amends and restates in its entirety the Registrant’s Annual Report on Form 10-K for the fiscal year ended June 30, 2010 as originally filed with the Securities and Exchange Commission on September 28, 2010 (the “Original Filing”). This Amendment is being filed to correct an inadvertent clerical error in the Item 6 table which provides a reconciliation of Adjusted EBITDA to net cash provided by (used in) operating activities that appears on page 32 herein.

Pursuant to Rule 12b-15 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), the certifications required pursuant to the rules promulgated under the Exchange Act, as adopted pursuant to Sections 302 and 906 of the Sarbanes-Oxley Act of 2002, which were included as exhibits to the Original Filing, have been restated and re-executed as of the date of this Amendment and are included as Exhibits 31.1, 31.2 and 32 hereto.

This Amendment has no effect on the Registrant’s consolidated financial statements.  Except as described above, this Amendment does not amend, update or change any other items or disclosures contained in the Original Filing or otherwise reflect events that occurred subsequent to the filing of the Original Filing.

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MXENERGY HOLDINGS INC.

ANNUAL REPORT ON FORM 10-K/A

FOR THE FISCAL YEAR ENDED JUNE 30, 2010

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Cautionary Note Regarding Forward-Looking Statements

Some statements in this Annual Report on Form 10-K (the “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 include, but are not limited to, statements about our plans, objectives, expectations and intentions and other statements contained in the Annual Report that are not historical facts and 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, margins, profitability, attrition, bad debts, expenses, 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.

When used in this Annual Report on Form 10-K, the words “may,” “will,” “should,” “expects,” “anticipates,” “intends,” “plans,” “believes,” “seeks,” “predicts,” “estimates,” “potential,” “continue,” “projected” and similar expressions are generally intended to identify forward-looking statements, although the absence of such a word does not mean that such statement is not a forward-looking statement.

Forward-looking statements are subject to risks, uncertainties, and assumptions about us and our operations that are subject to change based on various important factors, some of which are beyond our control.  The following factors, as well as the factors identified in “Risk Factors,” among others, could cause our financial performance to differ significantly from the goals, plans, objectives, intentions and expectations expressed in our forward-looking statements:

·                  failures in our risk management policies and hedging procedures;

·                  shortfalls in marketing or unusual customer attrition that result in our purchases exceeding our supply commitments;

·                  unavailability or lack of reliability in monthly settlement index prices;

·                  changes in the forward prices of natural gas and electricity;

·                  insufficient liquidity to properly implement our hedging strategy or manage commodity supply;

·                  changes in weather patterns from historical norms that affect customer consumption patterns;

·                  failure of our customers to pay their bills or our failure to maintain adequate billing and collection procedures;

·                  failure of LDCs (as defined herein) to pay amounts owed to us when due;

·                  failure to collect imbalance receivables;

·                  inaccuracy of data in our billing systems;

·                  disruptions in local transportation and transmission facilities;

·                  changes in regulations that affect our ability to use marketing channels;

·                  changes in statutes or regulations that affect growth and commodity, operating or financing costs or otherwise impact our profitability;

·                  investigations by any state utility commissions, state attorneys general or federal agencies that could result in fines, sanctions or damage to our reputation;

·                  failure to properly manage our growth;

·                  the loss of key members of management or failure to retain employees;

·                  changes in general economic conditions;

·                  competition from utilities and other marketers;

·                  malfunctions in computer hardware or software or in database management systems or power systems, due to mechanical or human error, that result in billing errors or problems with collections, reconciliation, accounting or risk management;

·                  natural disasters, including hurricanes; and

·                  our reliance on energy infrastructure and transportation within the United States and Canada.

Therefore, we caution you not to place undue reliance on any forward-looking statements.  We undertake no obligation to publicly update or revise any forward-looking statements after the date of this Annual Report on Form 10-K to conform these statements to actual results.  All forward-looking statements attributable to us are expressly qualified by these cautionary statements.

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PART I

ITEM 1.  BUSINESS

Definitions

References in this 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 approximately 1,000,000 MMBtus.

References to “MWhr” refer to megawatt hours, each representing 1 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.  A governmental entity or LDC may be counted as a single customer despite representing an aggregation of multiple consumers of natural gas or electricity within a geographic service area under the terms of specific service agreements.  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.

Company Overview, History and Development

The Company was founded and incorporated in the state of Delaware in 1999.  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 number of retail energy marketers in the growing deregulated market.  We currently serve natural gas and electricity customers located in 41 market areas across 14 states in 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 as of June 30, 2010.

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Recent Developments

Equity and Debt Restructuring

A sharp drop in natural gas market prices during the six months ended December 31, 2008 resulted in a significant reduction in the available borrowing base under the Company’s revolving credit facility (the “Revolving Credit Facility”).  The reduced borrowing base strained the Company’s ability to post letters of credit as collateral with suppliers and hedge providers, caused defaults of certain financial covenants included in the agreement that governed the Revolving Credit Facility, prompted downgrades in the Company’s ratings from credit rating agencies and ultimately resulted in the Company obtaining material waivers of, and amendments to, the agreement that governed the Revolving Credit Facility and the Company’s principal commodity hedge facility (the “Hedge Facility”). Such amendments had material direct impacts on the Company’s liquidity position and operations during fiscal year 2009 and the first three months of fiscal year 2010, including requiring that the Company seek a new facility to replace the Revolving Credit Facility and the Hedge Facility.

On September 22, 2009, the Company completed an equity and debt restructuring, which included various transactions (the “Restructuring”).  The Restructuring included a debt exchange transaction that was accounted for as a troubled-debt restructuring in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”) and therefore did not result in any gain or loss recorded in the consolidated statements of operations.  The Company also entered into two master supply and hedge agreements with Sempra Energy Trading LLC (“RBS Sempra”) (the “ISDA Master Agreements” and collectively, the “Commodity Supply Facility”) to replace the Revolving Credit Facility and Hedge Facility.  The transactions consummated in connection with the Restructuring had material impacts on various asset, liability and stockholders’ equity accounts during the quarter ended September 30, 2009, as summarized in the following table.

