MxEnergy Holdings Inc - FORM 10-Q

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EX-32 - EX-32 - MxEnergy Holdings Inc	a10-6186_1ex32.htm
EX-31.2 - EX-31.2 - MxEnergy Holdings Inc	a10-6186_1ex31d2.htm
EX-31.1 - EX-31.1 - MxEnergy Holdings Inc	a10-6186_1ex31d1.htm
EX-10.76 - EX-10.76 - MxEnergy Holdings Inc	a10-6186_1ex10d76.htm
EX-10.75 - EX-10.75 - MxEnergy Holdings Inc	a10-6186_1ex10d75.htm
EX-10.77 - EX-10.77 - MxEnergy Holdings Inc	a10-6186_1ex10d77.htm

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

x		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 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)

Delaware		20-2930908
(State or Other Jurisdiction of		(I.R.S. Employer Identification No.)
Incorporation or Organization)

595 Summer Street, Suite 300
Stamford, Connecticut		06901
(Address of Principal Executive Offices)		(Zip Code)

(203) 356-1318

(Registrant’s telephone number, including area code)

Indicate by check mark 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 Web site, 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 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.

Large accelerated filer o		Accelerated filer o

Non-accelerated filer x		Smaller reporting company o

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

As of April 30, 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 16,385,098 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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MXENERGY HOLDINGS INC.

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2010

TABLE OF CONTENTS

Item Number		Page Number

PART I — FINANCIAL INFORMATION

Cautionary Note Regarding Forward-Looking Statements		3

1.	Financial Statements (unaudited):
	Condensed Consolidated Balance Sheets at March 31, 2010 and June 30, 2009	4
	Condensed Consolidated Statements of Operations for the Three Months and Nine Months Ended March 31, 2010 and 2009	5
	Condensed Consolidated Statements of Stockholders’ Equity for the Nine Months Ended March 31, 2010 and 2009	6
	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended March 31, 2010 and 2009	7
	Notes to Condensed Consolidated Financial Statements	8
2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	40
3.	Quantitative and Qualitative Disclosures about Market Risk	61
4T.	Controls and Procedures	64

PART II — OTHER INFORMATION

1.	Legal Proceedings	66
1A.	Risk Factors	66
2.	Unregistered Sales of Equity Securities and Use of Proceeds	66
3.	Defaults Upon Senior Securities	66
4.	(Removed and Reserved)	66
5.	Other Information	66
6.	Exhibits	67

Signatures		68

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PART I — FINANCIAL INFORMATION

Cautionary Note Regarding Forward-Looking Statements

Some statements in this Quarterly Report on Form 10-Q (the “Quarterly 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 Quarterly 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 the Quarterly Report, 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” in the Company’s Annual Report on Form 10-K for the fiscal year ended June 30, 2009, 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 consumer consumption patterns;

· failure to collect imbalance receivables;

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

· disruptions in local transportation and transmission facilities;

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

· changes in statutes or regulations that inhibit growth or increase costs and impact profitability;

· investigations by 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;

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

· other factors not currently known or considered material by us.

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 Quarterly Report 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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Item 1 — Financial Statements

MXENERGY HOLDINGS INC.

Condensed Consolidated Balance Sheets (Unaudited)

(dollars in thousands, except share data)

	Balance At
	March 31, 2010			June 30, 2009

Assets:
Current assets:
Cash and cash equivalents	$	2,853		$	23,266
Restricted cash	2,748			75,368
Fixed Rate Notes Escrow Account (Note 14)	8,977			—
Accounts receivable from customers and LDCs, net (Note 5)	99,640			47,598
Accounts receivable, net — RBS Sempra (Note 13)	14,700			—
Natural gas inventories (Note 6)	6,625			29,415
Current portion of unrealized gains from risk management activities, net (Note 11)	—			294
Income taxes receivable	7,185			6,461
Deferred income taxes (Note 9)	4,674			9,020
Other current assets	17,334			12,084
Total current assets	164,736			203,506
Goodwill (Note 7)	3,810			3,810
Customer acquisition costs, net (Note 8)	26,123			27,950
Fixed assets, net	2,391			3,728
Deferred income taxes (Note 9)	10,097			15,089
Deferred debt issue costs (Notes 13, 14)	13,754			4,475
Other assets	541			513
Total assets	$	221,452		$	259,071

Liabilities and stockholders’ equity:
Current liabilities:
Accounts payable and accrued liabilities (Note 10)	$	31,518		$	43,147
Current portion of unrealized losses from risk management activities, net (Note 11)	39,006			34,224
Deferred revenue	1,605			4,271
Bridge Financing Loans payable (Note 17)	—			5,400
Denham Credit Facility (Note 17)	—			12,000
Total current liabilities	72,129			99,042
Unrealized losses from risk management activities, net (Note 11)	4,192			14,071
Long-term debt (Note 14)	57,830			163,476
Total liabilities	134,151			276,589

Redeemable Convertible Preferred Stock (Note 15)	—			54,632

Commitments and contingencies (Note 18)	—			—

Stockholders’ equity:
Common stock (Note 16):
Class A Common Stock (par value $0.01; 50,000,000 shares authorized; 33,940,683 shares issued and 33,710,902 shares outstanding at March 31, 2010)	339			—
Class B Common Stock (par value $0.01; 10,000,000 shares authorized; 4,002,290 shares issued and outstanding at March 31, 2010)	40			—
Class C Common Stock (par value $0.01; 40,000,000 shares authorized; 16,385,098 shares issued and outstanding at March 31, 2010)	164			—
Common Stock (par value $0.01; 10,000,000 shares authorized; 4,681,219 shares issued and outstanding at June 30, 2009)	—			47
Total common stock	543			47
Additional paid-in capital	138,348			18,275
Class A treasury stock (229,781 shares at March 31, 2010)	(99		)	—
Accumulated other comprehensive loss	(196		)	(3		)
Accumulated deficit	(51,295		)	(90,469		)
Total stockholders’ equity	87,301			(72,150		)
Total liabilities and stockholders’ equity	$	221,452		$	259,071

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

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MXENERGY HOLDINGS INC.

Condensed Consolidated Statements of Operations (Unaudited)

(dollars in thousands)

	Three Months Ended March 31,
	2010			2009

Sales of natural gas and electricity	$	233,636		$	305,108
Cost of goods sold (excluding depreciation and amortization):
Cost of natural gas and electricity sold	164,997			214,889
Realized losses from risk management activities, net	1,269			20,932
Unrealized (gains) losses from risk management activities, net	26,001			11,462
	192,267			247,283
Gross profit	41,369			57,825

Operating expenses:
General and administrative expenses	14,454			15,714
Advertising and marketing expenses	1,707			417
Reserves and discounts	2,628			4,415
Depreciation and amortization	5,979			10,309
Total operating expenses	24,768			30,855

Operating profit	16,601			26,970
Interest expense, net of interest income of $59 and $6, respectively	7,778			12,244
Income before income tax expense	8,823			14,726
Income tax expense	(3,563		)	(5,343		)
Net income	$	5,260		$	9,383

	Nine Months Ended March 31,
	2010			2009

Sales of natural gas and electricity	$	462,377		$	687,373
Cost of goods sold (excluding depreciation and amortization):
Cost of natural gas and electricity sold	311,664			536,428
Realized losses from risk management activities, net	34,504			42,154
Unrealized (gains) losses from risk management activities, net	(2,451		)	113,396
	343,717			691,978
Gross profit (loss)	118,660			(4,605		)

Operating expenses:
General and administrative expenses	41,366			43,661
Advertising and marketing expenses	2,449			1,694
Reserves and discounts	6,443			9,279
Depreciation and amortization	16,875			28,656
Total operating expenses	67,133			83,290

Operating profit (loss)	51,527			(87,895		)
Interest expense, net of interest income of $116 and $342, respectively	28,942			34,604
Income (loss) before income tax (expense) benefit	22,585			(122,499		)
Income tax (expense) benefit	(9,336		)	47,183
Net income (loss)	$	13,249		$	(75,316	)

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

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MXENERGY HOLDINGS INC.

Condensed Consolidated Statements of Stockholders’ Equity (Unaudited)

(dollars in thousands)

	Nine Months Ended March 31, 2010
	Common Stock			Additional Paid-in Capital		Class A Treasury Stock			Accumulated Other Comprehensive Loss			(Accumulated Deficit) Retained Earnings			Total Stockholders’ Equity

Balance at June 30, 2009	$	47		$	18,275	$	—		$	(3	)	$	(90,469	)	$	(72,150	)
Issuance of Class A Common Stock	339			81,468		—			—			—			81,807
Issuance of Class B Common Stock	40			9,005		—			—			—			9,045
Issuance of Class C Common Stock	164			28,591		—			—			—			28,755
Acquisition of Class A treasury stock	—			—		(99		)	—			—			(99		)
Cancellation of common stock	(47		)	—		—			—			—			(47		)
Stock compensation expense	—			1,009		—			—			—			1,009
Revaluation of redeemable convertible preferred stock	—			—		—			—			25,925			25,925
Comprehensive income:
Net income	—			—		—			—			13,249			13,249
Foreign currency translation	—			—		—			(193		)	—			(193		)
Total comprehensive income															13,056
Balance at March 31, 2010	$	543		$	138,348	$	(99	)	$	(196	)	$	(51,295	)	$	87,301

	Nine Months Ended March 31, 2009
	Common Stock		Additional Paid-in Capital			Unearned Stock Compensation			Accumulated Other Comprehensive Income (Loss)			(Accumulated Deficit) Retained Earnings			Total Stockholders’ Equity

Balance at June 30, 2008	$	36	$	23,635		$	(4	)	$	(189	)	$	9,732		$	33,210
Issuance of common stock	11		(11		)	—			—			—			—
Unamortized stock compensation	—		(600		)	600			—			—			—
Stock compensation expense	—		781			—			—			—			781
Amortization of stock compensation	—		—			(596		)	—			—			(596		)
Purchase and cancellation of treasury shares	—		(12		)	—			—			—			(12		)
Revaluation of redeemable convertible preferred stock	—		(4,389		)	—			—			—			(4,389		)
Comprehensive loss:
Net loss	—		—			—			—			(75,316		)	(75,316		)
Foreign currency translation	—		—			—			343			—			343
Total comprehensive loss															(74,973		)
Balance at March 31, 2009	$	47	$	19,404		$	—		$	154		$	(65,584	)	$	(45,979	)

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

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MXENERGY HOLDINGS INC.

