Exhibit 99.1

FINAL TRANSCRIPT

Conference Call Transcript

**MXE - Q2 2011 MXenergy Holdings Inc. Earnings Conference Call

Event Date/Time: Feb 17, 2011 / 07:00PM GMT

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CORPORATE PARTICIPANTS

Philip Mittleman

MXenergy Holdings Inc - Associate General Counsel

Jeffrey Mayer

MXenergy Holdings Inc. - President & CEO

Chaitu Parikh

MXenergy Holdings Inc. - EVP & CFO

CONFERENCE CALL PARTICIPANTS

Alan Shenyak

Vernal Capital

Ted Burdick

Soros - Analyst

PRESENTATION

Operator

Good day, ladies and gentlemen, and welcome to the Q2 2011 MXenergy Holdings Inc. Earnings Conference Call. My name is Madge, and I will be your operator for today. At this time all participants are in a listen-only mode. Later we will conduct a question-and-answer session. (Operator Instructions)

Operator

I would now like to turn the presentation over to your host for today's call, Mr. Philip Mittleman, Associate General Counsel. Please proceed.

Philip Mittleman - MXenergy Holdings Inc - Associate General Counsel

Thank you, Madge. Good afternoon, I am Philip Mittleman, Associate General Counsel of MXenergy Holdings Inc. Today, we'll be reviewing our financial results for the quarter ended December 31, 2010. During the call, MXenergy Holdings Inc. may also be referred to as MXenergy, MX, the Company, we, or us.

Before we begin, I would like to remind you that certain statements made during this conference call which are not based on historical facts may be deemed to be forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995.

Because these forward-looking statements involve known and unknown risks and uncertainties, there are important factors that could cause actual results, events or developments to differ materially from those expressed or implied by these forward-looking statements. Such factors include those risks described in our annual report on Form 10-K for the fiscal year ended June 30, 2010.

All information is current as of the date of this call, and the Company undertakes no duty to update this information. We will take questions at the end of the call. Due to SEC disclosure regulations, we will be limited to commenting on information that has already been made available to the public by the Company.

We will not be able to address events occurring after December 31, 2010, which have not been disclosed in the current Form 10-Q. I'm joined today by Jeffrey Mayer, our President and Chief Executive Officer and by Chaitu Parikh, our Executive Vice President and Chief Financial Officer. And now, I'll turn the call over to Jeff Mayer for an overview of our operating results.

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Jeffrey Mayer - MXenergy Holdings Inc. - President & CEO

Thank you, Phil, and, good afternoon, everyone. Today we are reviewing our results for the quarter and six months ended December 31, 2010. The quarter ended December 31, 2010 is the second quarter of our fiscal year ending June 30, 2011.

Second quarter results include the beginning of the winter heating season, which is the crucial operating period during our fiscal year for our natural gas business and for our business as a whole. I'm pleased to say that our winter heating season has gotten off to a good start with strong operating results for the month of December 2010, primarily driven by colder than normal weather in most of our markets.

We caution you, however, that the third quarter of our fiscal year is typically our strongest operating quarter for our natural gas business, and that our overall results of our entire fiscal year are heavily dependent upon a strong third quarter. Having said that, I'll note that I'm sure everybody is aware the weather has been very cold in most of our territories, which is always helpful.

That being said, our adjusted earnings before interest tax, depreciation and amortization, stock compensation, and unrealized gains or losses from risk management activities, which we refer to as adjusted EBITDA, were $22 million for the second quarter of fiscal year 2011, which was $1.2 million higher than the adjusted EBITDA of $20.8 million, which we earned in the same period last year. The increase in adjusted EBITDA stem from higher electricity gross profit, which was partially offset by higher operating expenses and slightly lower natural gas gross profit.

In our SEC filings, we describe the impacts of certain timing differences related to our natural gas inventory costing methodology, and a recognition of certain realized gains and losses from risk management activities that relate to inventories. These timing differences had a negative impact on natural gas gross profit for the second quarter and the first half of fiscal year 2011.

We expect these negative impacts to reverse as we record revenue during the remaining winter months. Excluding the impacts of these timing differences, adjusted EBITDA was $23 million for the second quarter, $3.8 million higher than the same period last year. Adjusted EBITDA was $15.1 million for the first half of fiscal year 2011, which was $2.2 million lower than our adjusted EBITDA of $17.3 million for the same period last year.

The decrease in adjusted EBITDA was primarily the result of lower natural gas gross profit and higher operating expenses, which were partially offset by higher electricity gross profit. Excluding the impacts of the aforementioned timing differences, adjusted EBITDA was $17.9 million for the first half of fiscal year 2011, which was relatively unchanged from the same period last year.

