Exhibit 99.1

FINAL TRANSCRIPT

**MXE - Q1 2011 MXenergy Earnings Conference Call

Event Date/Time: Nov 17, 2010 / 09:00PM GMT

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CORPORATE PARTICIPANTS

Philip Mittleman

MXenergy - Associate General Counsel

Jeffrey Mayer

MXenergy - President, CEO

Chaitu Parikh

MXenergy - EVP, CFO

CONFERENCE CALL PARTICIPANTS

Ted Burdick

Camulos Capital - Analyst

PRESENTATION

Operator

Good day, ladies and gentlemen, and welcome to the First Quarter 2011 MXenergy Earnings Conference Call. My name is Jeremy, and I’ll be your operator for today. At this time, all participants are in listen-only mode. Later we will conduct a question and answer session.

(Operator Instructions)

I would now like to turn the conference over to your host for today, Mr. Philip Mittleman, Associate General Counsel for MXenergy. Please proceed, sir.

Philip Mittleman - MXenergy - Associate General Counsel

Thank you, Jeremy, and good afternoon. I’m Philip Mittleman, Associate General Counsel of MXenergy Holdings, Inc. Today we’ll be reviewing our financial results for the quarter ended September 30, 2010. During the call, MXenergy Holdings, Inc. may also be referred to as “MXenergy”, “MX”, “the company”, “we”, or “us”.

Before we begin, I’d 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’s already been made available to the public by the company. We will not be able to address events occurring after September 30, 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.

Jeffrey Mayer - MXenergy - President, CEO

Thank you, Phil, and good afternoon, everyone. Today we are reviewing our results for the quarter ended September 30, 2010, which is the first quarter of our fiscal year 2011. Although the first quarter of our fiscal year tends to be the strongest quarter for electricity operations, it is typically our weakest quarter overall, due to the size of our natural gas portfolio in relation to our total business. Our natural gas customer base has significantly lower consumption over the summer months.

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, was a loss of $6.9 million for the first quarter of fiscal year 2011, $3.3 million higher than our loss of $3.6 million for the same period last year. The reduction in Adjusted EBITDA stemmed from lower natural gas gross profit and higher operating expenses, which were partially offset by higher electricity gross profit.

Higher electricity gross profit for the first quarter of fiscal year 2011 was primarily driven by higher volumes sold. Average electricity RCEs for the first quarter of fiscal year 2011 increased 14% from the prior quarter and increased 139% from the same period in the prior fiscal year. Lower gross profit per megawatt-hour sold partially offset the impact of higher volumes sold.

Since the completion of our debt and equity restructuring in September 2009, we have focused on growth in many of our traditional electricity markets, in order to improve the seasonal cash flow associated with the electricity business segment and to reduce risks associated with commodity and geographic concentrations. In addition, actual electricity RCEs as of September 30, 2010 include over 55,000 customers added as a result of our expansion into new electricity markets in Pennsylvania and Maryland during the nine months ended September 30, 2010.

We are currently evaluating marketing strategies for certain new electricity markets that we see as strong opportunities for growth. We will continue to look for opportunities to grow in our existing markets, identify potential new territories to enter, and evaluate acquisition opportunities for customer portfolios that are consistent with our overall business objectives. We believe that, as of September 30, 2010, we have sufficient liquidity under the Commodity Supply Facility to meet these growth objectives.

Lower natural gas gross profit was due partly to lower volume of natural gas sold and partly to changes in the timing of recognition of certain fixed transportation and capacity charges that were necessitated by certain provisions of our Commodity Supply Facility with RBS Sempra. Average natural gas RCEs for the first quarter of fiscal 2011 increased 2% from the prior quarter, but declined 8% from the same period in the prior fiscal year.

Our total customer base increased 28,000 RCEs, or 5%, during the first quarter of fiscal year 2011 to 634,000 RCEs at September 30, 2010. During the quarter, we experienced growth of 3% in natural gas RCEs and 9% in electricity RCEs. Our total customer base increased 87,000 RCEs, or 16%, during the 12-month period ended September 30, 2010. During that period, growth of 145% in electricity RCEs was partially offset by a decline of 5% in natural gas RCEs.