Condensed Consolidated Statements of Cash Flows (Unaudited)

(dollars in thousands)

	Nine Months Ended March 31,
	2010			2009
Operating activities:
Net income (loss)	$	13,249		$	(75,316	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Unrealized (gains) losses from risk management activities, net	(2,451		)	98,269
Stock compensation expense	1,009			185
Provision for doubtful accounts	4,661			6,958
Depreciation and amortization	16,875			28,656
Deferred tax expense (benefit)	9,338			(50,830		)
Non-cash interest expense, primarily unrealized losses on interest rate swaps and amortization of debt issuance costs	7,975			11,878
Amortization of customer contracts acquired	(50		)	(620		)
Changes in assets and liabilities, net of effects of acquisition:
Restricted cash	72,620			197
Accounts receivable	(56,703		)	(55,389		)
Accounts receivable, RBS Sempra	(14,700		)	—
Natural gas inventories	22,790			50,277
Income taxes receivable	(724		)	8,061
Fixed Rate Notes Escrow Account	(8,977		)	—
Other assets	(6,169		)	(7,193		)
Accounts payable and accrued liabilities	(11,579		)	(30,328		)
Deferred revenue	(2,666		)	(2,433		)
Net cash provided by (used in) operating activities	44,498			(17,628		)

Investing activities:
Customer acquisition costs	(13,166		)	(11,899		)
Purchases of fixed assets	(545		)	(744		)
Purchase of assets of Catalyst Natural Gas, LLC	—			(1,609		)
Net cash used in investing activities	(13,711		)	(14,252		)

Financing activities:
Repayment of Floating Rate Notes due 2011	(26,700		)	—
Repayment of Fixed Rate Notes due 2014	(423		)	—
Proceeds from Denham Credit Facility	—			12,000
Repayment of Denham Credit Facility	(12,000		)	—
Proceeds from Bridge Financing Loans under the Revolving Credit Facility	—			10,400
Repayment of Bridge Financing Loans under the Revolving Credit Facility	(5,400		)	—
Proceeds from cash advances under the Revolving Credit Facility	—			30,000
Repayment of cash advances under the Revolving Credit Facility	—			(30,000		)
Debt issuance costs	(6,249		)	(7,218		)
Acquisition of Class A treasury stock	(99		)	—
Purchase and cancellation of treasury shares	—			(12		)
Stock issuance costs	(329		)	—
Net cash (used in) provided by financing activities	(51,200		)	15,170
Net decrease in cash and cash equivalents	(20,413		)	(16,710		)
Cash and cash equivalents at beginning of period	23,266			71,958
Cash and cash equivalents at end of period	$	2,853		$	55,248

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

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MXENERGY HOLDINGS INC.

Notes to Condensed Consolidated Financial Statements (Unaudited)

Nine Months Ended March 31, 2010

Note 1. Organization and Basis of Presentation

MXenergy Holdings Inc. (“Holdings”) was founded in 1999 as a retail energy marketer, and was incorporated in Delaware on January 24, 2005 as part of a corporate reorganization. The two principal operating subsidiaries of Holdings are MXenergy Inc. and MXenergy Electric Inc. which are engaged in the marketing and supply of natural gas and electricity, respectively. Holdings and its subsidiaries (collectively, the “Company”) operate in 40 natural gas and electricity utility areas located in 14 states in the United States (the “U.S.”) and in two Canadian provinces.

The accompanying unaudited condensed consolidated financial statements of the Company have been prepared in accordance with requirements of the Securities and Exchange Commission (the “SEC”). Accordingly, they do not include all of the information and footnotes required by accounting principles generally accepted in the U.S. (“U.S. GAAP”) for complete financial statements. In the opinion of management, all normal and recurring adjustments considered necessary for a fair presentation of financial position, results of operations and cash flows for the interim periods have been made. These unaudited condensed consolidated financial statements should be read in conjunction with the Company’s Annual Report on Form 10-K for the fiscal year ended June 30, 2009 (the “2009 Form 10-K”). Certain reclassifications have been made to prior period amounts to conform to the current period presentations. The accounting and reporting policies of the Company are consistent, in all material respects, with those used to prepare the 2009 Form 10-K, except for the impact of new accounting pronouncements summarized in Note 2 below.

The condensed consolidated balance sheet at June 30, 2009 has been derived from the audited consolidated financial statements included in the Company’s 2009 Form 10-K, but does not include all of the information and footnotes required by U.S. GAAP for complete financial statements.

The preparation of financial statements in conformity with U.S. GAAP requires the use of estimates and assumptions that affect reported amounts and disclosures. Actual amounts could differ from those estimates. Interim results should not be considered indicative of results for future periods.

Note 2. New Accounting Pronouncements

Accounting Pronouncements Adopted During the Nine Months Ended March 31, 2010

In June 2009, the Financial Accounting Standards Board (the “FASB”) issued Statement of Financial Accounting Standards No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles — a replacement of FASB Statement No. 162” (“SFAS No. 168”). Effective for financial statements issued for interim and annual periods ending after September 15, 2009, the Accounting Standards Codification (the “ASC”) supersedes all existing accounting and reporting standards, excluding those issued by the SEC, and is now the single source of authoritative U.S. GAAP for entities that are not SEC registrants. Rules and interpretative releases of the SEC are also sources of U.S. GAAP for SEC registrants. The Company adopted the provisions of SFAS No. 168 effective for the financial statements included in this Form 10-Q. The adoption of SFAS No. 168, as codified by ASC Topic 105, “Generally Accepted Accounting Principles,” impacted the Company’s financial statement disclosures, but did not have any effect on its financial position or results of operations.

Effective July 1, 2009, the Company adopted ASC guidelines regarding accounting and reporting for business combinations that are consummated after July 1, 2009. These guidelines include certain changed principles and requirements related to: (1) recognition and measurements of identifiable assets acquired, liabilities assumed, goodwill acquired, any gain from a bargain purchase, and any noncontrolling interest in an acquired company; (2) application issues relating to accounting and disclosures for assets and liabilities arising from contingencies in a business combination; and (3) disclosures regarding business combinations in financial statements. The Company will apply the ASC guidelines prospectively to business combination transactions consummated after July 1, 2009, if any. The Company did not consummate any business combination transactions during the nine months ended March 31, 2010.

In August 2009, the FASB issued Accounting Standards Update No. 2009-05, “Fair Value Measurements and Disclosures” (“ASU 2009-05”). ASU 2009-05 amends ASC Topic 820, “Fair Value Measurements and Disclosures” by providing additional guidance clarifying the measurement of liabilities at fair value. The

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amendments prescribed by ASU 2009-05 became effective for the Company’s quarterly reporting period ending December 31, 2009 and did not have any impact on the Company’s financial position or results of operations.

In February 2010, the FASB issued Accounting Standards Update No. 2010-09, “Subsequent Events (Topic 855) — Amendments to Certain Recognition and Disclosure Requirements” (“ASU 2010-09”). ASU 2010-09 amends ASC Topic 855, “Subsequent Events,” by clarifying the scope of disclosure requirements related to subsequent events. The amendments prescribed by ASU 2010-09 became effective for the Company’s quarterly reporting period ending March 31, 2010 and did not have any impact on the Company’s financial position or results of operations. Refer to Note 21 for disclosures regarding subsequent events.

In January 2010, the FASB issued Accounting Standards Update No. 2010-06 (“ASU 2010-06”), which amends FASB ASC Topic 820, “Fair Value Measurements and Disclosures.” The amended guidance in ASU 2010-06 requires entities to disclose additional information regarding assets and liabilities that are transferred between levels of the fair value hierarchy. ASU 2010-06 also requires that required Level 3 disclosures regarding purchases, sales, issuances and settlements be reported on a gross basis. ASU 2010-06 clarifies existing guidance pertaining to the level of disaggregation at which fair value disclosures should be made and the requirements to disclose information about the valuation techniques and inputs used in estimating Level 2 and Level 3 fair value measurements. The amended guidance in ASU 2010-06 pertaining to disclosure of transfers between levels of the fair value hierarchy, the level of disaggregation of disclosures and disclosure of valuation techniques and inputs used in estimating Level 2 and Level 3 measurements became effective and were adopted for the Company’s quarterly reporting period ending March 31, 2010.

The requirement to disclose Level 3 purchases, sales, issuances and settlements on a gross basis will become effective for fiscal years (and for interim periods within those fiscal years) beginning after December 15, 2010. The Company intends to adopt these provisions effective for its quarterly reporting period ending September 30, 2011.

Note 3. Debt and Equity 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 (refer to Note 13), 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 consummated an equity and debt restructuring (the “Restructuring”), which included various transactions. The Restructuring included a debt exchange transaction that was accounted for as a troubled-debt restructuring in accordance with 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 (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 three months ended September 30, 2009, as summarized in the following table.