As previously reported, we are a service provider under a standard service offer program in Ohio, which we refer to as the SSO Program. Under the SSO Program for the 12-month period that ends on March 31, 2011, we will receive a NYMEX-referenced price, plus a price adjustment for natural gas delivered by LDC to its customers who are eligible to participate in this SSO Program.

Although we expect to deliver significant incremental volume of natural gas under the SSO Program, we also expect that our gross profit per MMBtu sold will be significantly lower than the gross profit we normally experience from our direct retail energy customers. Through nine months of the contractual term, our results under the SSO Program have been as we expected. The SSO Program in which we participate terminates on March 31, 2011.

For the first half of fiscal year 2011, our gross profit for the SSO Program has been negatively affected by the timing of fixed transportation costs associated with natural gas that has yet to be delivered to customers under the program.

Although these costs were recognized as cost of good sold when incurred, a portion of the related revenue will not be recorded until the natural gas is delivered during the remaining winter months through March 31.

Excluding the impact of all timing differences that have been described, we recognized higher gross profit associated with natural gas delivered to customers during the second quarter and the first half of fiscal year 2011, as compared with the same periods last year. Colder than normal weather in most of our markets was partially offset by lower volumes of natural gas delivered to customers.

Average natural gas RCEs declined 2% for the second quarter of fiscal year 2011 as compared with the previous quarter, and declined 6% for the first half of fiscal year 2011 as compared with the same period in the prior fiscal year. During the first half of fiscal year 2011, high residential RCEs were more than offset by lower small business and commercial RCEs, including several large commercial accounts, each of which represents the loss of several hundred RCEs.

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Since our gross profit per MMBtu of natural gas delivered to residential customers is significantly higher than that for commercial customers, this shift in our customer portfolio has resulted in an overall increase in our natural gas gross profit. Higher electricity gross profit for the second quarter and the first six months of fiscal year 2011 was primarily driven by higher volumes of electricity sold.

Average electricity RCEs increased more than 140% for the second quarter and the first six months of fiscal year 2011, compared with the same periods in the prior fiscal year.

Actual electricity RCEs as of December 31, 2010 include over 77,000 net customers added, as a result of our expansion into new electricity markets in Pennsylvania and Maryland over the past year. Lower gross profit per megawatt hour sold partially offset the impact of higher electricity volumes sold.

During the second half of fiscal year 2010 and the first half of fiscal year 2011, we have focused on growth in new as well as in some of our existing electricity markets where we have spotted opportunities. This growth has the beneficial impact of improving the seasonal cash flow associated with the electricity business segment and to reduce risks associated with commodity and geographic concentrations.

General and administrative operating expenses are significantly higher for the first half of fiscal year of 2011 compared to the prior year. We have increased our staff count in customer operations, information systems, electricity supply, and other areas to support actual customer growth in new and existing electricity markets, planned customer growth in natural gas and electricity markets, and the enhancement of our internal controls environment.

And I'll remind everybody that up until the restructuring in September of 2009, we had to hold back some of this infrastructure strength and support, and we have been making up for lost time. Historically, we have experienced a seasonal trend of lower customer additions during the months of December through February due to the impacts of the holiday season and of weather on our marketing activities. As such, we also tend to incur lower customer acquisition costs during this period.

This trend continued during the month of December 2010, which contributed to a 23% decrease in capitalized customer acquisition costs during the second quarter of fiscal year 2011, as compared with the previous quarter. Steady electricity customer growth over the 12 months ended December 31, 2010 was primarily due to expanded marketing activities.

Advertising and marketing expenses were more than 300% higher during the first half of fiscal year 2011, as compared with the same period in the prior fiscal year. Additionally, capitalized customer acquisition costs increased $8.3 million or 134% for the first six months of fiscal year 2011, as compared to the same period in the prior year. Our cost to acquire customers approximated $100 per RCE for the first six months of 2011, which was consistent with the cost to acquire customers during the fiscal year ended June 30, 2010.

And, here, also I'll note that the increase in the first half of fiscal year 2011 has to be considered in light of the fact that for pretty much all of the first quarter of fiscal year 2010, our marketing activities were restricted under the terms of our previous financing arrangements prior to the restructuring. In-contract attrition continued to trend higher to 31% for the 12 months ended December 31, 2010 from 26% for the 12 months ended June 30, 2010 and 27% for the 12 months ended September 30, 2010.

We believe that slightly higher attrition during periods of strong customer growth, such as the growth that we experienced in our electricity portfolio is consistent with our historical experience.

In addition, higher in-contract attrition for the 12 months ended December 31, 2010 was driven by competitive pressure in electricity markets, particularly new markets in Pennsylvania and Connecticut. Over the past 12 months, the number of competitors has increased significantly in these markets in part because of low prices and working capital requirements, and this has resulted in greater price-on-price competition.