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Material impacts of the Restructuring are further described in the “Balance Sheet Overview” section within Item 7 of this Annual Report.  As a result of the Restructuring, we significantly decreased our outstanding debt obligations, which resulted in lower debt service requirements for fiscal year 2010 and future years.  In addition, the Revolving Credit Facility and Hedge Facility were replaced by the Commodity Supply Facility, which provides us with a stable source of liquidity through August 2012 with an investment grade counterparty.  Overall, the transactions consummated in the Restructuring improved our liquidity position, improved our financial and operational flexibility and allowed us to compete more effectively within the markets that we serve.

Ohio SSO Program

In April 2010, we began delivering natural gas to an LDC in Ohio as part of a new Standard Service Offer program (the “SSO Program”).  Under the SSO Program, for the twelve-month period from April 1, 2010 through March 31, 2011, we will receive a NYMEX-referenced price plus a price adjustment for natural gas delivered by the LDC to its customers who are eligible to participate in the SSO Program.  We expect that our gross profit per MMBtu sold to the LDC will be lower under the SSO Program than the gross profit that we normally experience from our direct retail energy customers.  From April 1 through June 30, 2010, we delivered approximately 1.6 million MMBtus of natural gas to the LDC under the SSO Program.  As of June 30, 2010, based upon estimates received directly from the LDC, we expect that the customers assigned to us as a participant in the SSO Program will consume approximately 9.7 million MMBtus of natural gas annually, the majority of which will occur during the upcoming winter heating season.

Information Regarding Our Business Segments

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.

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Additional information regarding our business segments can be found in Note 23 of the audited consolidated financial statements, included in Item 8 of this Annual Report.

Our Products

We sell natural gas and electricity 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 two 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 the commodity is hedged in the forward markets with financial swaps and physical forward contracts that settle monthly.  Physical natural gas and electricity is then purchased at the time such swap contracts settle.  We regularly calculate the amount of the 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 market.

We market variations of two basic products:

·                     Fixed price contracts — Generally with terms of up to two years for natural gas and electricity, fixed rate products provide consumers with price protection against fluctuations in natural gas and electricity prices.  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 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, our objective is to hedge a minimum of 100% of the anticipated natural gas and electricity commodity purchases required to meet expected customer demand for all accounts served under fixed price contracts.  Any difference between actual consumption and our purchased commodity volume results in pricing risk for the month.

·                     Variable price contracts — Variable price products generally are priced competitively with the price offered by the region’s incumbent utility and/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, fixed term transportation costs and/or hedging strategy.  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 deliveries under variable rate natural gas and electricity 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.  However, we do hedge natural gas inventory purchased during the summer to ensure that the value of storage inventory is correlated to the market price of natural gas when it is withdrawn during the winter months.  Any difference between actual consumption and our purchased commodity volume results in pricing risk for the month.

The natural gas and electricity sold is metered and delivered to customers by LDCs.  Except in our Georgia natural gas and Texas electricity markets and for certain of our commercial customers, LDCs generally provide billing and collection services on our behalf for residential and small commercial customers.  In the case of our Georgia and Texas retail markets, we bill 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.

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Our Customer Portfolio

Our customer base consists of residential and small and mid-market commercial customers.  We have limited exposure to high concentrations of sales volumes to individual customers.  From April 1 through June 30, 2010, we delivered approximately 1.6 million MMBtus of natural gas to the LDC under the SSO Program, which represented approximately 3.6% of our total natural gas sales volume for fiscal year 2010.  For fiscal years 2009 and 2008, no single natural gas customer accounted for more than 3% of our total natural gas sales volume.

The following graph illustrates changes in our average RCE count for fiscal years 2006 through 2010.

The reduction in average natural gas RCEs during fiscal year 2010 resulted primarily from liquidity-related limitations placed on our ability to obtain new customers and to retain existing customers and from high credit-related attrition in certain of our markets.  Volatility in natural gas prices negatively impacted our liquidity position and resulted in amendments to our Revolving Credit Facility, which placed formal constraints on the term and type of contracts that we could offer to new customers and to existing customers who informed us of their intent to terminate their contract before its termination date.  In order to conserve cash, we also reduced direct mail marketing and advertising expenditures and scaled back our use of certain sales channels during fiscal year 2009 and the first quarter of fiscal year 2010, which had a negative impact on brand awareness and our ability to acquire new customers.

Deteriorating economic conditions during fiscal year 2009 resulted in credit-related attrition that was higher than historical levels.  Refer to “Retaining and Winning Back Customers” below for additional commentary regarding customer attrition.

During fiscal year 2010, we experienced a more stable price environment and lower customer defaults as compared with the prior fiscal year.  In addition, under the provisions of the Commodity Supply Facility, the constraints on our marketing and hedging activities have been removed, and we are able to offer a wider variety of natural gas and electricity products to current and potential customers using our traditional marketing channels.  As a result, during the second and third quarters of fiscal year 2010, we experienced in-contract attrition in most of our natural gas and electricity markets that was lower than that experienced during fiscal year 2009 and the first quarter of fiscal year 2010, and we experienced customer growth in certain of our electricity markets.

Acquiring New Customers

As of June 30, 2010, most of our current customers have been acquired organically through an integrated marketing approach that consists of multiple combinations of direct marketing activities, such as door-to-door marketing, success-based and hourly telemarketing and direct mailings, and indirect marketing activities, which include traditional and online media, public

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relations and local event participation.  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.  As a result of our return to normal marketing activities, our total expenditures for acquiring customers, which includes amounts capitalized as customer acquisition costs and certain other marketing and advertising expenses, increased approximately 50% during fiscal year 2010, as compared with the prior fiscal year.  Our cost to acquire customers approximated $100 per RCE for fiscal year 2010, which was consistent with the amount spent per RCE in the prior fiscal year.

In order to conserve cash, we significantly reduced direct mail marketing, advertising and overall marketing expenditures during fiscal year 2009, as compared to the prior fiscal year.  We also scaled back our use of certain sales channels, which had a negative impact on brand awareness and new customer acquisitions during fiscal year 2009.  During fiscal year 2010, as a result of the Restructuring, we are offering a wider variety of natural gas and electricity products to current and potential customers using our traditional marketing channels.