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	Balance at June 30, 2009			Restructuring Transactions, Net			Other Operating Activity, Net			Balance at September 30, 2009
	(in thousands)
Assets:
Cash and cash equivalents	$	23,266		$	(2,375	)	$	(17,385	)	$	3,506
Restricted cash	75,368			(75,000		)	1,133			1,501
Accounts receivable – RBS Sempra	—			17,948			(6,072		)	11,876
Fixed Rate Notes Escrow Account	—			8,977			—			8,977
Deferred debt issue costs	4,475			15,083		(1)	(3,546		)(2)	16,012
Net impact on selected asset accounts	$	103,109		$	(35,367	)	$	(25,870	)	$	41,872

Liabilities and stockholders’ equity:
Liabilities:
Bridge Financing Loans payable	$	5,400		$	(5,400	)	$	—		$	—
Denham Credit Facility	12,000			(12,000		)	—			—
Long-term debt:
Fixed Rate Notes due 2014	—			49,951			79		(3)	50,030
Floating Rate Notes due 2011	163,476			(158,787		)	1,665		(3)	6,354
Net impact on selected liability accounts	180,876			(126,236		)	1,744			56,384

Redeemable convertible preferred stock	54,632			(54,632		)	—			—

Stockholders’ equity:
Common stock	47			496			—			543
Additional paid in capital	18,275			119,080			(117		)	137,238
Accumulated deficit	(90,469		)	25,925			(10,236		)	(74,780		)
Net impact on selected stockholders’ equity accounts	(72,147		)	145,501			(10,353		)	63,001
Net impact on selected liability and stockholders’ equity accounts	$	163,361		$	(35,367	)	$	(8,609	)	$	119,385

(1) Represents the aggregate of $6.1 million of legal, consulting and other costs directly associated with Restructuring transactions and the $9.0 million fair value of Class B Common Stock issued to RBS Sempra as a condition to its entering into the agreements governing the Commodity Supply Facility.

(2) Represents amortization of deferred debt issue costs recorded as interest expense during the three months ended September 30, 2009.

(3) Represents amortization of original issue discount recorded as interest expense during the three months ended September 30, 2009.

Material impacts of the Restructuring transactions that resulted in sources and uses of cash and cash equivalents include:

· $75.0 million of restricted cash held as collateral for obligations under the Revolving Credit Facility was released to cash and cash equivalents upon termination of the Revolving Credit Facility in September 2009;

· $26.7 million was paid to bondholders in partial exchange for their Floating Rate Senior Notes due 2011 (the “Floating Rate Notes due 2011”; refer to Note 14);

· $12.0 million of principal outstanding, plus accrued and unpaid interest, under the credit agreement (the “Denham Credit Facility”) with Denham Commodity Partners LP (“Denham”) was repaid and the Denham Credit Facility was terminated (refer to Note 17);

· $9.0 million was transferred from cash and cash equivalents to an escrow account (the “Fixed Rate Notes Escrow Account”), which is maintained as security for future interest payments to holders of the 13.25% Senior Subordinated Secured Notes due 2014 (the “Fixed Rate Notes due 2014”; refer to Note 14);

· $6.4 million of legal, consulting and other fees directly related to various Restructuring transactions were paid and recorded as deferred debt issue costs ($6.1 million) and stock issue costs ($0.3 million). The deferred debt issue costs will be amortized as an increase to interest expense over the remaining terms of the related agreements; and

· $5.4 million of principal outstanding, plus accrued and unpaid interest, of bridge financing loans under the Revolving Credit Facility (the “Bridge Financing Loans”) were repaid and the Bridge Financing Loans were terminated (refer to Note 17).

In addition, in connection with the Commodity Supply Facility, certain banking relationships that previously belonged to the Company are now under RBS Sempra’s name and control. Cash is released by RBS Sempra to the Company as required to meet the Company’s ongoing operating cash requirements. As a result, $11.9 million

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that would have been included in cash and cash equivalents prior to the Restructuring were recorded as accounts receivable — RBS Sempra on the consolidated balance sheet as of September 30, 2009. The ISDA Master Agreements include provisions that allow for net settlement of amounts due from and due to RBS Sempra. Accordingly, the Company reports amounts due from and due to RBS Sempra net on the consolidated balance sheets.

Long-Term Debt Activity

The Company consummated an exchange offer of $158.8 million aggregate principal amount of outstanding Floating Rate Notes due 2011 for:

· $26.7 million of cash;

· $67.8 million aggregate principal amount of Fixed Rate Notes due 2014, which were recorded on the consolidated balance sheets net of a $17.8 million original issue discount. The original issue discount will be amortized as an increase to interest expense over the remaining term of the Fixed Rate Notes due 2014; and

· 33,940,683 shares of newly authorized $0.01 par value Class A Common Stock of Holdings, recorded at their aggregate fair value of approximately $82.1 million ($0.3 million par value, recorded as Class A Common Stock; and $81.8 million recorded as additional paid in capital on the consolidated balance sheets).

The exchange was accounted for as a troubled-debt restructuring in accordance with U.S. GAAP, and therefore did not result in any gain or loss recorded in the consolidated statements of operations.

Stockholders’ Equity Activity

All equity transactions consummated in connection with the Restructuring were recorded at the fair value of various classes of common stock issued on September 22, 2009. In addition to the Class A Common Stock issued to holders of Fixed Rate Notes due 2014, Holdings also issued the following shares of common stock as a result of non-cash transactions:

· 4,002,290 shares of newly authorized $0.01 par value Class B Common Stock were issued to RBS Sempra, as a condition to its entry into the agreements governing the Commodity Supply Facility. The aggregate $9.0 million fair value of Class B Common Stock issued to RBS Sempra was also recorded as deferred debt issue costs on the consolidated balance sheets during the first quarter of fiscal year 2010 and will be amortized as interest expense over the remaining term of the Commodity Supply Facility.

· 11,862,551 shares of newly authorized $0.01 par value Class C Common Stock were issued to holders of Series A redeemable convertible preferred stock (the “Preferred Stock”). Prior to the Restructuring, the Preferred Stock was recorded at its estimated redemption value of $54.6 million on the consolidated balance sheets. The aggregate fair value of Class C Common Stock issued to holders of Preferred Stock was $28.7 million ($0.1 million par value, recorded as Class C Common Stock; and $28.6 million recorded as additional paid in capital). The $25.9 million excess of redemption value of the Preferred Stock over the fair value of Class C Common Stock issued to the holders of the Preferred Stock was recorded as a reduction of accumulated deficit on the consolidated balance sheets.

· 4,499,588 shares of newly authorized $0.01 par value Class C Common Stock were issued to the holders of Holdings’ common stock issued and outstanding prior to the consummation of the Restructuring. All 4,681,219 shares of Holdings’ common stock issued and outstanding prior to the Restructuring were retired as a result of the transaction.

In connection with the Restructuring, the shareholders agreed to create a new equity-based incentive plan, pursuant to which the Company may issue Class C Common Stock not to exceed 10% of Holdings’ outstanding common stock (on a fully diluted basis) after giving effect to the Restructuring. In January 2010, Holdings’ Board of Directors authorized a new plan and approved grants of restricted stock units (“RSUs”) to certain senior executive officers, directors and a former director (refer to Note 16).

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Operating Expense Activity

In connection with the Restructuring, the Company recorded approximately $2.2 million of non-recurring general and administrative expenses, all of which were recorded during the three months ended September 30, 2009, including:

· $0.8 million of bonuses, included in salaries and benefits, which were paid to senior management in connection with the consummation of the Restructuring;

· $0.2 million of severance costs, included in salaries and benefits, which related to certain employees terminated in September 2009 as part of an initiative to streamline the Company’s organizational structure and control operating costs; and

· $1.2 million of professional fees incurred in connection with various potential liquidity events considered during fiscal year 2009 and the first three months of fiscal year 2010.

Note 4. Seasonality of Operations

Natural gas and electricity sales accounted for approximately 85% and 15%, respectively, of the Company’s total sales for the nine months ended March 31, 2010. 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 collections from the Company’s natural gas customers peak in the spring of each calendar year, while cash collections from electricity customers peak in 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.

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. In addition, budget billing programs and payment terms of local distribution companies (“LDCs”) can cause timing differences between the billing and collection of accounts receivable and the recording of revenues.

The impact of rapidly rising or falling commodity prices also varies greatly depending on the period of time in which they occur during the Company’s fiscal year. Although commodity price movements can have material short-term impacts on monthly and quarterly operating results, the Company’s economic hedging and contract pricing strategies are designed to reduce the impact of such trends on operating results for a full fiscal year. Therefore, the short-term impacts of changing commodity prices should be considered in the context of the Company’s entire annual operating cycle.

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Note 5. Accounts Receivable

Accounts Receivable from Customers and LDCs, Net

Accounts receivable, net, is summarized in the following table.

	Balance at
	March 31, 2010			June 30, 2009
	(in thousands)
Billed customer accounts receivable:
Guaranteed by LDCs	$	27,907		$	7,768
Non-guaranteed by LDCs	41,182			26,679
	69,089			34,447
Unbilled customer accounts receivable (1):
Guaranteed by LDCs	16,217			5,737
Non-guaranteed by LDCs	14,664			10,547
	30,881			16,284
Total customer accounts receivable	99,970			50,731
Less: Allowance for doubtful accounts	(5,480		)	(7,344		)
Customer accounts receivable, net	94,490			43,387
Cash imbalance settlements and other receivables, net (2)	5,150			4,211
Accounts receivable, net	$	99,640		$	47,598

(1) Unbilled customer accounts receivable represents estimated revenues associated with natural gas and electricity consumed by customers but not yet billed under the monthly cycle billing method utilized by LDCs.

(2) Cash imbalance settlements represent differences between natural gas delivered to LDCs for consumption by the Company’s customers and actual customer usage. Such imbalances are expected to be settled in cash within the next 12 months in accordance with contractual payment arrangements with the LDCs.

The Company operates in 40 natural gas and electricity utility areas located in 14 U.S. states and two Canadian provinces. The Company’s diversified geographic coverage mitigates the credit exposure which could result from concentrations in a single LDC territory or a single regulatory jurisdiction, from extreme local weather patterns or from an economic downturn in any single geographic region. In addition, the Company has limited exposure to risk associated with high concentrations of sales volumes with individual customers. The Company’s largest customer accounted for approximately 2% of natural gas sales during the nine months ended March 31, 2010 and 2009.

The allowance for doubtful accounts represents the Company’s estimate of potential credit losses associated with customer accounts receivable in markets where such receivables are not guaranteed by LDCs. The Company assesses the adequacy of its allowance for doubtful accounts through review of the aging of customer accounts receivable and general economic conditions in the markets that it serves. Based upon this review as of March 31, 2010, the Company believes that its allowance for doubtful accounts is adequate to cover potential credit losses related to customer accounts receivable. An analysis of the allowance for doubtful accounts is provided in the following table.