We continue to work hard on stemming attrition, improving our customer communications, branding and loyalty programs, and in some cases, offering saver rates to loyal customers who contact us with lower competitive offers. During the first half of fiscal year 2011, we continued to develop marketing strategies for new markets that we consider to be strong opportunities for growth. In addition, we continue to look for opportunities to grow in our existing markets. Among other things, we have focused on building customer brand awareness and loyalty and enhancing the customer experience.

Initiatives to build brand awareness that we have undertaken include a specialized cable television channel available in the Northeast to subscribers to the Cablevision network, community events, such as coat drives, farmer's markets and food drives, and focusing on PR initiatives

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throughout the country. Initiatives to improve the customer experience include a savers club package of benefits for loyal customers, a savers card which is a debit card also for loyal customers, new retention programs, such as My Account for all but Texas customers thus far, and early renewal offers.

We believe that, as of December 31, 2010, we have sufficient liquidity under the commodity supply facility to meet these growth objectives. RBS Sempra has, as we have discussed in the past, indicated its intent to complete an orderly sale of its assets, including, but not limited to, the entity which provides our commodity supply facility.

Although we have received assurances from RBS Sempra that it will continue to fulfill its obligations under the commodity supply facility, we are actively exploring alternatives for potential new supply, credit, and hedging counter parties. I will now turn the call over to Chaitu Parikh for a more detailed discussion of our financial results and liquidity position. Chaitu?

Chaitu Parikh - MXenergy Holdings Inc. - EVP & CFO

Thank you, Jeff. We realized adjusted EBITDA of $22 million for the second quarter of fiscal year 2011, which was $1.2 million higher than the same period last year.

This was primarily due to higher electricity gross profit of $5.3 million, higher natural gas gross profit of $3.2 million, and was partially offset by $2.6 million net negative comparative impact of timing differences associated with natural gas inventories and related hedge settlements, lower natural gas fee revenue of $0.7 million and higher operating expenses of $4 million. Excluding the impact of certain natural gas gross profit timing differences between the comparative periods, adjusted EBITDA increased 20% from the prior year to $23 million for the quarter ended December 31, 2010.

Higher electricity gross profit and higher natural gas gross profit were partially offset by higher operating expenses. Adjusted EBITDA was $15.1 million for the first half of fiscal year 2011, which was $2.2 million lower than what we earned in the same period last year.

This is primarily due to lower gross profit from our natural gas customers of about $1 million, $4.2 million of net negative impact of timing differences associated with natural gas inventories and related hedge settlements, lower natural gas fee revenue of $1.4 million, and higher operating expenses of $5.1 million. This is partially offset by higher electricity gross profit of $9.5 million.

If we were to exclude the impact of certain natural gas gross profit timing differences between these comparative periods and certain non-recurring restructuring related expenses recorded during the first quarter of fiscal year 2010, adjusted EBITDA of $17.9 million for the first half of this fiscal year is relatively comparable to what we earned in the prior fiscal year.

Lower natural gas gross profit and higher operating expenses were offset by higher electricity gross profit this year. Our natural gas gross profit per MMBtu sold for the second quarter of fiscal year 2011 increased significantly from the immediately preceding quarter, due in part to the seasonal impact of spreading fixed transportation costs over more volumes sold. For the first half of fiscal year 2011, after excluding the previously referenced comparative period timing differences and the impact of the SSO Program, our natural gas gross profit per MMBtu sold remained consistent when compared to the same period last year.

As reported in our quarterly and annual filings, there are many factors that impact our natural gas gross profit, including timing differences related to our valuation of natural gas inventories and our recognition of realized gains and losses from risk management activities.

These timing differences had a net negative impact on our natural gas gross profit and gross profit per MMBtu sold for the second quarter and for the first half of fiscal year 2011, as compared with the same periods in the prior year.

Excluding the net impact of these timing differences, natural gas gross profit increased $2.5 million or 9% for the second quarter, and decreased $2.4 million or 6% for the first half of fiscal year 2011. As an expected result of certain provisions of the commodity supply facility during the quarter ended September 30, 2010, we experienced a more pronounced impact of a timing difference related to the recognition of certain fixed transportation capacity costs. As required by the commodity supply facility, we assigned certain storage inventory to RBS Sempra that we owned during the comparative quarter ended September 30, 2009.

In addition, we assigned capacity rights in certain markets to RBS Sempra during fiscal year 2010. Our inventory valuation methodology considers all direct costs incurred to acquire inventory, including a component of fixed transportation and capacity costs.