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 and liquid instruments; and

·                 the acquisition can be supported by our financing capabilities.

Some of the companies we acquired were 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.  We completed 10 separate acquisitions since our inception in 1999, including the following acquisitions since 2005:

On August 1, 2006, we acquired substantially all of the assets of SESCo, a wholly owned subsidiary of Shell Oil Company.  As of August 1, 2006, SESCo supplied natural gas to approximately 315,000 RCEs in the deregulated markets of Georgia and Ohio.  In addition to expanding our relationships with customers in two of our existing LDC markets in Ohio, the SESCo acquisition added Georgia to the list of states in which we operate.  Georgia has been our largest natural gas market since the acquisition of SESCo.

Customer Retention and Attrition

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 commodity 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 with those customers are made through both mail and phone, encouraging the customer to reconsider his or her decision, reminding the customer of early-termination fees he or she may incur and, in some cases, offering a new rate plan.

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Customer renewal and in-contract attrition percentages are summarized in the following tables.

(1)   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.  Customer renewal percentages in the table represent the percentage of customers who received such notification that ultimately continued their relationship with us.

(2)   In-contract customer attrition percentage is defined as: (a) the percentage of loss of fixed rate customers after they have begun to receive natural gas or electricity from us but before their contract term officially expires; and (b) the percentage of loss of any variable rate customers, whose contracts generally do not have expiration dates.

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 MWhr per year.  However, each customer does not actually consume 100 MMBtu of natural gas or 10 MWhr of electricity.  For example, one of our mid-market or large commercial customers may consume the equivalent of several hundred or even thousands of RCEs.  Therefore, any reduction or increase in RCEs in any of our markets does not necessarily correlate directly with net customer attrition.

Fiscal year 2009 was an unusually challenging year for us with respect to customer retention and attrition.  Our marketing activities and hedging capabilities were constrained under the Revolving Credit Facility and Hedge Facility, which severely limited our ability to offer desirable product options to existing or new customers.  For instance, our ability to offer long-term fixed rate products to new and renewal customers was severely limited.  This contributed to attrition generally, and particularly for various commercial customers, each of which represented a large number of RCEs per customer.  Organic customer growth was also well below our historical levels due to these constraints.

Difficult economic conditions in many of our markets during fiscal year 2009 and the first three months of fiscal year 2010 resulted in credit-related attrition that was higher than historical levels.  Credit-related attrition was particularly high in our Georgia natural gas market, partially due to expected credit quality issues within the portfolio of customers that we acquired from Catalyst Natural Gas LLC (“Catalyst”) in October 2008.

Volatile commodity prices during fiscal year 2009 caused many consumers of natural gas and electricity to migrate to market rates that were lower than their current rates.  Since we were limited in our ability to offer new competitive rates to customers who indicated their intention to terminate their contract, many of our customers left us in favor of other retail marketers or their local utility.

During fiscal year 2010, we and our customers experienced a more stable price environment and lower customer defaults as compared with the prior year.  In addition, under the provisions of the Commodity Supply Facility, the constraints on our marketing and hedging activities have been removed, and we are able to offer a wider variety of natural gas and electricity products to current and potential customers using our traditional marketing channels.  As a result, during fiscal year 2010, we experienced lower in-contract attrition in most of our natural gas and electricity markets and customer growth in certain of our electricity markets.

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Customer Contract Concentrations

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 price 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.

As of June 30, 2010, 2009 and 2008, approximately 42%, 45% and 60%, respectively, of our natural gas customer portfolio had fixed rate contracts while the remaining 58%, 55% and 40%, respectively, 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, our objective is to hedge a 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, 2010, contracts with our fixed price natural gas customers have an average remaining life of approximately 5 months.

As of June 30, 2010, 2009 and 2008, approximately 70%, 36% and 36%, respectively, of our electricity customer portfolio had fixed rate contracts while the remaining 30%, 64% and 64%, respectively, had variable rate contracts.  Although our objective is to economically hedge a minimum of 100% of anticipated electricity commodity purchases required to meet expected customer demand under fixed price contracts, there are certain ancillary and capacity costs that we are unable to hedge due to the term and the size of our electricity portfolio.   In addition, since we cannot fully anticipate hourly spikes in demand for electricity during peak summer months, we may be unable to fully hedge commodity purchases necessary to meet such spikes in demand.  Historically, our inability to economically hedge certain electricity commodity purchases and related costs has not had a material impact on our results of operations.  As of June 30, 2010, contracts with our fixed price electricity customers have an average remaining life of approximately 6 months.

Geographic Market Concentrations

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

·                  benefit from a diverse geographic stream of sales;

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

·                  lower supply price risk and/or the risk of ancillary services events in a particular electricity market;

·                  achieve scalability from knowledge of multiple LDC programs and procedures;

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

·                  lower the risk of extreme regional weather patterns;

·                  lower the risk of material impact from regional economic downturns;

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

·                  capitalize on our regional supply and pricing knowledge.

RCEs by geographic area, excluding the SSO Program, are summarized in the following table.

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(1)         Includes markets in Georgia, Texas and Florida.

(2)         Includes markets in New York, New Jersey, Connecticut, Massachusetts, Pennsylvania, Maryland, Ontario and British Columbia.

(3)         Includes markets in Ohio, Michigan, Indiana, Illinois and Kentucky.

(4)         Excludes RCEs to be served in connection with the SSO Program in Ohio, pursuant to a one-year contract that expires March 31, 2011.

Our business platform is partly based on providing long-term, fixed rate price protection in contrast to variable rates offered by LDCs against which we compete in the markets that we serve.  For the majority of fiscal year 2009, our financial and liquidity restrictions limited new and renewed contract terms to 12 months or less.  Therefore, we were unable to fulfill consumer demand for longer-term products, losing growth and renewal opportunity to LDCs and competitors in many of our markets.

Southern U.S. markets — Total RCEs in our southern markets decreased 20% and 17% during fiscal years 2010 and 2009, respectively, mainly due to a decrease in our customer base in the Georgia natural gas market.  In addition to the impact of liquidity constraints in Georgia, customer account terminations were also unusually high due to bad debt experience attributed to economic conditions, and to more stringent credit standards initiated during the year for new and renewable customer accounts.  Liquidity and contract term limitations also impacted growth and renewals in our Texas electricity market.