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Allowance for Doubtful Accounts Activity	2010			2009
	(in thousands)
Three months ended March 31:
Balance at beginning of period	$	5,128		$	4,505
Add: Provision for doubtful accounts	1,565			3,245
Less: Net charge-offs of customer accounts receivable	(1,213		)	(1,633		)
Balance at end of period	$	5,480		$	6,117

Provision for doubtful accounts as a percent of sales of natural gas and electricity in non-guaranteed markets	1.37		%	2.10		%

Nine months ended March 31:
Balance at beginning of period	$	7,344		$	5,154
Add: Provision for doubtful accounts	4,661			6,958
Less: Net charge-offs of customer accounts receivable	(6,525		)	(5,995		)
Balance at end of period	$	5,480		$	6,117

Provision for doubtful accounts as a percent of sales of natural gas and electricity in non-guaranteed markets	1.92		%	1.87		%

Reserves and discounts in the consolidated statements of operations include the provision for doubtful accounts related to customer accounts receivable within markets where such receivables are not guaranteed by LDCs as well as discounts related to customer accounts receivable that are guaranteed by LDCs. During the nine months ended March 31, 2010, approximately 47% of the Company’s total sales of natural gas and electricity were within markets where LDCs do not guarantee customer accounts receivable while 53% of total sales were within markets where LDCs guarantee customer accounts receivable at a weighted average discount rate of approximately 1%. Such discount is the cost to guarantee the customer accounts receivable. In markets where customer accounts receivable are guaranteed by the LDC, the Company is exposed to the credit risk of the LDC, rather than to that of its customers. The Company monitors the credit ratings of LDCs and the parent companies of LDCs that guarantee customer accounts receivable. The Company also periodically reviews payment history and financial information for LDCs to ensure that it identifies and responds to any deteriorating trends. As of March 31, 2010, all of the Company’s customer accounts receivable in guaranteed markets were from LDCs with investment grade credit ratings.

The Company will continue to closely monitor economic conditions and actual collection data within these and other markets for signs of any negative long-term trends which could result in higher allowance requirements.

Note 6. Natural Gas Inventories

Natural gas inventories are summarized in the following table.

	Balance at
	March 31, 2010		June 30, 2009
	(in thousands)

Storage inventory for delivery to customers	$	4,394	$	24,457
Imbalance settlements in-kind (1)	2,231		4,958
Total	$	6,625	$	29,415

(1) Represents inventory to be transferred to the Company or its customers from LDCs as a result of an excess of natural gas deliveries over amounts used by customers in prior periods. These inventories are expected to be transferred to the Company or its customers within the upcoming twelve-month period.

During the nine months ended March 31, 2010, in connection with RBS Sempra’s responsibility to manage the Company’s storage capacity under the Commodity Supply Facility, the Company also sold approximately 2,200,000 million British thermal units (“MMBtus”) of natural gas inventory to RBS Sempra for its weighted-average cost of $12.0 million. The Company is required to re-acquire such natural gas from RBS Sempra as necessary to meet customer demand during the upcoming winter months for the price at which the inventory was

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sold to RBS Sempra. The remaining decrease in natural gas held in storage from June 30, 2009 to March 31, 2010 was primarily due to normal seasonal activity as customer consumption of natural gas inventory during the winter months generally exceeds purchases of inventory during the first nine months of the Company’s fiscal year.

The weighted-average cost per MMBtu of natural gas held in storage increased 22% from June 30, 2009 to March 31, 2010, which partially offset the impact of lower volume of natural gas held in storage.

Note 7. Goodwill

The Company’s goodwill, which relates to the acquisition of substantially all of the assets of Shell Energy Services Company L.L.C. during fiscal year 2007, is assigned to the natural gas business segment. The Company tests its goodwill for impairment annually at June 30, or if events or changes in circumstances may indicate that an impairment of goodwill exists. Material events, transactions and changes in circumstances are evaluated for their impact on the fair value of the natural gas business segment and the recorded value of goodwill. During the nine months ended March 31, 2010, the Company evaluated the impacts of various transactions consummated in connection with the Restructuring and concluded that they did not have any impact on the recorded carrying value assigned to goodwill.

Note 8. Customer Acquisition Costs, Net

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

	Gross Book Value		Accumulated Amortization		Net Book Value
	(in thousands)
Balance at March 31, 2010:
Customer contracts acquired	$	10,506	$	7,979	$	2,527
Direct sales and advertising costs	48,956		25,360		23,596
Total customer acquisition costs	$	59,462	$	33,339	$	26,123

Balance at June 30, 2009:
Customer contracts acquired	$	48,832	$	42,553	$	6,279
Direct sales and advertising costs	40,744		19,073		21,671
Total customer acquisition costs	$	89,576	$	61,626	$	27,950

Amortization expense relating to capitalized customer acquisition costs was $5.5 million and $8.4 million for the three months ended March 31, 2010 and 2009, respectively, and $15.0 million and $22.7 million for the nine months ended March 31, 2010 and 2009, respectively. Amortization expense associated with customer acquisition costs capitalized as of March 31, 2010 is expected to be approximately $4.4 million for the remainder of fiscal year 2010, $13.7 million for fiscal year 2011 and $8.0 million thereafter. As of March 31, 2010, the weighted average remaining amortization period associated with all customer acquisition costs was approximately 1.4 years.

Note 9. Income Taxes

The Company’s effective income tax rate was a charge of 40.4% and 36.3% for the three months ended March 31, 2010 and 2009, respectively. The change in the effective tax rate for the three months ended March 31, 2010 was primarily due to:

· an increase in the effective tax rate for non-recovery of state tax losses due to certain states not allowing tax loss carrybacks; and

· changes in permanent differences.

For the nine months ended March 31, 2010 and 2009, the effective tax rate was a charge of 41.3% and a benefit of 38.5%, respectively. The change in the effective tax rate for the nine months ended March 31, 2010 was primarily due to:

· reporting taxable net income for the current period, as compared with a net loss for the same period in the prior fiscal year;

· an increase in the effective rate for non-recovery of state tax losses due to certain states not allowing tax loss carrybacks; and

· changes in permanent differences.

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Deferred income taxes reflect the net tax effects of temporary differences between the carrying amount of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The Company’s policy is to establish a valuation allowance if it is “more likely than not” that the related tax benefits will not be realized. As of March 31, 2010 and June 30, 2009, the Company determined, based on available evidence, including historical financial results for the prior three years, that it is “more likely than not” that a portion of these items may not be recoverable in the future. Accordingly, the Company recorded valuation allowances at March 31, 2010 and June 30, 2009 related to non-recovery of deferred tax assets.

The Worker, Homeownership and Business Assistance Act of 2009, which was signed into law on November 6, 2009, contains a number of tax law changes, including a provision that permits companies to elect to carry back certain net operating losses for up to five years. As of March 31, 2010, the Company expects to carry back the amount of any tax loss for fiscal year 2010.

Note 10. Accounts Payable and Accrued Liabilities

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

	Balance at
	March 31, 2010		June 30, 2009
	(in thousands)
Trade accounts payable and accrued liabilities (1)	$	14,938	$	13,952
Accrued commodity purchases	6,549		9,847
Interest payable (2)	1,554		8,946
Payroll and related expenses	3,539		4,761
Sales and other taxes	3,121		2,193
Other	1,817		3,448
Total accounts payable and accrued liabilities	$	31,518	$	43,147

(1) Includes $0.1 million and $1.9 million due to related parties at March 31, 2010 and June 30, 2009, respectively, for legal services, financial advisory services and management fees. Refer to Note 17 for additional information regarding related party transactions.

(2) Includes $1.0 million of accrued interest at June 30, 2009 related to Bridge Financing Loans and the Denham Credit Facility. All amounts due to the Bridge Financing Loans lenders and Denham were repaid in September 2009 in connection with the Restructuring. Refer to Note 17 for additional information regarding related party transactions.

Interest payable primarily includes accrued and unpaid interest associated with the Fixed Rate Notes due 2014 and the Floating Rate Notes due 2011. Trade accounts payable and accrued expenses include amounts accrued for transportation and distribution charges, imbalances, other utility-related expenses and general operating expenses.

Note 11. Derivatives and Hedging Activities

The Company is exposed to certain risks relating to its ongoing business operations. The primary risks managed by using derivative instruments are commodity price risk and interest rate risk. The Company has a risk management policy that is intended to reduce its financial exposure related to changes in the price of natural gas and electricity and to changes in the interest rates associated with its Commodity Supply Facility and Floating Rate Notes due 2011. The Company’s risk management policy defines various risk management controls and limits that are designed to monitor its commodity price risk position and ensure that hedging performance is in line with objectives established by its Board of Directors and management. Speculative trading activities are explicitly prohibited under the Company’s risk management policy.

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

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Settlements on the derivative instruments are realized monthly and are generally based upon the difference between the contract price and the closing price as quoted on the New York Mercantile Exchange (“NYMEX”) or other published index.

The recorded values of derivative instruments reflect management’s best estimate of fair value, which takes into account various factors including closing exchange and over-the-counter quotations, parity differentials and volatility factors underlying the commitments. In addition, the recorded fair values are discounted to reflect counterparty credit risk and time value of settlement.

Volumes associated with commodity and interest rate derivative contracts that are recorded at fair value on the consolidated balance sheets, which expire at various times through March 2012, are summarized in the following table. The volumes in the table do not quantify risk or represent assets or liabilities of the Company, but are used in the calculations of fair value and cash settlements under the contracts.

	Open Positions as of
	March 31, 2010		June 30, 2009
Natural gas instruments (amounts reflected in MMBtus (1)):
Financial forward derivative instruments:
NYMEX-referenced over the counter swaps	9,443,000		10,158,000
Basis swaps	20,535,000		11,712,000
Options	150,000		1,015,000

Physical forward instruments (2):
Physical fixed purchase and sale contracts	1,353,000		—
Physical basis purchase and sale contracts	560,000		—
Physical index purchase and sale contracts	549,000		—

Electricity instruments (amounts reflected in MWhrs (3)):
Financial forward derivative instruments:
Swaps and fixed price contracts	158,000		168,000

Physical forward instruments (2):
Electricity purchase and sale contracts	642,000		—

Interest rate swaps (in millions)	$	80.0	$	110.0

(1) 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.