Steady electricity customer growth over the nine months ended September 30, 2010 and more recent natural gas customer growth during fiscal year 2011 were due to expanded marketing activities. Advertising and marketing expenses were more than 300% higher during the first quarter of fiscal year 2011, as compared with the same period in the prior fiscal year. And you’ll recall, in the prior fiscal year, we were operating under severe financial constraints imposed by our banks and our prior credit facilities.

Additionally, capitalized customer acquisition costs increased $5.8 million, or 250%, for the first quarter 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 quarter ended September 30, 2010, which was consistent with the cost to acquire customers during the fiscal year ended June 30, 2010.

In-contract attrition trended slightly higher, from 25% for the 12 months ended March 31, 2010, to 26% for the 12 months ended June 30, 2010, and to 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 over the same period, is consistent with our historical experience.

The second and third quarters of our fiscal year are the peak heating season in our markets, and, therefore, are also the peak revenue periods for our natural gas business. The majority of our operating results for all of fiscal year 2011 will therefore be recognized during the six months ending March 31, 2011.

With this in mind, we would like to remind our investors that there are many factors that can have a significant impact on the natural gas gross profit that we recognize. For instance, and this is just a partial list — we disclosed quite a few risk factors in our annual report, but we wish to draw attention to a few of those —

The contracted prices we charge for natural gas delivered to our customers are subject to competitive pressures in our markets. Although we can control our contract prices, the growth of our business depends upon our ability to offer attractive pricing to prospective customers.

Volatility in the price we pay for natural gas is subject to a number of factors that can affect supply and demand for natural gas in specific markets or across all of our markets. Such factors, which are not within our control, can cause significant swings in our gross profit earned.

The volume of gas consumed by our customers is greatly impacted by weather, economic conditions, or other factors that we also cannot control. To be conservative, we rely upon the historic load profiles of our customers.

The cost, timing, and volume of natural gas added to and removed from storage inventory and the impact of our related hedging activities can also have a significant impact on overall results. Our ability to effectively manage such activity has been and always will be essential to our success.

The impact of volatile natural gas market prices varies greatly depending on the period of time in which price changes occur during our fiscal year. Although operating results for a full 12-month period should not be materially impacted by such price changes due to our commodity hedging and contract pricing strategies, commodity price movements can have a material short-term impact on quarterly operating results.

As we 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 receive a NYMEX reference price plus a price adjustment for natural gas delivered by the LDC to its customers who are eligible to participate in the 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.

A final note — Royal Bank of Scotland Group, which is the parent company of our supply and hedging counterparty, RBS Sempra, previous announced that it intends to divest its interest in RBS Sempra. To date, no transaction has been announced by Royal Bank of Scotland that would have any impact on our relationship with RBS Sempra or our business in general. RBS Sempra has affirmed its commitment to provide service to us under the Commodity Supply Facility.

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 - EVP, CFO

Thank you, Jeff. For the first quarter of fiscal year 2011, our Adjusted EBITDA was a loss of $6.9 million, which was $3.3 million, or 92% higher than the loss in the same period last year.

This is primarily due to the following items — a $1.6 million negative impact of timing differences associated with natural gas inventory and related hedge settlements; lower natural gas fee revenue of approximately $0.8 million; changes in the timing of recognition of certain fixed transportation and capacity costs, which resulted in higher cost of goods sold for natural gas during the quarter; and higher operating expenses of $1.1 million.

These negative impacts were partially offset by a $4.2 million increase in electricity gross profit. This increase was primarily due to higher average electricity customers served during the first quarter of fiscal year 2011, which was offset by lower gross profit per megawatt-hour sold.

Excluding the impact of certain natural gas gross profit timing differences between the comparative periods and certain non-recurring restructuring-related expenses incurred during the first quarter of last year, our Adjusted EBITDA loss increased to a loss of $5 million for the quarter ended September 30, 2010, as compared with a $1.1 million loss for the same period in the prior fiscal year. Lower natural gas gross profit and higher operating expenses were partially offset by higher electricity gross profit.

As Jeff previously noted, there are many factors that impact our natural gas gross profit. Certain impacts, recognized during one or more reporting quarters, when we are accumulating natural gas supply, will reverse during a subsequent reporting quarter, when natural gas inventory is delivered to customers.

Traditionally, we experience timing differences associated with valuation and hedging of natural gas inventories, which include — realized gains or losses from risk management activities recognized in cost of goods sold during a reporting period that directly relates to natural gas inventories not yet sold to customers as of the period end reporting date; and changes in the market prices of natural gas that result in adjustments to cost of goods sold during a reporting period due to a valuation of natural gas inventories not yet sold to customers as of the period end reporting date.