Northeastern U.S., Mid-Atlantic U.S. and Canadian markets — Total RCEs within this region increased 54% during fiscal year 2010, primarily due to strong customer growth in various electricity markets.  During fiscal year 2010, we focused on growth in our existing guaranteed electricity markets in order to improve the seasonal cash flow associated with the electricity business segment and reduce risks associated with commodity and geographic concentrations.  In addition, actual electricity RCEs at June 30, 2010 include approximately 56,000 RCEs added as a result of our expansion into a new electricity market in Pennsylvania.

In April 2010, we obtained our electricity retail supplier license in the State of Maryland and began actively marketing in July to electricity customers within a Maryland service territory.  Additionally, recently approved regulations in Maryland will require natural gas and electricity utilities to either guarantee supplier receivables or improve the way customer payments are allocated to suppliers.  Within one of the two natural gas markets in Maryland where we currently operate, the LDC began guaranteeing the receivables of retail suppliers on July 15, 2010.  We anticipate the other LDC market in Maryland will begin guaranteeing receivables sometime during fiscal year 2011.

Recent legislation in Massachusetts will require electricity LDCs to guarantee the accounts receivable of retail suppliers, although the time frame for this implementation is currently unknown.  New initiatives that will increase the attractiveness of certain other northeastern electricity and natural gas markets also began to take effect early in fiscal year 2011.

Midwestern U.S. markets — Total RCEs in our Midwestern region, excluding RCEs expected to be served in connection with the SSO Program, decreased 9% and 26% during fiscal years 2010 and 2009, respectively, due primarily to competitive pressure and budgetary constraints placed on our sales and marketing team.  The contract term limitations placed on us prior to the Restructuring also significantly impacted growth opportunities in the Michigan market.

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In April 2010, we began delivering natural gas to an LDC in Ohio as a participant in the SSO Program.  Under the SSO Program, we receive a NYMEX-referenced wholesale price plus a retail price adjustment for natural gas delivered by the LDC to its customers who remain eligible to participate in the SSO Program.  As of June 30, 2010, based upon estimates received directly from the LDC, we expect that the customers assigned to us as a participant in the SSO Program will consume approximately 9.7 million MMBtus of natural gas annually.

Potential market growth opportunities — For fiscal year 2011, we will continue to explore expansion into LDC markets that are open to competition and appear to provide attractive growth potential.  The decision to enter into new LDC territories will continue to be governed by several factors, including:

·                compatibility with our existing operating systems and supply base;

·                attractiveness of LDC program rules, such as billing options and guarantees of customer accounts receivable;

·                competitive landscape;

·                mass market consumption profiles;

·                regulatory climate;

·                market location and size; and

·                our ability to provide value to customers.

Guaranteed and Non-Guaranteed Market Concentrations

We are exposed to direct credit risk associated with customer accounts receivable in eleven of the markets that we serve, where such receivables are not guaranteed by LDCs.  For fiscal years 2010, 2009 and 2008, 51%, 55% and 56%, respectively, of our total sales of natural gas and electricity were within markets where LDCs do not guarantee customer accounts receivable.  We refer to these markets as “non-guaranteed” markets.  We maintain an allowance for doubtful accounts, which represents our estimate of potential credit losses associated with accounts receivables from customers within non-guaranteed markets.  We record a provision for doubtful accounts based on historical loss experience within our markets and periodically assess the adequacy of the allowance for doubtful accounts through review of the aging of customer accounts receivable and general economic conditions in the markets that we serve.

Within thirty of the markets that we serve, we operate under a purchase of receivables program whereby all billed receivables are purchased by the LDC.  We refer to these markets as “guaranteed” markets.  For fiscal years 2010, 2009 and 2008, 49%, 45% and 44%, respectively, of our total sales of natural gas and electricity were 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.  Within these markets, we are exposed only to the credit risk of the LDC, rather than that of our customers.  We monitor the credit ratings of LDCs and the parent companies of LDCs that guarantee customer accounts receivable.  We also periodically review payment history and financial information for LDCs to ensure that we identify and respond to any deteriorating trends.  As of June 30, 2010, all of our customer accounts receivable in LDC-guaranteed markets were from LDCs with investment grade credit ratings.

In addition, in certain markets, we have commercial customers that have asked us to bill them directly for consumption of natural gas and electricity.  For these customers, we bear credit risk associated with non-payment by the customer.

Commodity Supply and Pricing Risk Management

Natural Gas Supply

We buy natural gas in the wholesale market in time and location specific bulk quantities at fixed and indexed prices.  Effective September 22, 2009, under the Commodity Supply Facility, we began purchasing natural gas supply from RBS Sempra, as our exclusive natural gas supplier.  The Commodity Supply Facility also requires that we release natural gas transportation and storage capacity to RBS Sempra and for RBS Sempra to perform certain transportation and storage nominations.  During fiscal year 2010, we released transportation and storage capacity in several markets to RBS Sempra according to a mutually acceptable schedule and in a manner intended to ensure an effective transition of these functions.  In connection with the Commodity Supply Facility, we are obligated to reimburse RBS Sempra for various direct costs associated with transportation and storage capacity released to RBS Sempra by the Company.

We periodically adjust our portfolio of supply purchase and sales contracts, storage and transportation capacity based upon continual analysis of our forecasted load requirements to determine whether it would be more economical to utilize natural gas from storage or to purchase from the spot market, with consideration given 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’ locations of use, utilizing its extensive network of small diameter distribution pipe.

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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 buy electricity in the wholesale market in time and location specific block and hourly shaped quantities at fixed and indexed prices. Effective September 22, 2009, under the Commodity Supply Facility, we began purchasing electricity from RBS Sempra, as our exclusive electricity supplier.  The Commodity Supply Facility also requires that RBS Sempra perform certain load bidding and scheduling services on our behalf with the respective Independent System Operator (ISO) or Regional Transmission Organization (RTO) to the Company’s customers in each LDC.  In connection with the Commodity Supply Facility, we are obligated to reimburse RBS Sempra for various direct costs associated with scheduling and balancing the Company’s supply to the ISOs and RTOs.  ISOs and RTOs provide services such as transmission and load balancing, which comprise a relatively small portion of the end user’s utility bill in comparison with energy and capacity costs.