(2) Represents agreements for the purchase and sale of natural gas or electricity that are accounted for as derivatives because they did not qualify for the “normal purchases and sales” exclusion under U.S. GAAP as of the respective period-end date.

(3) 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.

The fair value of these derivative instruments recorded on the Company’s consolidated balance sheet is summarized in the following table.

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Type of Derivative	Location on the Consolidated Balance Sheet	Prior to Netting		Impact of Master Netting Agreements			After Netting
		(in thousands)
Fair value as of March 31, 2010:

Asset derivatives:
Commodity derivatives	Unrealized gains from risk management activities, net	$	12,210	$	(12,210	)	$	—
Total		$	12,210	$	(12,210	)	$	—

Liability Derivatives:
Commodity derivatives	Unrealized losses from risk management activities, net	$	49,457	$	(12,210	)	$	37,247
Interest rate derivatives	Unrealized losses from risk management activities, net	5,951		—			5,951
Total		$	55,408	$	(12,210	)	$	43,198

Fair value as of June 30, 2009:

Asset derivatives:
Commodity derivatives	Unrealized gains from risk management activities, net	$	24,649	$	(24,355	)	$	294
Total		$	24,649	$	(24,355	)	$	294

Liability Derivatives:
Commodity derivatives	Unrealized losses from risk management activities, net	$	64,347	$	(24,355	)	$	39,992
Interest rate derivatives	Unrealized losses from risk management activities, net	8,303		—			8,303
Total		$	72,650	$	(24,355	)	$	48,295

The effect of derivative instruments on the Company’s consolidated statements of operations is summarized in the following table.

	Location of (Gains) Losses Recognized on the Consolidated Statement of Operations	Amount of (Gains) Losses Recognized
		(in thousands)
Three Months Ended March 31:

2010:
Commodity derivatives	Cost of goods sold —realized (gains) losses from risk management activities, net	$	1,269
Commodity derivatives	Cost of goods sold — unrealized (gains) losses from risk management activities, net	26,001
Interest rate derivatives	Interest expense, net of interest income	(1,313		)
Total		$	25,957

2009:
Commodity derivatives	Cost of goods sold —realized (gains) losses from risk management activities, net	$	20,932
Commodity derivatives	Cost of goods sold — unrealized (gains) losses from risk management activities, net	11,462
Interest rate derivatives	Interest expense, net of interest income	(661		)
Total		$	31,733

Nine Months Ended March 31:

2010:
Commodity derivatives	Cost of goods sold —realized (gains) losses from risk management activities, net	$	34,504
Commodity derivatives	Cost of goods sold — unrealized (gains) losses from risk management activities, net	(2,451		)
Interest rate derivatives	Interest expense, net of interest income	(2,352		)
Total		$	29,701

2009:
Commodity derivatives	Cost of goods sold —realized (gains) losses from risk management activities, net	$	42,154
Commodity derivatives	Cost of goods sold — unrealized (gains) losses from risk management activities, net	113,396
Interest rate derivatives	Interest expense, net of interest income	3,477
Total		$	159,027

Commodity Price Risk Management Activities

The Company utilizes swap instruments and, to a lesser extent, option instruments to economically hedge the anticipated natural gas and electricity commodity purchases required to meet expected customer demand for all accounts served under fixed price contracts (up to 110% in the winter months with respect to customer demand in certain natural gas utility service areas with daily balancing requirements and up to 110% in the summer months with respect to customer demand in certain electricity utility service areas).

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Financial Natural Gas Derivative Contracts

The Company utilizes the Commodity Supply Facility (refer to Note 13) to enter into NYMEX-referenced over-the-counter swaps, basis swaps and options to economically hedge the risk of variability in the cost of natural gas. Under the Commodity Supply Facility, as of March 31, 2010, the Company has the ability to enter into NYMEX and basis swaps through August 2012.

In connection with the Commodity Supply Facility, during the nine months ended March 31, 2010, certain of the Company’s natural gas hedge agreements under the former Hedge Facility were novated to RBS Sempra from the previous counterparty. Such novations did not have any impact on the Company’s rights, obligations, risks or accounting methodology associated with the agreements.

Physical Forward Natural Gas Derivative Contracts

As of June 30, 2009, the Company had forward physical contracts to purchase natural gas beginning in July 2009 and ending in November 2010. Based on the terms of these purchases, the Company had elected to treat all such contracts as “normal purchases” under U.S. GAAP, and therefore the contracts were not reported on the consolidated balance sheets at June 30, 2009.

Under the terms of the Commodity Supply Facility, most of the outstanding physical forward agreements for the purchase of natural gas were novated to RBS Sempra during the second quarter of fiscal year 2010. Based upon the terms of the ISDA Master Agreements, certain of these novated agreements no longer qualify as “normal purchases.” Since the novation dates of these agreements, changes in fair value have been reflected in earnings and recorded in unrealized gains and/or unrealized losses from risk management activities on the consolidated balance sheets at March 31, 2010. These agreements are included in the March 31, 2010 fair value measurements reported in Note 12.

Financial Electricity Derivative Contracts

As of June 30, 2009, the Company did not have an exclusive agreement with any single hedge provider for electricity. The Company managed its exposure to risk associated with its electricity hedge providers through a formal credit risk management process and through daily review of exposures from open positions. As of June 30, 2009, all of the Company’s electricity hedge positions were with counterparties with investment grade credit ratings. The Company generally was required to post letters of credit to cover its liability positions with various counterparties in accordance with electricity hedging agreements.

Effective September 22, 2009, under the Commodity Supply Facility, the Company has an exclusive agreement with RBS Sempra for electricity economic hedging activities. Subsequent to the Restructuring, the Company’s existing electricity swap agreements with other counterparties were novated to RBS Sempra. Such novations did not have any impact on the Company’s rights, obligations, risks or accounting methodology associated with the agreements.

Physical Forward Electricity Derivative Contracts

As of June 30, 2009, the Company had physical forward contracts to purchase electricity beginning in July 2009 and ending in September 2011. Based on the terms of these purchases, the Company had elected to treat all such contracts as “normal purchases” under U.S. GAAP, and therefore the contracts were not reported on the consolidated balance sheets at June 30, 2009.

Under the terms of the Commodity Supply Facility, all physical forward agreements for the purchase of electricity were novated to RBS Sempra during the second quarter of fiscal year 2010. Based upon the terms of the ISDA Master Agreements, certain of these novated agreements no longer qualify as “normal purchases.” Since the novation dates of these agreements, changes in fair value have been reflected in earnings and recorded in unrealized gains and/or unrealized losses from risk management activities on the consolidated balance sheets at March 31, 2010. These agreements are included in the March 31, 2010 fair value measurements reported in Note 12.

Interest Rate Risk Management Activities

The Company is exposed to risk from fluctuations in interest rates under the Commodity Supply Facility and the

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Floating Rate Notes due 2011. The Company manages its exposure to interest rate fluctuations by utilizing interest rate swaps to effectively convert the interest rate exposure from a variable rate to a fixed rate of interest.

As of March 31, 2010, an $80.0 million swap was outstanding, which expires on August 1, 2011. The fixed-for-floating swap effectively fixes the six-month LIBOR rate at 5.72% per annum. During fiscal year 2010, the $80.0 million interest rate swap agreement was novated to RBS Sempra from the previous counterparty, as required by the terms of the Commodity Supply Facility. Such novation did not have any impact on the Company’s rights, obligations, risks or accounting methodology associated with the interest rate swap agreement.

Under the Commodity Supply Facility, the Company is subject to variable interest rates in connection with cash borrowings and credit support, primarily in the form of letters of credit, provided by RBS Sempra. As of March 31, 2010, approximately $39.2 million of letters of credit were outstanding under the Commodity Supply Facility and $6.4 million aggregate principal of Floating Rate Notes due 2011 was outstanding.

As of June 30, 2009, the Company’s interest rate derivative liabilities were collateralized under the Revolving Credit Facility. At March 31, 2010, the Company posted $6.0 million of cash as collateral against its mark-to-market exposure related to the outstanding interest rate swap agreement, which is recorded in other current assets on the consolidated balance sheets.

The Company has not designated interest rate swaps as hedges and, accordingly, changes in the market value of the interest rate swaps are charged directly to interest expense. Changes in the market value of interest rate swaps resulted in increases (decreases) to interest expense of $(1.3) million and $(0.7) million for the three months ended March 31, 2010 and 2009, respectively, and $(2.4) million and $3.5 million for the nine months ended March 31, 2010 and 2009, respectively. At March 31, 2010, the total unrealized losses from risk management activities on the consolidated balance sheets related to interest rate swaps was approximately $6.0 million.

A $30.0 million interest rate swap that was outstanding at June 30, 2009 was terminated in September 2009.

Note 12. Fair Value of Financial Instruments

The Company measures assets and liabilities associated with various financial forward derivative instruments and physical forward purchase and sale agreements at fair value on a recurring basis, and categorizes these fair value measurements in accordance with a fair value hierarchy that prioritizes the assumptions, or “inputs,” used in applying valuation techniques. The three levels of inputs within the fair value hierarchy are:

· Level 1 — Observable inputs that reflect unadjusted quoted prices for identical assets and liabilities in active markets as of the reporting date.

· Level 2 — Inputs other than quoted prices included in Level 1 that represent observable market-based inputs, such as quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets that are not considered to be active. Level 2 also includes unobservable inputs that are corroborated by market data.

· Level 3 — Inputs that are not observable from objective sources and therefore cannot be corroborated by market data.

The Company generally utilizes a market approach for its recurring fair value measurements. In forming its fair value estimates, the Company utilizes the most observable inputs available for the respective valuation technique. If a fair value measurement reflects inputs from different levels within the fair value hierarchy, the measurement is classified based on the lowest level of input that is significant to the fair value measurement. The key inputs and assumptions utilized for the fair value measurements recorded by the Company are summarized as follows:

Financial natural gas derivative contracts — NYMEX-referenced swaps are valued utilizing unadjusted market commodity quotes from a pricing service, which are considered to be quotes from an active market, but are deemed to be Level 2 inputs because the swaps are not an identical instrument to the commodity. Basis swaps and options are generally valued using observable broker quotes. Other inputs and assumptions include contract position volume, price volatility, commodity delivery location, credit quality of the Company and of derivative counterparties, credit enhancements, if any, and time value.