In addition to the timing differences related to valuation and hedging of natural gas inventory, we experienced a more pronounced impact of a timing difference related to the recognition of certain fixed transportation and capacity costs this year. This is an expected result of certain provisions of a Commodity Supply Facility during the quarter ended September 30, 2010. As required by the supply facility, we sold certain storage inventory to RBS Sempra that we owned during the comparative quarter ended September 30, 2009. In addition, we assigned capacity rights and 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. Since we have lower storage volumes in fiscal year 2011, we have a lower amount of fixed transportation and capacity costs deferred in our balance sheet, and a greater amount of these costs are expense to cost of goods sold during the months leading up to the peak heating season. This reduces our gross profit per MMBTU sold during these months.

We expect to recover these costs by recording revenue during the upcoming winter months, as we deliver higher volumes of natural gas to our customers. This will effectively reduce the fixed transportation cost per MMBTU sold during those months.

Each of these timing differences had a negative impact on our natural gas gross profit and gross profit per MMBTU sold for the first quarter of fiscal year 2011, as compared with the same period in the prior fiscal year. The following factors also reduced our natural gas gross profit for the current period.

First, during the quarter ended September 30, 2010, we recorded revenue associated with approximately half a million MMBTUs of natural gas consumed by customers in connection with the SSO Program. In addition to the lower gross profit per MMBTU

expected under the SSO Program, we also experienced the same effect of proportionately higher transportation and capacity costs in cost of goods sold for the SSO Program, as we experienced for many of our other natural gas markets.

Second, excluding the impact of the SSO Program, we delivered approximately 19% less volume of natural gas to our customers due to fewer average RCEs served during the period.

And third, we recorded $0.8 million less of fees earned from natural gas customers as a result of our serving fewer natural gas customers in markets where we are responsible for the billing and fees associated with customer delinquencies.

Electricity gross profit was 75% higher for the first quarter of fiscal year 2011, as a 130% increase in volume sold, which resulted from growth in electricity customers served, was partially offset by a 24% decrease in gross profit per megawatt hour sold, due to our pricing strategy to achieve growth in existing and new electricity markets.

On an Adjusted EBITDA basis, and excluding certain restructuring-related expenses incurred during the first quarter of last year, total operating expenses were approximately $3.3 million, or 22% higher for the quarter ended September 30, 2010, as compared with the same period in the prior year. 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 direct result of the restructuring. Excluding these restructuring-related costs, general and administrative expenses increased $2 million, or 16% for the current quarter, primarily due to higher employee compensation, billing, and other costs resulting from expanded operations to support actual and planned growth in our customer base.

Advertising and marketing costs increased $1.1 million for the first quarter of fiscal year 2011. Subsequent to our restructuring that was completed in September, 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 markets in Pennsylvania and Maryland. As a result, during the quarter ended September 30, 2010, we incurred marketing expenditures that reflected a return to historical levels prior to the restructuring.

Reserves and discounts include a provision for doubtful accounts related to accounts receivable in those markets where 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 decreased by $0.2 million, or 13%, for the current quarter, as compared with the prior fiscal year, which reflects the net effect of the following factors —

Sales of natural gas and electricity in markets where customer accounts receivable are not guaranteed by LDCs decreased 16% during the current quarter. Credit environments generally stabilized in many of our markets during the final nine months of fiscal year 2010 and the first quarter of fiscal year 2011. By comparison, during the fiscal year 2009 and in the first quarter of fiscal year 2010, we experienced a deterioration in the aging of our customer accounts receivable in certain of our larger markets in Georgia, Texas, and the northeastern United States, which resulted in charge-offs of customer accounts receivable and provisions for doubtful accounts that were higher than our historical levels.

And our acquisition of Catalyst Natural Gas during fiscal year 2009 contributed to higher allowance and provision for doubtful accounts in our Georgia natural gas market during the quarter ended September 30, 2009.

Contractual discounts associated with LDC guarantees of customer accounts receivable increased by $0.4 million for the current quarter due to significantly higher sales of natural gas and electricity within our LDC guaranteed markets. The weighted average contractual discount rates for the current quarter were comparable to the rates for the same period in the prior fiscal year.