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.  Our objective under this policy is to economically hedge all anticipated natural gas and electricity commodity purchases required to meet expected customer demand for all accounts served under fixed price contracts.  We typically contract for sufficient commodity volume to meet 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 to weather changes, we may have to buy or sell additional natural gas or electricity volume, which exposes us to additional 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 the following instruments to offset price risk associated with volume commitments under fixed and variable price contracts where the price to the customer must be established ahead of the index settlement:  (1) for natural gas: NYMEX-referenced gas swaps, basis swaps, physical commodity hedges, physical basis hedges and index options; and (2) for electricity: ISO zone specific swaps, basis swaps, physical commodity hedges, physical basis hedges and index options.  We also utilize carbon dioxide offset credits and various renewable energy credits in order to meet regulatory requirements related to operating in electricity markets and our commitments from “green” product offers.

Refer to Item 7A of this Annual Report for additional commentary regarding commodity price risk management.

Seasonality of Operations

The majority of natural gas customer consumption occurs during the months of November through March.  By contrast, electricity customer consumption peaks during the months of June through September.  Because the natural gas business segment comprises such a large component of the Company’s overall business operations, operating results for the second and third fiscal quarters represent the vast majority of operating results for the Company’s full fiscal year.

Cash collected from natural gas customers peaks in the late winter and early spring of each calendar year, while cash collected from electricity customers peaks in the late summer and early fall.  The Company utilizes a considerable amount of cash from operations to meet working capital requirements during the months of November through March of each fiscal year.  In addition, the Company utilizes considerable cash to purchase natural gas inventories during the months of April through October.

Budget billing programs can reduce the seasonality of cash receipts, but they can also cause timing differences between the billing and collection of accounts receivable and the recording of revenues.  The payment terms of LDCs also can cause timing differences between the billing and collection of accounts receivable and the recording of revenues.

Weather conditions have a significant impact on customer demand and market prices for natural gas and electricity.  Customer demand exposes the Company to a high degree of seasonality in sales, cost of sales, billing and collection of customer accounts receivable, inventory requirements and cash flows.

The impact of rapidly rising or falling commodity prices also varies greatly depending on the period of time in which they occur during our fiscal year.  Although commodity price movements can have material short-term impacts on monthly and

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quarterly operating results, our economic hedging and contract pricing strategies may reduce the impact of such trends on operating results for a full fiscal year.

Industry Overview

Market Deregulation

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

In many cases, LDCs actively support deregulation and have welcomed the entry of retail energy marketers.  Regulated LDCs generally do not profit from commodity supplied to their customers; rather, their rate of return is based on their infrastructure assets or “rate base.” Accordingly, regulated LDCs charge consumers for commodity on a pass-through basis, and do 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.

Our retail energy sales depend upon our ability to identify and enter profitable, deregulated, retail energy markets, manage the cost of customer acquisitions, retain customers and attract new customers in our existing markets, and integrate acquired businesses successfully.  The principal components of our strategy to compete in existing and new markets include:

·                 offering competitively priced products;

·                 maintaining prudent and proven hedging and risk management policies;

·                 building and maintaining an excellent commodity supply team;

·                 pursuing organic growth and opportunistic acquisitions;

·                 maintaining a low cost operating structure;

·                 upholding high customer service standards; and

·                 leveraging our investment in information systems.

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.

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According to the United States Energy Information Agency (“EIA”), as of December 2009, 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 2009, of the approximately 65.3 million residential natural gas customers in the U.S., nearly 35.0 million have access to choice programs, with approximately 5.1 million (or 14.7% of eligible customers) actually 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.

As of December 31, 2009, there were approximately 150 marketers licensed to serve residential natural gas customers, of which 110 were actively serving or enrolling customers.  Marketers competing for the commercial and residential markets fall into three categories: utility affiliates, national marketers and niche marketers.  The commitment of many of these marketers is often modest, confined to a limited geographic region, and supported by limited capital, personnel and operational infrastructure.

We focus on natural gas markets that are less susceptible to competitive pressures on profit margins and that lend themselves to mass-market techniques.  The number of active competitive retail natural gas marketers ranges from 2 to 15 in most of the states that we serve, with as many as 60 in New York.  In addition to all local utilities, we consider the main retail competitors within our natural gas markets to be Georgia Natural Gas, Direct Energy (an affiliate of UK based Centrica), Gas South, Vectren Source, IDT Energy, Dominion Retail Energy (a deregulated affiliate of Dominion Resources, Inc.), Just Energy and Interstate Gas Services.

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.

According to the EIA, as of May 2010, 15 states and the District of Columbia operate retail markets in which customers may choose alternative electricity suppliers.  For electricity, our primary retail competitors are ConEd Solutions, Direct Energy, StarTex Power, TXU Energy, Reliant Energy, Champion Energy Services and Dominion Retail Energy.

Foreign Operations

Our foreign operations are located in Canada.  Foreign operations comprised less than 1% of our consolidated total assets at June 30, 2010 and 2009 and less than 1% of our consolidated sales of natural gas and electricity for the fiscal years ended June 30, 2010 and 2009.  Management believes that the financial and operational risks associated with our Canadian operations are immaterial.

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 in Item 10 of this Annual Report.

As of June 30, 2010, we had approximately 203 full-time equivalent employees in the United States and Canada.  None of our employees are subject to a collective bargaining agreement, and we believe that our relationship with our employees is good.

Environmental Matters

We do not have physical custody or control of the natural gas provided to our customers, or any facilities used to produce or transport natural gas or electricity.  Although we hold title to natural gas in interstate pipelines and storage tanks, we believe that the carriers have the liability risk associated with infrastructure failures that could cause environmental issues.  Therefore, we do not believe that we have significant exposure to legal claims or other liabilities associated with

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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 our corporate headquarters: 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 consumption volumes or market rates.

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 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 or be below expected attrition, which could result in a cost to cover previously purchased fixed price hedges and physical commodity supply or in incremental cost to source additional commodity supply.