Financial electricity derivative contracts — Electricity swaps are valued utilizing market commodity quotes from a pricing service, which are deemed to be observable inputs. Other inputs and assumptions include contract position volume, price volatility, commodity delivery location, credit quality of the Company and of derivative

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counterparties, credit enhancements, if any, and time value.

Physical forward natural gas and electricity derivative contracts — The Company utilizes market commodity quotes from a pricing service to value these instruments, which are deemed to be observable inputs. Other inputs and assumptions include contract position volume, commodity delivery location, credit quality of the Company and of derivative counterparties, credit enhancements, if any, and time value.

Interest rate swaps — Interest rate swaps are valued utilizing quotes received directly from swap counterparties. Key inputs and assumptions include interest rate curves, credit quality of the Company and of derivative counterparties, credit enhancements, if any, and time value.

The fair value of the Company’s assets and liabilities that are measured at fair value on a recurring basis is summarized by level within the fair value hierarchy in the following tables.

	Balance at March 31, 2010
	Level 1		Level 2		Level 3		Total
	(in thousands)
Liabilities:
Commodity derivatives	$	—	$	37,247	$	—	$	37,247
Interest rate derivatives	—		5,951		—		5,951
Total	$	—	$	43,198	$	—	$	43,198

	Balance at June 30, 2009
	Level 1		Level 2		Level 3		Total
	(in thousands)
Assets:
Commodity derivatives	$	—	$	294	$	—	$	294
Total	$	—	$	294	$	—	$	294

Liabilities:
Commodity derivatives	$	—	$	39,992	$	—	$	39,992
Interest rate derivatives	—		8,303		—		8,303
Total	$	—	$	48,295	$	—	$	48,295

The Company has elected not to record the Fixed Rate Notes due 2014 or the Floating Rate Notes due 2011 at fair value. The aggregate principal amount of long-term debt recorded on the consolidated balance sheets, before original issue discount, is $73.7 million at March 31, 2010. Utilizing observable market data, the aggregate fair value of the Fixed Rate Notes due 2014 and the Floating Rate Notes due 2011 was approximately $55.3 million as of March 31, 2010.

Note 13. Commodity Supply Facility and Revolving Credit Facility

Commodity Supply Facility

In connection with the Restructuring consummated on September 22, 2009, the Revolving Credit Facility, Hedge Facility and various arrangements for the supply of natural gas and electricity were replaced by the Commodity Supply Facility. Under the Commodity Supply Facility, the primary obligors are Holdings’ two significant operating subsidiaries, MXenergy Inc. and MXenergy Electric Inc. All obligations under the Commodity Supply Facility are guaranteed by Holdings and its other domestic subsidiaries and are secured by a first priority lien on substantially all existing and future assets of Holdings and its domestic subsidiaries other than the Fixed Rate Notes Escrow Account described in Note 14. The maturity date of the Commodity Supply Facility is August 31, 2012, provided that RBS Sempra will have the right to extend such maturity date by one year in its sole discretion, if notice is provided by RBS Sempra no later than April 30, 2011.

The Commodity Supply Facility provides for the exclusive supply of physical (other than as needed for balancing) and financial natural gas and electricity, credit support (including letters of credit and guarantees) for certain collateral needs, cash advances for natural gas inventory and seasonal financing as needed, and associated hedging transactions in order to maintain the balanced trading book required by the Company’s risk management policies. The Commodity Supply Facility provides for certain volumetric fees for all natural gas and electricity purchases.

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The Commodity Supply Facility is governed by the separate ISDA Master Agreements for natural gas and electricity. On September 28, 2009, MXenergy Inc. and MXenergy Electric Inc. entered into amendments to the ISDA Master Agreements for natural gas and electricity, respectively, with the Company and certain of its subsidiaries, as guarantors, and RBS Sempra. Pursuant to the terms of these amendments, the definition of Adjusted Consolidated Tangible Net Worth in the ISDA Master Agreements was amended to exclude non-cash charges associated with any deferred tax valuation allowances. As of March 31, 2010, the Company was in compliance with all provisions of the ISDA Master Agreements.

In accordance with the terms of the ISDA Master Agreements, the Company is required to maintain a minimum collateral coverage ratio (the “Collateral Coverage Ratio”) of 1.25:1.00 for the months of October through March (inclusive) and 1.40:1.00 for any other calendar month. The Collateral Coverage Ratio is calculated as the ratio of: (1) certain assets of the Company, primarily including cash, amounts due from RBS Sempra representing the Company’s operating cash, accounts receivable from customers and LDCs and natural gas inventories; to (2) certain liabilities of the Company, primarily arising from exposure and/or amounts due to RBS Sempra (including amounts due for the purchase of natural gas and electricity, accrued but unpaid financing fees and settlements arising from derivative contracts).

As of March 31, 2010, the Company had a Collateral Coverage Ratio of approximately 2.34:1.00. The calculation of the Collateral Coverage Ratio as of March 31, 2010 reflected available liquidity of approximately $82.7 million. At March 31, 2010, the Company had no outstanding cash advances and had $39.2 million of letters of credit outstanding under the Commodity Supply Facility.

In connection with the Commodity Supply Facility, the Company must maintain a consolidated tangible net worth, as defined in the ISDA Master Agreements, of at least $60.0 million. As of March 31, 2010, the Company’s consolidated tangible net worth exceeded $60.0 million.

Provided that the Company is in compliance with the Collateral Coverage Ratio requirement, as described above, the Commodity Supply Facility provides for cash advances of up to $45.0 million to finance seasonal working capital requirements. These cash borrowings will accrue interest at the greater of: (1) RBS Sempra’s cost of funds plus 5%; or (2) LIBOR plus 5%. Outstanding credit support (e.g., letters of credit and/or guarantees) provided by RBS Sempra will accrue interest at LIBOR plus 3%, with a minimum rate of 4%, except that, if the cash held in certain collateral accounts exceeds all outstanding settlement payments under the Commodity Supply Facility by $27.0 million, interest will accrue at a reduced rate of 1% on the amount of outstanding credit support in excess of $27.0 million.

Under the supply terms of the Commodity Supply Facility, the Company has 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 the Company with respect to such third party transactions. Such transactions with third parties are subject to RBS Sempra approval, and to a requirement that the volumes of those transactions do not exceed certain annual limits specified in the agreements that govern the Commodity Supply Facility. In addition to the actual purchase price paid by RBS Sempra and certain related costs and expenses, the Company is charged a fee for such purchases.

Under the Commodity Supply Facility, the Company is obligated to purchase a minimum of 130,000,000 MMBtus of natural gas from RBS Sempra, for physical delivery in accordance with the following schedule: (1) 39,000,000 MMBtus during the first contract year; (2) 44,000,000 MMBtus during the second contract year; and (3) 47,000,000 MMBtus during the third contract year. In addition, the Company is obligated to purchase a minimum of 1,850,000 MWhrs of electricity from RBS Sempra, for physical delivery in accordance with the following schedule: (1) 500,000 MWhrs during the first contract year; (2) 650,000 MWhrs during the second contract year; and (3) 700,000 MWhrs during the third contract year. The estimated total value of these purchases will depend upon the market price of natural gas at the time of purchase. The Company will be obligated to pay a volumetric fee for any unused balance of the minimum volume purchase requirement for any contract year, or if the agreement is terminated prior to the end of the contract. The excess of actual commodity purchases from RBS Sempra over the minimum purchase requirement for any contract year, if any, will be deducted from the minimum purchase requirement for the subsequent contract year. As of March 31, 2010, the commodity to be purchased for delivery to the Company’s customers during the first contract year of the Commodity Supply Facility is expected to exceed the minimum purchase obligation for natural gas and electricity.

The Commodity Supply Facility provides that the Company will release natural gas transportation and delivery capacity to RBS Sempra and for RBS Sempra to perform certain transportation and storage nominations. The

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Commodity Supply Facility also provides for RBS Sempra to act on the Company’s behalf to satisfy the requirements of regional electricity transmission operators for capacity rights and ancillary services.

Under the hedging terms of the Commodity Supply Facility, the Company’s aggregate outstanding notional amount of fixed price physical and/or financial hedges is limited to $260.0 million. Fixed price hedges are limited to a contract term of 24 months. In addition, the fixed price portfolio of hedges is limited to a weighted-average volume tenor not to exceed 14 months in duration. As of March 31, 2010, the Company was in compliance with each of these requirements.

With regards to the Company’s fixed price customer mix, the Company may not enter into any fixed price contracts, excluding renewals of existing fixed price contracts, if:

· During any twelve-month period, more than 75% of all residential customer equivalents (“RCEs”) have been added under fixed price contracts;

· During any twelve-month period, more than 235,000 RCEs have been added under fixed price contracts; and

· The Company’s fixed price RCEs exceed 325,000 at any time.

In connection with the Commodity Supply Facility, during the nine months ended March 31, 2010, certain of the Company’s natural gas hedge agreements under the former Hedge Facility and all of the Company’s existing electricity swap agreements with other counterparties were novated to RBS Sempra. Additionally, certain of the Company’s forward physical agreements for the purchase of natural gas and all of the Company’s forward physical agreements for the purchase of electricity were novated to RBS Sempra. Such novations did not have any impact on the Company’s rights, obligations, risks or accounting methodology associated with the agreements.

During fiscal years 2009 and 2010, the Company incurred approximately $10.7 million of legal fees, consulting fees and other costs directly related to the Commodity Supply Facility, which were deferred on the consolidated balance sheet and are being amortized as an increase to interest expense over the remaining term of the Commodity Supply Facility. These deferred costs include the value of 4,002,290 shares of Class B Common Stock issued to RBS Sempra in connection with the Restructuring (refer to Note 16). Amortization expense associated with these deferred costs was approximately $0.9 million and $1.9 million for the three months and nine months ended March 31, 2010, respectively.