Depreciation and amortization was relatively unchanged for the current quarter. Higher amortization of customer acquisition costs resulting from higher additions to capitalize customer acquisition costs during the 2010 fiscal year and the first quarter of fiscal year 2011, as compared with the comparable prior year periods, were offset by lower depreciation and amortization

expense associated with software, fixed assets, and customers acquired in connection with a 2006 purchase acquisition, which were fully depreciated or amortized as of August 2009.

Net interest expense decreased $6.2 million, or 48%, to $6.7 million for the current quarter. Note that this includes approximately $2.4 million of non-cash interest charges, which primarily relates to amortization of deferred financing costs and discounts recorded on issued debt.

The fiscal year 2011 decrease in interest expense is primarily due to — 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 facilities; and lower amortization of deferred debt issuance costs and original debt issue discounts.

During the first quarter of fiscal year 2011, our cash and cash equivalents increased $1.7 million to a balance of $7.9 million at the end of the quarter. Cash was used in or provided by the following material operating, investing, and financing activities during the period — $3.7 million of cash was provided by operating activities during the quarter; $0.9 million of cash was used for investing activities, primarily for acquisition of fixed assets; and $1.1 million of cash was used for financing activities, which resulted from our payment of taxes associated with common stock issued to certain senior officers.

Under the terms of our Commodity Supply Facility, our operating cash is currently controlled by RBS Sempra. Cash is released weekly by RBS Sempra to cover our ongoing operating cash requirements. The facility also includes provisions that allow for net settlement of amounts due from and due to RBS Sempra. At September 30, 2010, we have cash in excess of amounts owing to RBS Sempra for settled hedges and delivered commodity of approximately $13 million.

We are carrying approximately $16 million less natural gas inventories on our balance sheet as of September 30, 2010 than we carried at September 30, 2009, due to the structure of the Commodity Supply Facility. In addition, our natural gas inventories do not include any supply necessary to serve the needs of customers under the SSO Program. We will purchase these volumes of natural gas in future periods as they are delivered to the utilities to serve our customers during the winter months.

At September 30, 2010, we had approximately $23 million of cash collateral posted to support our obligations to various counterparties. This includes $9 million required to secure future interest payments to the bond holders, $8 million as security for obligations to various hedging, pipeline, transmission, and transportation counterparties, and $5 million required for us to participate in the SSO Program. In addition, as of September 30, 2010, we have issued $34 million in letters of credit under the Commodity Supply Facility to support our ongoing credit needs.

After accounting for the letters of credit, we have available liquidity of approximately $40 million under the Commodity Supply Facility, of which $13 million represents net cash due to us from RBS Sempra. As of September 30, 2010, we are in compliance with the terms of the Commodity Supply Facility and of our long-term debt instruments, and we believe we have sufficient availability under the facility to meet our liquidity needs for ongoing operations and anticipated growth.

This concludes our earnings commentary, and we’d now like to open the call to questions.

QUESTIONS AND ANSWERS

Operator

(Operator Instructions). Our first question comes from Ted Burdick. Please proceed.

Ted Burdick - Camulos Capital - Analyst

Good afternoon. I was wondering if you could talk a little bit more about the electricity ads. I have two questions. One, you highlighted the growth in the new markets in Pennsylvania and Maryland. Do you think that level of growth is sustainable in the existing-type markets as opposed to finding new markets to go into?

And then, the second question on the customer account was, you just mentioned that there’s a higher churn during this period of higher customer growth, and just wondering why those two are related.

Jeffrey Mayer - MXenergy - President, CEO

On your first question, Ted, note that our growth overall in electricity in the past year was not limited to those two new markets. In fact, we grew quite a bit in our existing markets as well. There’s no doubt that new markets offer an opportunity. I can’t give you any forward-looking projections on future growth in those markets or other markets, but I think you can be assured that we continue to look at our existing markets for growth, and, as I mentioned, we are evaluating some additional markets out there that are opening up in a number of places, or that have been open and which we believe offer opportunities for us, which we haven’t pursued before. For example, there are a couple markets where we have gas customers and see an opportunity to cross-market electricity to those same customers.

Ted Burdick - Camulos Capital - Analyst

So would you say that the opportunity is balanced between new markets and existing? Or one over the other?