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Since we have lower storage volumes in fiscal year 2011, we have a lower amount of fixed transportation capacity costs deferred on our balance sheet and a greater amount of these costs have been expensed to cost of goods sold during the months leading up to the peak heating season. This has caused a reduction in our gross profit per MMBtu sold during these months. This had a pronounced negative impact on our natural gas gross profit during the first quarter of fiscal year 2011. We began to recover these costs by recording revenue during the second quarter of fiscal year 2011.  And we expect to continue to recover these costs by recording revenue during the remaining winter months as we deliver higher volumes of natural gas to our customers, which will effectively reduce the fixed transportation costs per MMBtu sold during those months.

For the first six months of fiscal year 2011, we recorded revenue associated with approximately 3.5 million MMBtus of natural gas delivered under the SSO Program. As we expected, gross profit per MMBtu sold has been lower under the SSO Program than what we experienced from our normal residential retail portfolio.

In addition, the timing differences related to transportation costs previously described further lowered our natural gas gross profit related to the SSO Program. If we were to exclude the impact of the SSO Program, our gross profit and gross profit per MMBtu sold would both have been higher for the second quarter of fiscal year 2011 compared to the same period last year. Similarly, our gross profit and gross profit per MMBtu for the first half of fiscal year 2011 would have equaled or surpassed amounts recorded during the same period last year.

Effective March 31, the SSO Program will terminate. We'll continue to evaluate these programs in the future and will participate if we believe we can generate an adequate return from them. Excluding timing differences and the impact of the SSO Program, we recorded higher natural gas gross profit during the second quarter and the first half of fiscal year 2011, due to the combined impact of higher gross profit per MMBtu sold and colder than normal temperatures in most of our natural gas markets.

These positive impacts were offset by lower volumes of natural gas sold to customers and lower fees earned from natural gas customers, which was related to the reduction in RCEs during fiscal year 2011. Electricity gross profit was 106% higher for the second quarter and 90% higher for the first half of the fiscal year 2011.

Significant increases in volumes sold for both periods, which resulted from growth in electricity customers served, were partially offset by lower gross profit per megawatt hours sold due in part to increased competition in certain existing and new electricity markets.

One thing I'd like to highlight is that over the last several weeks, as temperatures across much of the US dropped to well below normal, the ERCOT market experienced grid congestion, which caused prices to spike dramatically above normal for several hours. Our risk management program adequately addressed our supply needs during the period, and we do not believe our financial results will be materially impacted by these price spikes.

General and administrative expenses for the first quarter of last year include $2.2 million of compensation costs and professional fees that were incurred as a result of the restructuring. Excluding these restructuring related expenses, on an adjusted EBITDA basis, total operating expenses were approximately $4 million higher for the second quarter of fiscal year 2011, and were $7.3 million higher for the first half of fiscal year 2011 compared with the same period last year.

Excluding restructuring related costs, general and administrative expenses increased $2 million for the second quarter and increased $4 million for the first six months of fiscal year 2011, as compared with the same period last year. These increases were primarily due to higher employee compensation, billing, and other costs resulting from expanded operations to support our actual and planned growth in our customer base and enhancements to improve the effectiveness of our internal control environment.

During much of the prior year comparative period, we were restricted in our ability to hire employees and incur additional general and administrative costs in contemplation of the restructuring that was completed in September 2009. Advertising and marketing costs increased $1.3 million for the second quarter, and increased $2.4 million for the first half of fiscal year 2011.

Again, subsequent to the restructuring that was completed in 2009, we implemented various elements of a growth and marketing plan, which included strategic marketing initiatives in our current markets as well as incremental marketing expenses related to new markets, particularly new markets in Pennsylvania and Maryland.

As a result, during the first half of fiscal year 2011, we incurred marketing expenditures that reflected a return to more historical levels prior to the restructuring.

Reserves and discounts, which includes a provision of doubtful accounts related to accounts receivable in those markets where

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we bear direct credit risk from our customers and to a lesser extent, contractual discounts related to markets where the local utilities guarantee customer accounts receivable. The provision for doubtful accounts increased by $0.3 million for the second quarter and increased $0.1 million for the first half of fiscal year 2011. During the second quarter, we reported a $0.6 million provision related to delays in our internal budget billing true up process. As part of our remediation plan to address and resolve the material weakness identified at June 30, 2010, we continue to implement certain controls and procedures during the current fiscal year to address delays in the budget bill process. Excluding this special provision, the provision for doubtful accounts decreased during the second quarter and the first half of fiscal year 2011. This decrease is primarily due to the net affect of the following factors. Sales of natural gas and electricity in markets where customer accounts receivables are not guaranteed by LDCs decreased 15% during the first half of fiscal year 2011.

The credit environment has generally stabilized in many of our markets during the final nine months of fiscal year 2010 and the first half of fiscal year 2011.