The ISDA Master Agreements contain customary covenants that restrict certain activities including, among other things, the Company’s ability to:

· incur additional indebtedness;

· create or incur liens;

· guarantee obligations of other parties;

· engage in mergers, consolidations, liquidations and dissolutions;

· create subsidiaries;

· make acquisitions;

· engage in certain asset sales;

· enter into leases or sale-leasebacks;

· make equity distributions;

· make capital expenditures;

· make loans and investments;

· make certain dividend, debt and other restricted payments;

· engage in a different line of business;

· amend, modify or terminate certain material agreements in a manner that is adverse to the lenders; and

· engage in certain transactions with affiliates.

The ISDA Master Agreements also contain customary events of default, including:

· payment defaults;

· breaches of representations and warranties;

· covenant defaults;

· cross defaults to certain other indebtedness (including the Fixed Rate Notes due 2014) in excess of specified amounts;

· certain events of bankruptcy and insolvency;

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· ERISA defaults;

· judgments in excess of specified amounts;

· failure of any guaranty or security document supporting the Commodity Supply Facility to be in full force and effect;

· the termination or cancellation of any material contract which termination or cancellation could reasonably be expected to have a material adverse effect on us; or

· the occurrence of a change of control.

Net Accounts Receivable from or Payable to RBS Sempra

The agreements that govern the Commodity Supply Facility include provisions that allow for net settlement of amounts due from and due to RBS Sempra. Accordingly, the Company reports amounts due from and due to RBS Sempra net on the consolidated balance sheets. At March 31, 2010, the net $15.0 million amount due from RBS Sempra is reported as accounts receivable, net — RBS Sempra on the condensed consolidated balance sheets.

Revolving Credit Facility

As of June 30, 2009, and through September 21, 2009, MXenergy Inc. and MXenergy Electric Inc. were borrowers under the Revolving Credit Facility. During fiscal year 2009 and through September 30, 2009, the Company incurred approximately $9.1 million of amendment fees, legal fees, consulting fees and other costs directly related to amendments to the Revolving Credit Facility and Hedge Facility, which were deferred on the consolidated balance sheet and amortized as an increase in interest expense over the remaining terms of the facilities. Amortization expense associated with these deferred costs was approximately $0 and $2.2 million during the three months ended March 31, 2010 and 2009, respectively, and $1.6 million and $4.4 million for the nine months ended March 31, 2010 and 2009, respectively.

Note 14. Long-Term Debt

Long-term debt is summarized in the following table.

	Balance at
	March 31, 2010		June 30, 2009
	(in thousands)
Fixed Rate Notes due 2014 (net of unamortized original issue discount of $15,833)	$	51,460	$	—
Floating Rate Notes due 2011 (net of unamortized original issue discount of $43 and $1,724, respectively)	6,370		163,476
Total long-term debt	$	57,830	$	163,476

Fixed Rate Notes due 2014

In connection with the Restructuring consummated on September 22, 2009, the Company issued $67.8 million aggregate principal amount of the Fixed Rate Notes due 2014. Interest on the Fixed Rate Notes due 2014 accrues at the rate of 13.25% per annum and is payable semi-annually in cash on February 1 and August 1 of each year. The Fixed Rate Notes due 2014 will mature on August 1, 2014. Interest expense associated with the Fixed Rate Notes due 2014 was approximately $2.2 million and $4.7 million for the three months and nine months ended March 31, 2010, respectively.

The Fixed Rate Notes due 2014 were issued at a discount of approximately $17.8 million, which was recorded as a reduction from the Fixed Rate Notes due 2014 balance on the Company’s consolidated balance sheets during the first quarter of fiscal year 2010, and which is being amortized as an increase to interest expense over the remaining life of the Fixed Rate Notes due 2014. Total interest expense associated with amortization of this discount was approximately $1.1 million and $2.1 million for the three months and nine months ended March 31, 2010, respectively.

The Company incurred approximately $5.3 million of legal fees, consulting fees and other costs directly related to issuance of the Fixed Rate Notes due 2014, which were recorded as deferred debt issue costs on the consolidated balance sheets and are being amortized as an increase to interest expense over the remaining term of the Fixed

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Rate Notes due 2014. Total interest expense associated with amortization of these deferred debt issue costs was approximately $0.3 million and $0.6 million for the three months and nine months ended March 31, 2010, respectively.

On December 30, 2009, the Company entered into a purchase agreement (the “Stock and Notes Purchase Agreement”) pursuant to which a holder of the Company’s Class A Common Stock and Fixed Rate Notes due 2014 (the “Seller”) agreed to sell its holdings to the Company. Pursuant to the Stock and Notes Purchase Agreement, on January 4, 2010, the Company acquired approximately $0.5 million aggregate principal amount of Fixed Rate Notes due 2014 from the Seller for approximately $0.3 million. The resulting gain on extinguishment of debt of $0.2 million was recorded as a reduction of interest expense for the three months ended March 31, 2010. A pro rata portion of deferred debt issue costs and original debt issue discount associated with the Fixed Rate Notes due 2014 acquired, which approximated an aggregate amount of $0.1 million, was also recorded as additional interest expense during the three months ended March 31, 2010.

The Fixed Rate Notes due 2014 are senior subordinated secured obligations of the Company, subordinated in right of payment to obligations of the Company under the Commodity Supply Facility. The Fixed Rate Notes due 2014 are senior in priority to the Company’s unsecured senior obligations, including the Floating Rate Notes due 2011, to the extent of the aggregate value of the assets securing the Fixed Rate Notes due 2014 that is in excess of the aggregate amount of the outstanding Commodity Supply Facility obligations.

The Fixed Rate Notes due 2014 are jointly, severally, fully and unconditionally guaranteed by all domestic subsidiaries of Holdings.

The Fixed Rate Notes due 2014 are secured by a first priority security interest in an escrow account (the “Fixed Rate Notes Escrow Account”), which is maintained as security for future interest payments to holders of the Fixed Rate Notes due 2014, and by a second priority security interest in substantially all other existing and future assets of the Company. The Fixed Rate Notes Escrow Account was funded with approximately $9.0 million in September 2009, which approximates the interest payable by the Company on the Fixed Rate Notes due 2014 for a twelve-month period.

At any time on or prior to August 1, 2011, the Company may, at its option, use the net cash proceeds of equity offerings, if any, to redeem either: (1) 100% of the aggregate principal amount of outstanding Fixed Rate Notes due 2014; or (2) up to 35% of the aggregate principal amount of outstanding Fixed Rate Notes due 2014, in each case at a redemption price of 113.250% of the principal amount thereof, plus accrued and unpaid interest thereon, if any, to the date of redemption, provided that:

· if the Company redeems less than all of the Fixed Rate Notes due 2014, at least 65% of the principal amount of the Fixed Rate Notes due 2014 issued under the indenture governing them remains outstanding immediately after any such redemption; and

· the Company makes such redemption not more than 90 days after the consummation of any such equity offering.

After August 1, 2011, the Company may redeem the Fixed Rate Notes due 2014 at its option, in whole or in part, upon not less than 30 days’ or more than 60 days’ notice, at the redemption prices specified in the indenture that governs the Fixed Rate Notes due 2014.

Upon a change of control of the Company, the Company would be required to make an offer to purchase each holder’s Fixed Rate Notes due 2014 at a price of 101% of the then outstanding principal amount thereof, plus accrued and unpaid interest.

The indenture that governs the Fixed Rate Notes due 2014 contains restrictions on Holdings and its subsidiaries with regard to declaring or paying any dividend or distribution on Holdings capital stock. As of March 31, 2010, the Company was in compliance with all provisions of the indenture governing the Fixed Rate Notes due 2014.

Holdings has no significant independent operations. Each of Holdings’ domestic subsidiaries jointly and severally, fully and unconditionally guarantees the Fixed Rate Notes due 2014. Refer to Note 20 for consolidating financial statements of Holdings and its guarantor and non-guarantor subsidiaries.

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Floating Rate Notes due 2011

During fiscal years 2007 and 2008, the Company purchased $24.8 million aggregate principal amount of Floating Rate Notes due 2011 outstanding, plus accrued interest, from noteholders for amounts less than face value. On September 22, 2009, the Company consummated an exchange offer of $158.8 million aggregate principal amount of outstanding Floating Rate Notes due 2011 for $26.7 million of cash, $67.8 million aggregate principal amount of Fixed Rate Notes due 2014 and 33,940,683 shares of newly authorized Class A Common Stock (refer to Note 16).

Holders of approximately $6.4 million aggregate principal amount of Floating Rate Notes due 2011 did not tender their notes pursuant to the Restructuring. These Floating Rate Notes due 2011 will remain outstanding until their maturity date in August 2011 unless acquired or retired by the Company sooner. The indenture governing the Floating Rate Notes due 2011 was amended to eliminate substantially all of the restrictive covenants and certain events of default from such indenture.

The interest rate on the Floating Rate Notes due 2011 was 7.88% and 9.13% at March 31, 2010 and June 30, 2009, respectively. The weighted-average interest rate was 8.07% and 9.65% for the three months ended March 31, 2010 and 2009, respectively, and was 8.39% and 10.31% for the nine months ended March 31, 2010 and 2009, respectively. Interest expense associated with the Floating Rate Notes due 2011 was $0.1 million and $4.0 million for the three months ended March 31, 2010 and 2009, respectively, and was $3.6 million and $13.0 million for the nine months ended March 31, 2010 and 2009, respectively.

Interest expense associated with amortization of original issue discount was less than $0.1 million and $0.2 million during the three months ended March 31, 2010 and 2009, respectively, and $1.7 million and $0.6 million during the nine months ended March 31, 2010 and 2009, respectively. Interest expense associated with amortization of deferred debt issue costs was less than $0.1 million and $0.2 million for the three months ended March 31, 2010 and 2009, respectively, and $0.3 million and $0.7 million for the nine months ended March 31, 2010 and 2009, respectively.

We have entered into interest rate swap agreements to economically hedge the floating rate interest expense on the Floating Rate Notes due 2011. Refer to Note 11 for additional information regarding the Company’s use of interest rate swaps.