Jeffrey Mayer - MXenergy - President, CEO

I don’t think I’m projecting one way or the other. I think it’s fair to say that it’s going to be a combination of both. As we add markets, I think it’s fair to say most of our growth will come from existing markets. Bear in mind, electricity is a relatively new business for us, and we only have limited markets to choose from. So the new markets offer a great deal of growth opportunity. But I think, looking down the road, as we are in more markets, it’s likely you’ll see most of the growth come from those existing markets.

Ted Burdick - Camulos Capital - Analyst

Okay. And what about the higher churn associated with a higher growth rate and customers? Why are the two related?

Chaitu Parikh - MXenergy - EVP, CFO

Ted, what we experience is that, when we are adding a large number of new customers during any period, we tend to see a slight increase in attrition immediately after bringing those customers on for service. And then, over a period of time, that attrition sort of normalizes over a longer period of time. So over the last several quarters, as we’ve been adding a significant number of customers, we’ve seen that there is an effect of a slight increase in our attrition rate.

Ted Burdick - Camulos Capital - Analyst

Okay. And, next, if we could talk a little bit about the gross margin on the natural gas. And I appreciate you went at length — describe the different factors that went into it. But could you sort of particularly quantify — and again, I apologize if you said it before — this one effect that you described as related to the commodity agreements having the storage effect on gross margin.

And also, I guess, the other question I would have is, has it been a benefit in previous quarters, i.e. the third and fourth quarter of fiscal 2010?

Chaitu Parikh - MXenergy - EVP, CFO

We can’t really quantify the amount, because we haven’t really disclosed what that amount is. But it definitely had an impact, and so we had tried to explain what that impact is. It is a new phenomenon for us this quarter, and, to probably a lesser extent, in the June quarter as well.

What’s causing this to occur is, under the facility with Sempra, because we are now assigning our storage assets over to Sempra to manage, we’re just carrying less storage at the end of each reporting period on our balance sheet. And as we incur these fixed costs, more of those costs are being expensed, instead of being capitalized as part of inventory.

And so that’s the phenomenon that’s happening. That occurred for both our existing sort of retail natural gas business, as well as the business that we have under the SSO Program. So both of those — all the supply that we have on natural gas, or all of the storage that we have under natural gas, both of those types of businesses are being impacted by this effect.

Ted Burdick - Camulos Capital - Analyst

And did it help in any way in the third and fourth fiscal quarters of 2010?

Chaitu Parikh - MXenergy - EVP, CFO

No, that didn’t help, because we did not go through an injection period last year, last summer, where Sempra had assignments of that inventory. It really started this spring, late spring, when we assigned storage assets over to Sempra, and we started to inject gas into the ground. Because last year, it was a time of year when we entered into the facility, it was really October or November when we assigned the inventory over. We had already incurred all those costs and capitalized a portion of those fixed transportation costs into the inventory value.

Ted Burdick - Camulos Capital - Analyst

Okay. And last question — I don’t want to monopolize this. You noted that the sort of — when separated, the SG&A cost went up $2 million this quarter over last quarter after affecting last quarter for the restructuring expenses. Was all that cash? And would you characterize most of this SG&A as continuing higher expenses? Or were they more one-time type of things?

Chaitu Parikh - MXenergy - EVP, CFO

Yes, it was cash. We do think there was some period over period increase. I probably can’t characterize, in terms of going forward, where we think those expenses will be. But I would tell you that there are no one-time costs associated with the $2 million increase in the current quarter.

Ted Burdick - Camulos Capital - Analyst

Okay. Thank you.

Operator

I’m showing there are no questions queued at this time.

Jeffrey Mayer - MXenergy - President, CEO

Let’s just give our listeners another moment.

Operator

(Operator Instructions).

Jeffrey Mayer - MXenergy - President, CEO

And Ted, you’re welcome to come back, if you’d like. All right Jeremy, thanks very much. Phil?

Philip Mittleman - MXenergy - Associate General Counsel

Well, if there are further questions, I want to thank all of you for joining us today. A replay of this conference call will be available starting this afternoon for the next 30 days at the investor relations link at www.mxholdings.com. Additionally, a transcript of today’s teleconference will be available within the next 7 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 - President, CEO

Thank you all.

Operator

Ladies and gentlemen, that concludes today’s conference. Thank you for your participation. You may now disconnect. Have a great day.

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