By comparison, during the 2009 fiscal year and in the first quarter of fiscal year 2010, we experienced deterioration in the aging of our customer accounts receivable in certain of our larger markets in Georgia, Texas, and the northeastern US which resulted in charge-offs of customer accounts receivable and provisions for doubtful accounts that were higher than our historical levels.

And finally, our acquisition of Catalyst Natural Gas during the fiscal year 2009 contributed to a higher allowance and provision for doubtful accounts in our Georgia natural gas market during the quarter ended September 30, 2009. Contractual discounts associated with the LDC guarantees of customer accounts receivable increased by $0.4 million for the second quarter and increased $0.8 million for the first half of fiscal year 2011, due to significantly higher sales of natural gas and electricity within our LDC guaranteed markets.

The weighted average contractual discount rates in the current quarter were comparable to the rates for the same period in the prior fiscal year.

Depreciation and amortization increased $1.3 million for the second quarter and increased $1.3 million for the first half of fiscal year 2011, primarily due to amortization of customer acquisition costs resulting from higher additions to capitalized customer acquisition costs during fiscal year 2010 and the first half of fiscal year 2011 as compares with the prior year period.

Net interest expense decreased by $1 million for the second quarter and decreased $7.2 million for the first half of fiscal year 2011. The fiscal year 2011 decrease in interest expense is due to the following.

A 58% reduction in the aggregate principal balance of long-term debt outstanding as a result of the restructuring; generally lower fees associated with our current supply and hedging facility, as compared with our former facility; and, lower amortization of deferred debt issuance costs and original debt issue discounts.

Interest expense includes approximately $2.4 million and $4.6 million of non-cash interest charges for the second quarter and the first half of fiscal year 2011 respectively, which primarily relates to amortization of deferred financing costs and discounts recorded on issued debt. During the six months of fiscal year 2011, our cash and cash equivalence decreased by $1.9 million to a balance of $4.3 million at December 31, 2010.

Note that under the terms of our commodity supply facility, our operating cash is currently controlled by RBS Sempra. As of December 31, 2010, RBS Sempra held approximately $25 million of our cash. which is net against approximately $56 million we owe RBS Sempra for delivered commodity, settled hedges, and other financing costs. At December 31, 2010 we had approximately $23 million of cash collateral posted to support our obligations to various counter parties. This includes $9 million required to secure one year's interest payments to our bond holders, $6 million as security for obligations to various hedging, pipeline, transmission and transportation counter parties, and $5 million required for us to participate in the SSO Program.

In addition, we have issued $31 million in letters of credit under the commodity supply facility to support our ongoing credit needs. We have available liquidity of approximately $59 million under the commodity supply facility. This includes $45 million, which is the maximum credit available for cash advances, and $14 million which represents excess liquidity that can be used for additional letters of credit, commodity purchases, and other operating purposes.

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As of December 31, 2010 we are in compliance with the terms to the commodity supply facility and of our long-term debt instruments, and we believe we have sufficient availability under the supply facility to meet our liquidity needs for ongoing operations and our anticipated growth. This concludes our earnings commentary, and we would now like to open the call to questions.

Jeffrey Mayer  - MXenergy Holdings Inc. - President & CEO

Madge, we’ll take questions now.

QUESTION AND ANSWER

Operator

Thank you, sir.

(Operator Instructions)

And your first question comes from the line of [Alan Shenyak] from [Vernal Capital]. Please proceed.

Alan Shenyak  - Vernal Capital

Good afternoon, guys. How are you?

Jeffrey Mayer  - MXenergy Holdings Inc. - President & CEO

Doing good.

Chaitu Parikh  - MXenergy Holdings Inc. - EVP & CFO

Good, how are you, [Carling]?

Alan Shenyak  - Vernal Capital

Doing good, thanks for taking the question. Can you just remind me — this is more of an accounting question — I just forget, and I don’t recall when you reclassified the customer acquisition costs.

Chaitu Parikh  - MXenergy Holdings Inc. - EVP & CFO

We reclassified them with the June 30, 2010 10-K is when we reclassified them. So, they moved from an investing activity to an operating activity line. We just moved it up.

Alan Shenyak  - Vernal Capital

Got you. Does that impact your ability to depreciate those costs or capitalize those costs over time?

Chaitu Parikh  - MXenergy Holdings Inc. - EVP & CFO

No, it does not.

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Alan Shenyak  - Vernal Capital

Oh, okay. And then, with respect to the rolling of the SSO Program, and I think you mentioned March 31, 2011, that’s about 3 million Btus of the first six months of this fiscal year. Is that an accurate estimate?

Chaitu Parikh  - MXenergy Holdings Inc. - EVP & CFO

Yes. Yes, 3 million MMBtus. I think that’s correct.