Although our fixed price contracts with residential customers generally have terms of up to two 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 remedies 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.  Conversely, if forecasted attrition is higher than actual realized attrition, we are at risk for having to source additional hedges or supply at potentially higher market prices where no price increase can be passed on to customers through the duration of their contract terms.

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

We hedge our forward natural gas exposures through a combination of physical supply purchases and financial swap agreements.  Financial swap agreements may be settled against monthly New York Mercantile Exchange (“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 that are not present elsewhere in the country.  Accordingly, the NYMEX settlement prices may cease to accurately reflect 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 industry 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 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 derivative and physical contracts, we attempt to balance our physical and financial purchases and sales commitments.  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 estimate or predict.

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

Certain of our LDC, transportation and storage agreements 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 our customer base grows or as a result of movements in the market prices of commodity.  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 with a secondary peak during the winter.  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 natural gas and electricity consumption than forecasted.  Likewise, when winters are colder or summers are warmer than expected, consumption may be greater than we have hedged and, in the case of natural gas, may be 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-related 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 impacted materially 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.

Large fluctuations in the market price of natural gas and electricity within short periods of time also may have a negative impact on the availability of credit necessary to operate our business.

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

We bear direct credit risk related to our customers located in markets where accounts receivable are not guaranteed by LDCs.  This group of customers represented approximately 51% of our sales of natural gas and electricity during the fiscal year ended June 30, 2010.  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 electricity or natural 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.  Changing economic factors, such as rising unemployment rates and energy prices also result in a 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.

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

In certain markets, we rely on the LDC to guarantee customer accounts receivable and to perform timely and accurate billing.  Sales within these guaranteed markets represented approximately 49% of our total sales of natural gas and electricity during the fiscal year ended June 30, 2010.  As our business grows, the proportion of customers we serve that are billed by utilities could increase.  The bankruptcy of an LDC could result in a default in such LDC’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 demands considerable management, personnel and information system 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 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.

Settlements of imbalance receivables from certain LDCs and independent system operators may be subject to such LDCs’ or independent system operators’ ability to settle their imbalance receivables from other retail marketers.

Retail energy marketers are responsible for providing adequate natural gas to LDCs and electricity to independent system operators (“ISOs”) for ultimate delivery to customers.  Commodity amounts provided are generally based on estimates of customer usage over a prescribed period.  Imbalances occur when commodity amounts delivered by us to an LDC (for natural gas) or an ISO (for electricity) exceed amounts consumed by our customers (resulting in a receivable from the LDC or ISO) or when commodity amounts consumed by our customers exceed amounts delivered by us to the LDC or ISO (resulting in a payable to the LDC or ISO).  Certain LDCs and ISOs rely on collection of imbalances payable to them in order to settle imbalances payable by them to retail marketers.  If retail marketers default on their obligations to settle an imbalance owing to an LDC or an ISO, such LDC or ISO may not have adequate resources to satisfy its obligation to settle imbalances owing to marketers.  Therefore, the inability of an LDC or an ISO to collect imbalance amounts from other retail energy marketers may hinder our ability to collect imbalance amounts owed to us by such an LDC or ISO.

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, pricing, information systems and customer operations functions;

·                LDCs and ISOs with which we have billing service agreements; and

·                various LDCs and ISOs 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.

The Commodity Supply Facility is an exclusive arrangement to purchase natural gas and electricity from a single supplier.  The lack of competitive suppliers could result in higher commodity supply prices for us.

Prior to the Restructuring, we purchased natural gas and electricity from a portfolio of producers, marketers and energy trading firms in either a producing region or at delivery points.  The ability to source supply from multiple suppliers ensured a competitive pricing environment in which we could seek the lowest possible price for our business.

Effective September 22, 2009, we are required to purchase natural gas and electricity from RBS Sempra under an exclusive supply arrangement.  Under the terms of the Commodity Supply Facility, we have the ability to: (1) seek commodity price quotes from third parties for certain physically or financially settled transactions with respect to gas and electricity; and (2) request that RBS Sempra enter into such transactions with such third parties at such prices and to concurrently enter into back-to-back off-setting transactions with us with respect to such third party transactions.  RBS Sempra would not be obligated to enter into a transaction with any third party unless it is satisfied with the proposed transaction and counterparty

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and the volume of those transactions does not exceed annual limits.  In addition to the actual purchase price paid by RBS Sempra and certain related costs and expenses, we will be charged a fee for such purchases.

There is no guarantee that RBS Sempra would approve purchases of natural gas and electricity from third-parties when the prices offered by those third parties are beneficial to us.  Additionally, if RBS Sempra approves these transactions, RBS Sempra will charge us a fee and other transaction-related costs, which would decrease the benefit to us.  As a result, our ability to obtain the lowest possible pricing for commodity transactions may be reduced, which may result in higher commodity costs and lower gross profit per unit of natural gas or electricity sold to our customers.

In connection with the Commodity Supply Facility, RBS Sempra currently manages the scheduling of natural gas and electricity deliveries to LDCs and natural gas transportation logistics and storage capacity that we formerly managed internally.  As a result, we have less direct control over scheduling of natural gas and electricity to LDCs, which could result in lower reliability for deliveries to customers.

Prior to the Restructuring, we managed natural gas and electricity supply and natural gas storage capacity and transportation logistics internally.  We have well-trained management and staff who have developed strong expertise and effective working relationships related to these functions.  RBS Sempra now manages these functions in connection with the Commodity Supply Facility, with the operating support of our management and staff.  If RBS Sempra fails to effectively manage these functions, or fails to appropriately utilize our expertise, deliveries of natural gas and electricity to LDCs, and ultimately to our customers, could become less reliable, which could have a negative impact on our reputation and results of operations.

RBS Sempra’s majority owner announced that it intends to sell its stake in RBS Sempra, which could impact RBS Sempra’s ability to function as our primary commodity hedge and credit provider.

Royal Bank of Scotland Group announced that it intends to divest its majority interest in RBS Sempra.  We are uncertain whether such a divestiture will occur, whether it will occur in an orderly fashion, whether RBS Sempra’s ability to maintain its operations will be impacted, or whether its ability to provide us with commodity and economic hedges pursuant to the Commodity Supply Facility will be affected.  If RBS Sempra is unable to meet its supply, credit and hedging obligations under the Commodity Supply Facility, our liquidity position and operations may be adversely affected.