Alan Shenyak  - Vernal Capital

Yes, that’s like 15%. Okay.

Jeffrey Mayer  - MXenergy Holdings Inc. - President & CEO

Just to clarify for our listeners, I think we made this clear, we don’t include that volume in our RCE count, of course. This is a separate category, which is a negotiated deal with the utility.

Chaitu Parikh  - MXenergy Holdings Inc. - EVP & CFO

Right, that’s more of a wholesale type contract, so it’s not tied to actual customers that we have marketed to.

Alan Shenyak  - Vernal Capital

Oh, okay, that’s helpful. So of the 20.6 million MMBtus sold for the first six months of the year, those — it was excluded from that figure?

Chaitu Parikh  - MXenergy Holdings Inc. - EVP & CFO

No, it was included in that figure, but when we talk about RCEs, we don’t include. Typically RCEs is just a conversion of volume that our customers use, and we are not including the volume associated with that SSO program in our RCE count.

Alan Shenyak  - Vernal Capital

And can you just remind me if I were to say the beginning of the period you had 634,000 RCEs, based upon the disclosure of your customer renewal percentage and your in-contract attrition percentage, can I build a bridge that said, beginning balance of X, less your contract non-renewals, less your natural customer attrition, and then back into the implied number of your new customers? Or, am I missing some information in order to do that?

Chaitu Parikh  - MXenergy Holdings Inc. - EVP & CFO

You can do that analysis. The one piece that you’re missing is that when we calculate our attrition, it’s calculated on a per customer basis, actual customers, not RCEs. And the only disclosure we really put in the documents are RCEs.

So there is a little bit of disconnect there. And so, to the extent that we’re losing a large commercial account that represents several hundred RCEs, you’ll see a larger decline in the RCE number, and the customer count, you’re not going to see as much of a decline. So, that’s the one thing to keep in mind as you do that analysis.

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But I can tell you that the actual ratio of customers to RCEs hasn’t really changed significantly quarter to quarter, at least over the last couple quarters. So, you should be able to do that analysis and get a reasonable answer.

Alan Shenyak  - Vernal Capital

And can you just refresh my memory, the difference between a customer renewal and an in-contract attrition?

Chaitu Parikh  - MXenergy Holdings Inc. - EVP & CFO

Customer renewal is a customer that has gone through to the end of their fixed term contract. So if you have somebody on a one-year fixed price contract, and we have 92% renewal rate, then 92% of those customers who stayed with us throughout that full term of their contract, renewed onto whatever the new offer was.

And in-contract attrition represents those customers that left during the term of that contract, and also includes all of our variable customers on month-to-month contracts that happen to leave.

Alan Shenyak  - Vernal Capital

And you get comfortable with that number, has that number been trending down over time? Is it fairly volatile, and what are the largest reasons? Like, the top two reasons why someone in contract would drive that attrition number.

Jeffrey Mayer  - MXenergy Holdings Inc. - President & CEO

Well, first of all, the renewal number has been stable to slightly higher over the years. The in-contract attrition number, as we indicated, is slightly higher. There are a number of reasons, and I’ll mention the top two or three.

One is the churn that we see in all retail consumer markets that comes from customers moving or dying. That varies by market and by customer class. As you know, we serve a lot of single-family homes, so it’s a little less than you see in apartment complexes or houses, but nevertheless it’s a fairly high number.

The second most important category of churn is credit drops. These may be accounts that we drop in markets that we bill or in markets where the utility guarantees the receivable. The utility has, which accounts for, I believe a little over — around 50% of our market — of our RCEs. Where that’s the case, the utility generally reserves the right to cancel the customer agreement in the event that the customer is late in a payment of a certain period of time.

So if a customer misses a payment of a $1.98 in the summertime for natural gas, over a period of 60 days, the utility can take that account back and normally does in those markets where the utility is guaranteeing the receivable. So, there are your top two categories of attrition.

On top of that there are a number of categories that the utility notifies us of as well as customers that sign onto other marketers, either because they don’t know or remember that they’re signed up with is, which is often the case, or because of price-on-price competition, which is actually one of the smallest causes of attrition.

Alan Shenyak  - Vernal Capital

And one last question. With respect to your customer acquisition costs on a per account basis for the quarter, can you just walk me through the basic economics in terms of what your typical breakeven point in return on investment is? For that, I assume at $24 to $25 or $20 of gross profit per megawatt hour for an RCE that consumes 10 megawatt hours a year, that’s a pretty attractive return profile.

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Chaitu Parikh  - MXenergy Holdings Inc. - EVP & CFO

That’s right. It is a pretty attractive return profile. The premise that we follow is we try and ensure that we’re generating at least our gross profit back, at least enough gross profits to cover our acquisition costs in the first year. So, that’s sort of the general rule of thumb that we like to follow.