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.

We also depend on local utilities for maintenance of the infrastructure through which we deliver electricity and natural gas to our customers.  We are unable 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 risk management policies, hedge contracts and financial results and condition.

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

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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 electricity 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 natural gas and electricity industries.  If competitive restructuring of the natural gas and electricity 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 electricity and natural 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 electricity and natural gas markets created by these initiatives.  Regulations may be revised or reinterpreted or new laws and regulations may be adopted or become applicable to our operations or us.  Such changes may have a detrimental impact on our business, including our ability to use our established marketing channels.

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: (i) delay or reverse the deregulation process; (ii) interfere with our ability to do business; (iii) inhibit our growth; (iv) increase our commodity, operating or financing costs; or (v) otherwise impact our profitability. If competitive restructuring of electricity and natural gas markets is altered, reversed, discontinued or delayed, our business prospects and financial results could be negatively impacted.

As a result of recent economic events affecting the U.S. and world economies, the federal government recently enacted new legislation pursuant to which various federal agencies will implement new regulations for the financial services industry that could have an impact on the availability and cost of credit and hedging instruments.

The federal government recently enacted the Dodd-Frank Wall Street Reform and Consumer Protection Act pursuant to which various federal agencies will implement new regulations that will have significant impacts on the operations of financial institutions.  The impact of such regulations may affect the ability of financial institutions to offer credit and hedging instruments without significant additional capital or other costs to them.  Such increases in capital and other costs to financial institutions may result in higher costs to us in connection with our Commodity Supply Facility, which could increase our commodity, operating or financing costs or otherwise impact our profitability.

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 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.

Among other things, the growth of our operations will depend upon our ability to expand our customer base in our existing 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.  The Commodity Supply Facility may not be adequate to meet these higher liquidity requirements.

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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, financial condition and internal controls over financial reporting 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 or chief financial officer could give rise to a default under the Commodity Supply 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 normal employee turnover is expected, and additional turnover may occur due to reduced job responsibilities in certain roles as a result of the Restructuring, 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 alternate facilities;

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

·                  failure of performance by a counterparty to our hedge positions or lending agreements.

Such failures to perform by our business counterparties 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 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 a 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.

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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 termination 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 and related computer hardware.  Failure to continue 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, computer hardware and the employees that are responsible to manage them.  If any of our system conversion or improvement projects is unsuccessful, if we experience a catastrophic malfunction in any of our hardware or software, or if our processes for managing and maintaining our information systems are inadequate, we could be subjected to:

·                  inaccurate or non-timely financial accounting and reporting information;

·                  inaccurate or non-timely 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 employees and certain of our customers live are located along the southeast coast of Texas and are vulnerable to hurricanes in the Gulf of Mexico.

Because of its proximity to the Gulf of Mexico, the southeastern 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 in Houston, Texas and the surrounding 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.  If our business continuity plan does not function as planned, our operations, financial position and results of operations may be negatively impacted.

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

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

We identified a material weakness in the design and operation of our internal controls over financial reporting as of June 30, 2010 and 2009.  Although we instituted new controls and processes to address the material weakness during fiscal year 2010, there can be no assurance that such controls will effectively prevent material misstatements in our consolidated financial statements in future periods.

In our Annual Report on Form 10-K for the fiscal year ended June 30, 2009, we reported our conclusion that a combination of significant deficiencies, when considered in the aggregate, constituted a material weakness in our internal control over financial reporting.  For certain of the deficiencies noted as of June 30, 2009, we instituted and tested new controls and processes, which we concluded were effective during fiscal year 2010.

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Certain prior deficiencies still exist as of June 30, 2010, resulting in adjustments to our accounting records at June 30, 2010 for amounts that related to quarterly and annual periods previously reported.  These adjustments were not deemed by management to be material, individually or in the aggregate, in relation to our financial position or results of operations, taken as a whole, for any annual or quarterly reporting period during fiscal years 2010 or 2009.  However, we concluded that the deficiency continues to be a material weakness in the design and operation of our internal controls over financial reporting as of June 30, 2010 such that there was a reasonable possibility that a material misstatement of our interim or annual financial statements would not have been prevented or detected on a timely basis.

As of June 30, 2010, we have instituted enhanced processes and controls to support and validate the proper recording of revenue for substantially all of our markets.  Because controls for some of the markets were completed late in our fiscal year, however, we have not yet adequately tested the effectiveness of the controls for those markets.  While we believe that these enhanced controls and processes will remedy the material weakness, there can be no assurance that such controls will effectively prevent material misstatements in our consolidated financial statements.

Risks Related to Liquidity, Indebtedness and Capital Structure

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.  Our ability to obtain new financing will be constrained by the current economic conditions affecting financial markets and by the restrictive covenants contained in the agreements that govern the Commodity Supply Facility and the Fixed Rate Notes due 2014.  Specifically, the recent credit crisis and other related trends affecting the banking industry have caused significant operating losses and failures throughout the banking industry.  Many lenders and institutional investors have ceased to provide funding to potential borrowers.  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.  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 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.  We are limited in our ability to utilize the proceeds from new debt and equity issuances to prepay and repay the Fixed Rate Notes due 2014.

Holdings has no material operating activities.  Accordingly, Holdings’ only material source of cash, including cash to service the Commodity Supply Facility, the Fixed Rate Notes due 2014 and the Floating Rate Notes due 2011, 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.

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.  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.  Additionally, the terms of the Commodity Supply Facility limit our ability to incur additional indebtedness.  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.

We are exposed to the risk of rapid and significant increases in market prices and their potential impact on our operations in general and on our liquidity under the Commodity Supply Facility in particular.

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Dramatic swings in the market prices for natural gas during the fiscal year ended June 30, 2009 resulted in a significant strain on our liquidity under our Revolving Credit Facility, which was terminated as part of the Restructuring.  The significant increases and decreases in market prices over this period highlighted the difficulty of predicting market prices and anticipating their impact on our operations.  There can be no assurance that any actions we have taken will mitigate the risks associated with the volatile market price environment.  As a result, we will continue to be exposed to the risk of volatile market prices for natural gas and electricity and their impact on availability under the Commodity Supply Facility.

Our substantial debt obligations could adversely affect our financial health and prevent us from fulfilling such obligations, including our obligations under the Commodity Supply Facility, the Fixed Rate Notes due 2014 and the Floating Rate Notes due 2011 and we might have difficulty obtaining additional financing.

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 is limited by the agreements governing the Commodity Supply Facility, the Fixed Rate Notes due 2014 and the Floating Rate Notes due 2011.  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.

Restrictive covenants in the terms of our financings may reduce our operational and financial flexibility, which may prevent us from capitalizing on business opportunities.

The agreements that govern the Commodity Supply Facility and the Fixed Rate Notes due 2014 contain a number of operating and financial covenants restricting Holdings’ and its subsidiaries’ ability to, among other things:

·                  incur additional indebtedness;

·                  create liens on assets;

·                  pay dividends or distributions on, or redeem or repurchase, capital stock;

·                  make investments;

·                  transfer or sell assets;

·                  guarantee debt;

·                  restrict dividends and other payments;

·                  consolidate, merge or transfer all or substantially all assets and the assets of subsidiaries; and

·                  engage in unrelated businesses.

In addition, under the Commodity Supply Facility, Holdings and its subsidiaries are required to maintain a collateral coverage ratio.  If we breach any of the covenants contained in the agreements that govern the Commodity Supply Facility or the indenture, the principal of, and accrued interest on, the applicable debt could become due and payable.  In addition, that default could constitute a cross-default under our other indebtedness.  Although any default under the Fixed Rate Notes due 2014 is subject to certain standstill provisions, if such a default or cross-default were to occur, we would not be able to satisfy our debt obligations, which would have a substantial material adverse impact on our ability to continue as a going concern.  There can be no assurance that we will be able to comply with these restrictions in the future or that our compliance would not cause us to forego opportunities that might otherwise be beneficial to us.

As a result of the Restructuring, our amended organizational documents and governance agreements and the significant changes in our equity ownership could have a material impact on the Company’s future strategic direction.

As a result of the Restructuring, there was a significant change in our ownership.  In addition, holders of our Class A Common Stock, Class B Common Stock and Class C Common Stock were given separate approval rights under our organizational documents, which could have an impact on the future direction of the Company, including decisions regarding financing arrangements, capital structure, senior management appointments and business operations.  The interests of the

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holders of the various classes of our common stock may not be compatible with the interests of other shareholders and directors, or with the strategic objectives of senior management of the Company.

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ITEM 1B.  UNRESOLVED STAFF COMMENTS

None.

ITEM 2.  PROPERTIES

Certain of our executive, finance, marketing, internal audit and legal functions are located in our corporate headquarters in Stamford, Connecticut.  Substantially all of our operations, including pricing, information technology and data solutions, risk management, supply, customer operations, accounting, billing and collections and certain human resources functions are located in Houston, Texas, where most of our employees currently work.  We also have customer care and various other staff located in Annapolis Junction, Maryland.

We lease all of our properties.  As of June 30, 2010, we believe 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, billing practices and employment matters 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.  (REMOVED AND RESERVED)

None.

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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 $0.01 per share.  As of August 31, 2010, there were 49 holders of record of our Class A Common Stock, 1 holder of record of our Class B Common Stock and 78 holders of record of our Class C 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, subject to the conditions and limitations set forth in various debt, supply and hedging agreements.  We are restricted in our ability to pay dividends by various provisions of agreements that govern the Commodity Supply Facility, the Fixed Rate Notes due 2014 and the Floating Rate Notes due 2011.  Refer to “Liquidity and Capital Resources” in Item 7 of this Annual Report for additional information regarding dividend restrictions and the agreements that govern the Commodity Supply Facility, the Fixed Rate Notes due 2014 and the Floating Rate Notes due 2011.

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 in order to finance the expansion of our business and for general corporate purposes.

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ITEM 6.  SELECTED FINANCIAL DATA

Adjusted EBITDA

Management believes that Adjusted EBITDA, which is not a financial measure recognized under U.S. GAAP, 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 that 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 and electricity 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 new 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, restricted stock units, 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 ratios and covenants in the agreements governing our Commodity Supply Facility is 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 the 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, including the following:

·                  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 consolidated financial statements, which are included elsewhere in this Annual Report.  The table includes a reconciliation from net income (loss) calculated 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 this section.

(1)          Sales of natural gas and electricity and cost of goods sold each include pass-through revenue, primarily representing transportation and distribution charges billed to customers on behalf of certain LDCs, of approximately $56.8 million, $68.3 million, $63.6 million and $54.5 million for the fiscal years ended June 30, 2010, 2009, 2008 and 2007, respectively.  Sales of natural gas and electricity also include fee income charged to customers, such as late payment fees, early termination fees and service shut-off fees of approximately $18.6 million, $22.4 million, $19.4 million and $17.1 million for the fiscal years ended June 30, 2010, 2009, 2008 and 2007, respectively.  Pass-through revenue and fee income were not material for fiscal years prior to 2007;

(2)          Interest expense includes interest and fees incurred in connection with debt instruments, supply facilities and hedging facilities.  Interest expense also includes non-cash amortization of deferred debt issuance costs and original issue discount of approximately $11.6 million, $10.3 million and $5.3 million for fiscal years 2010, 2009 and 2008, respectively.

(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 Floating Rate Notes due 2011 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.  Pursuant to the Restructuring, $158.8 million aggregate principal amount of Floating Rate Notes were exchanged for cash, common stock and $67.7 million aggregate principal amount of Fixed Rate Notes due 2014.

(5)          As of June 30, 2009, the Preferred Stock was recorded at its estimated redemption value outside of stockholders’ equity on the consolidated balance sheet because it was deemed to be redeemable at the option of the Preferred Investors.  As of June 30, 2009, the holders of Preferred Stock did not make an election to redeem the Preferred Stock.  In connection with the Restructuring, the Preferred Stock was converted to Class C Common Stock on September 22, 2009.

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

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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.