And so, depending on what that gross profit looks like, it obviously varies based on programs and utilities and so on. That’s what guides us to how much we feel like we can spend and also to what we think we should be charging in the marketplace.

Alan Shenyak  - Vernal Capital

Okay. Thank you, very much.

Jeffrey Mayer  - MXenergy Holdings Inc. - President & CEO

Thank you.

Chaitu Parikh  - MXenergy Holdings Inc. - EVP & CFO

Thank you.

Operator

(Operator Instructions)

And your next question comes from the line of Ted Burdick from Soros. Please proceed.

Ted Burdick  - Soros - Analyst

Not to beat a dead horse, but just to follow up on the questions about attrition, how much of the uptick in attrition is a function of electricity being a bigger part of the business? Is there a higher churn in the — or higher attrition in the electricity business?

Jeffrey Mayer  - MXenergy Holdings Inc. - President & CEO

The answer is yes. And we think there are a couple reasons for that, although it may be a little early in the growth of this business to be entirely certain. So, it’s something we’re watching closely.

One reason is that we’ve historically noticed that when there are new markets which are experiencing a good deal of growth that attrition can kick up, probably because there’s a lot of competition, a lot of publicity surrounding the new market, and a lot of customer — cognitive dissonance, for want of a better term. Just customers experiencing a new option that they’re not familiar with and questioning their decisions.

The second factor which we feel has contributed to this in recent months, although, again, I think it’s probably too early to tell, and I said this in my remarks is the fact there is a great number of new entrants in these electricity markets. Some of the new entrants in the electricity markets that we haven’t noticed in the natural gas markets.

And it’s unclear why, but one thing is clear and that is that their cost of — their working capital requirements are a good deal lower because costs have been at pretty much historic lows, at least for the period since the — since retail deregulation got started beginning in the late ‘90s.

So the result of those new market entrants is that there is a good deal of marketing, and in a retail market where customers frequently only see our name as a line item on the utility bill, one often doesn’t have the loyalty that one might have in other businesses.

This is one reason I alluded to our customer loyalty programs that we have been working on in those areas over the past year, including the debit card, the savers club, the My Account, the television station on Cablevision, and other cost effective efforts to increase customer loyalty and awareness of who we are and to stem attrition.

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It’s a little too early to report on any impact from that, but this is — that’s the way we look at the market, and that’s the way we’re handling it.

Ted Burdick  - Soros - Analyst

Just over to the SSO Program, could you talk a little bit about — you mentioned that this one’s running off. And if they meet performance hurdles for future transactions, you’d do it again. The question is, what sort of performance hurdles do you use to assess it, and did the program you just are finishing right now meet them as expected? And again, are there more to come?

Chaitu Parikh  - MXenergy Holdings Inc. - EVP & CFO

Well, the first part I’d say is that we do say that through the end of December, it is meeting our expectations with one quarter left to report on through the end of March. So it did meet our expectations for this year.

We really — each program is a little different. As you know, these are auctions that are being held by some of the utilities in Ohio, and each program is a little bit different. So we have to look at what are the requirements, first and foremost for us, what are the capital requirements that are required? I mentioned that we have some $5 million that’s posted with the utilities to support this program.

So that’s a key metric for us, and we would look at what’s our best place to deploy the capital that we have. If we can participate in one of these programs, and it’s a good return for us, then we would look at that. And if it’s better for us to spend that capital on new customers, we’ll look to do that.

Ted Burdick  - Soros - Analyst

And speaking of new customers, obviously the electricity customers, the electricity percentage has increased significantly over the last 18 months since the restructuring. What is your target rate or balance between those two businesses over the next 18 months?

Jeffrey Mayer  - MXenergy Holdings Inc. - President & CEO

Well, clearly we can’t give you forward projections, but I think we say in — or we said earlier this afternoon that we do like to balance our book. We found over the years there’s a benefit to diversification of our risk among commodities, among markets, among customer contracts versus fixed versus floating, among geographic territories and so forth.

And this is an example of where I think it’s fair to say that this growth helps to improve the seasonality of our cash flows as well as relieve some of the concentration risk of being in one commodity and one territory. So, it definitely feels better right now, but I can’t tell you that we have a goal in mind. And if we did have a goal in mind, I couldn’t tell you about it anyway.

Ted Burdick  - Soros - Analyst

Understood. And last question, and again I’m not asking for specific projections, but certainly the increase in operating expenses, and Jeff noted this is a little bit of a catch-up for deferred expenses that — or not deferred expenses, but expenses that were not incurred during the restructuring process, a little bit of catch-up.

Is it fair to say that the operating base of the business has been expanded to such that those types of increases won’t be necessary in the next growth phase, or is this level of increase in operating costs going to be — is going to continue as the company continues to grow and seek new customers?

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Chaitu Parikh  - MXenergy Holdings Inc. - EVP & CFO

Yes, to a certain extent the costs — there is a relationship between the number of customers we’re serving and the number of markets we’re in and the costs that we incur. So if we are continuing to expand into new markets, then you should see a slight increase in cost. But as a general matter, I’d say that we have increased the staff count, and we feel like we have a full complement to run the business that we have today.

Ted Burdick  - Soros - Analyst

That’s very helpful. Last question. Any new territories that you guys are targeting? Are you more targeting your efforts on existing territories, either states that are thinking about deregulating and will be virgin for everyone, or just new territories for you?

Jeffrey Mayer  - MXenergy Holdings Inc. - President & CEO

Well, we can’t really advise you on new territories, but you can be assured we’re always looking at new opportunities. The history of our company is to — and the philosophy of our business has been to build a platform for growth, and we feel we’ve done a good job of giving ourselves the flexibility of being able to move into new territories when opportunities have presented themselves.

As I think we’ve said in the past, when we go into a new territory, we evaluate a number of factors, and just because new territory is opening for business or competitive supply doesn’t mean we’ll automatically jump in. We’re very cautious and careful about not placing undue burdens on our infrastructure. But we are poised for growth.

Ted Burdick  - Soros - Analyst

Thank you.

Jeffrey Mayer  - MXenergy Holdings Inc. - President & CEO

Thank you.

Operator

And your next question is a follow-up question from Alan Shenyak. Please proceed.

Alan Shenyak  - Vernal Capital

Hey, guys, just a quick follow-up on some of your comments in ERCOT market. Has your business and the risk management been impacted at all by the transition to a nodal market in ERCOT?

Jeffrey Mayer  - MXenergy Holdings Inc. - President & CEO

That’s a good question, and the answer is no. It’s probably still too early to tell. That market is still evolving, and I don’t think we’ve seen a forward market develop yet with any depth or liquidity. And again, I’ll repeat what I said before in another context. It’s the history of this business to be very conservative about these things.

And so we take a fairly cautious view of all of these risks, in particular new ones that are unquantifiable at this point. But it hasn’t has an impact one way or the other. It’s neither adverse, nor is it an opportunity as yet.

Alan Shenyak  - Vernal Capital

And just opportunistically considering that the 13.25% notes are callable in August of 2011, can you sort of shed some light as to how you’re thinking about those, considering that the capital markets appear to be pretty robust? And company’s that are leveraged 1.3 times typically don’t require 13.25% cost to capital — at least we hope not.

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Chaitu Parikh  - MXenergy Holdings Inc. - EVP & CFO

Yes.

Jeffrey Mayer  - MXenergy Holdings Inc. - President & CEO

The answer is no. We can’t share our thoughts. But, we also subscribe to the Wall Street Journal.

Alan Shenyak  - Vernal Capital

And just housekeeping-wise, fully diluted shares outstanding, what’s the real right number?

Chaitu Parikh  - MXenergy Holdings Inc. - EVP & CFO

Fully diluted — I don’t have it right at my fingertips, but it’s approximately 57 million.

Alan Shenyak  - Vernal Capital

Okay, great. Thanks very much.

Jeffrey Mayer  - MXenergy Holdings Inc. - President & CEO

Thank you, (inaudible).

Operator

And you have no more questions at this time, sir.

Jeffrey Mayer  - MXenergy Holdings Inc. - President & CEO

Madge, you want to repeat the instructions again?

Operator

(Operator Instructions)

Jeffrey Mayer  - MXenergy Holdings Inc. - President & CEO

Okay, well, hearing none, that doesn’t sound like you have any questions, Madge?

Operator

No, sir, you have no questions at this time.

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Jeffrey Mayer  - MXenergy Holdings Inc. - President & CEO

All right. Phil?

Philip Mittleman  - MXenergy Holdings Inc - Associate General Counsel

All right, if there are no further questions, I want to thank all of you for joining us today. A replay of this conference call will be available starting this evening and for the next 30 days at the investor relations link at www.mxholdings.com. Additionally, a transcript of today’s teleconference will be made available within the next seven days via the investor relations link at www.mxholdings.com.

We appreciate your continued interest in MXenergy, and look forward to having you on future calls with us.

Jeffrey Mayer  - MXenergy Holdings Inc. - President & CEO

Thank you very much, folks. We appreciate your continued support. We’ll see you next quarter.

Operator

Thank you for participating in today’s conference. This concludes the presentation, and you may now disconnect. Have a great afternoon.

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