Holdings has no significant independent operations. Each of Holdings’ domestic subsidiaries jointly and severally, fully and unconditionally guarantees the Floating Rate Notes due 2011. Refer to Note 20 for consolidating financial statements of Holdings and its guarantor and non-guarantor subsidiaries.

Note 15. Redeemable Convertible Preferred Stock

Prior to consummation of the Restructuring, Holdings was authorized to issue 5,000,000 shares of Preferred Stock. On June 30, 2004, MXenergy Inc. entered into a purchase agreement (the “Preferred Stock Purchase Agreement”) with affiliates of Charterhouse Group Inc. and Greenhill Capital Partners LLC (collectively, the “Preferred Investors”) to issue 1,451,310 shares of Preferred Stock at a purchase price of $21.36 per share.

As of June 30, 2009, the Company determined that the Preferred Stock was redeemable at the option of the Preferred Investors as a result of the redemption provisions included in the Preferred Stock Purchase Agreement. Therefore, the Preferred Stock was recorded outside of stockholders’ equity on the consolidated balance sheets at its estimated $54.6 million redemption value.

On September 22, 2009, all outstanding shares of Preferred Stock were exchanged for 11,862,551 shares of newly authorized Class C Common Stock, which represented 21.84% of the aggregate total shares of the Company’s common stock outstanding as of the consummation date of the Restructuring. The excess of the redemption value of the Preferred Stock over the aggregate fair value of common stock issued to the preferred shareholders was reclassified to stockholders’ equity on the consolidated balance sheets during the first quarter of fiscal year 2010. In connection with the Restructuring, Holdings filed an amended and restated Certificate of Incorporation that does not authorize any Preferred Stock.

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Note 16. Common Stock

Amendment and Restatement of Corporate Documents and Issuance of Common Stock

In connection with the Restructuring, on September 22, 2009, Holdings’ Certificate of Incorporation and Bylaws were amended and restated, and certain holders of common stock entered into a stockholders agreement (the “Stockholders Agreement”). These documents contain customary provisions, including, but not limited to, provisions relating to certain approval rights, preemptive rights, share transfer restrictions and rights of first refusal.

The amended and restated Certificate of Incorporation authorizes 200,000,000 shares of $0.01 par value common stock. The number of authorized shares and significant rights, as provided in the Stockholders Agreement, of each class of common stock include:

· 50,000,000 shares of Class A Common Stock. Holders of the Class A Common Stock are not subject to any transfer restrictions and are entitled to designate five directors to the Board of Directors, at least two of whom shall be independent and qualify as “financial experts.”

· 10,000,000 shares of Class B Common Stock. Shares of Class B Common Stock will convert to shares of Class C Common Stock if RBS Sempra sells any of its shares (subject to certain exceptions defined in the amended and restated Certificate of Incorporation) or if all of the Company’s obligations under the Commodity Supply Facility have been paid in full and all commitments pursuant to the Commodity Supply Facility have been terminated. RBS Sempra is entitled to designate one director to the Board of Directors.

· 40,000,000 shares of Class C Common Stock. Holders of Class C Common Stock who are current or former employees of the Company or any of its subsidiaries may not transfer their shares (except by will or in connection with customary estate planning) until the third anniversary of the closing date of the Restructuring and, in the case of shares acquired pursuant to the management incentive plan to be implemented by the Company (the “Management Incentive Plan”), as otherwise provided in the Management Incentive Plan. Transfers of shares of Class C Common Stock are subject to a right of first refusal in favor of the holders of shares of Class A Common Stock and holders of shares of Class B Common Stock. Holders of Class C Common Stock are entitled to nominate and elect two directors to the Board of Directors.

· 100,000,000 shares of Class D Common Stock, which will only be issued by Holdings if certain transactions specified in the amended and restated Certificate of Incorporation occur.

In connection with the Restructuring, Holdings issued the following shares of common stock:

· 33,940,683 shares of Class A Common Stock to holders of the Fixed Rate Notes due 2014, which represented 62.5% of the aggregate shares of common stock outstanding after the consummation of the Restructuring. The aggregate fair value of Class A Common Stock issued was approximately $82.1 million ($0.3 million par value, recorded as Class A Common Stock; and $81.8 million recorded as additional paid in capital on the consolidated balance sheets).

· 4,002,290 shares of Class B Common Stock to RBS Sempra, as a condition to the entry into the agreements governing the Commodity Supply Facility, which represented 7.37% of the aggregate shares of common stock outstanding after consummation of the Restructuring. The aggregate $9.0 million fair value of Class B Common Stock issued to RBS Sempra (par value of less than $0.1 million, recorded as Class B Common Stock; and $9.0 million recorded as additional paid in capital on the consolidated balance sheets) was recorded as deferred debt issue costs on the consolidated balance sheets during the first quarter of fiscal year 2010 and is being amortized as an increase to interest expense over the remaining term of the Commodity Supply Facility (refer to Note 13).

· 11,862,551 shares of Class C Common Stock to holders of Preferred Stock, which represented 21.84% of the aggregate shares of the common stock outstanding after consummation of the Restructuring. Prior to the Restructuring, the Preferred Stock was recorded at its estimated redemption value of $54.6 million on the consolidated balance sheets. The aggregate fair value of Class C Common Stock issued to holders of

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Preferred Stock was $28.7 million ($0.1 million par value, recorded as Class C Common Stock; and $28.6 million recorded as additional paid in capital on the consolidated balance sheets). The $25.9 million excess of redemption value of the Preferred Stock over the fair value of Class C Common Stock issued to the holders of Preferred Stock was recorded as a reduction of accumulated deficit on the consolidated balance sheets.

· 4,499,588 shares of Class C Common Stock to the remaining holders of Holdings’ common stock issued and outstanding prior to the consummation of the Restructuring, which represented 8.29% of the aggregate shares of common stock outstanding after the consummation of the Restructuring. All 4,681,219 shares of Holdings’ common stock issued and outstanding prior to the Restructuring were retired as a result of the transaction.

In connection with the Restructuring, the Company paid approximately $0.3 million of legal fees, consulting fees and other costs directly related to the issuance of shares of common stock outlined above, which were recorded as a reduction of additional paid in capital during the three months ended September 30, 2009.

Class A Treasury Stock

Pursuant to the Stock and Notes Purchase Agreement, on December 30, 2009, the Company acquired 229,781 shares of its Class A Common Stock from the Seller for approximately $0.1 million. As of March 31, 2010, Company does not intend to retire the outstanding shares of Class A Treasury Stock.

Stock-Based Compensation Plans

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

As of June 30, 2009, the Company had three active stock-based compensation plans under which warrants and options (collectively referred to as “awards”) have been granted to employees, directors and other non-employees. As of June 30, 2009, the Company had options and warrants outstanding which were, or may have been, exercisable for 1,008,770 shares of common stock. The vast majority of these options and all of the warrants were “out of the money” as of the consummation date of the Restructuring (i.e., the agreed-upon price for which the option/warrant holder may purchase the Company’s common stock exceeded the current fair value of the common stock). In connection with the Restructuring, the Company terminated its three existing stock-based compensation plans and offered cash settlements to holders of options and warrants in exchange for their agreement to cancel and terminate such options and warrants. As a result, all outstanding options and warrants as of June 30, 2009 were cancelled and terminated in connection with the Restructuring. The total amount required for such cash settlement payments was approximately $0.2 million, which was recorded as general and administrative expense during the three months ended September 30, 2009.

In connection with the Restructuring, as agreed to by the shareholders, in January 2010, Holdings’ Board of Directors authorized the creation of the MXenergy Holdings Inc. 2010 Stock Incentive Plan (the “2010 SIP”), pursuant to which the Company may issue Class C Common Stock not to exceed 10% of Holdings’ outstanding common stock (on a fully diluted basis) after giving effect to the Restructuring. Also in January 2010, Holdings’ Board of Directors approved grants of RSUs to certain senior executive officers, Directors and a former Director, pursuant to which the Company may issue approximately 2.9 million shares of Class C Common Stock, subject to prescribed vesting requirements. During the three months ended March 31, 2010, the Company recorded approximately $1.1 million of compensation expense in connection with the RSUs and issued 22,959 shares of Class C Common Stock to directors when a portion of their RSUs vested without restrictions.

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Note 17. Related Party Transactions

Amounts paid or accrued to related parties are summarized in the following table.

	Three Months ended March 31,				Nine Months ended March 31,
	2010		2009		2010		2009
	(in thousands)
Amount paid or accrued for:
Legal services	$	290	$	219	$	2,239	$	844
Financial advisory services	—		150		32		225
Management fees	30		66		97		199
Interest expense — Denham Credit Facility	—		266		246		544
Interest expense — Bridge Financing Loans	—		1,840		197		2,041

Legal Services

A former director and current stockholder of the Company is senior counsel to Paul, Hastings, Janofsky & Walker LLP (“Paul Hastings”), a law firm that provides legal services to the Company. Paul Hastings provides the Company with general legal services, which are recorded as general and administrative expenses, and has provided legal services associated with the Restructuring and amendments to the Revolving Credit Facility and Hedge Facility, which were deferred on the consolidated balance sheets, to be amortized over the estimated useful lives associated with the related agreements. Paul Hastings is expected to continue to provide legal services to the Company in future periods.

Financial Advisory Services

Prior to the consummation of the Restructuring, the Company had a financial advisory services agreement with Greenhill & Co., LLC (“Greenhill”), an affiliate of Greenhill Capital Partners, a significant stockholder of the Company (the “Greenhill Agreement”). Under the Greenhill Agreement, Greenhill provided advisory services in connection with the Restructuring, which were recorded as general and administrative expenses during the respective periods. The Greenhill Agreement was terminated effective September 22, 2009.

Management Fees

Prior to the consummation of the Restructuring, the Company had agreed to pay Denham, Daniel Bergstein, a former director of Holdings, and Charter Mx LLC, another significant stockholder of the Company, aggregate annual fees of $0.9 million, for management consulting services provided to the Company. Fees associated with these arrangements were recorded as general and administrative expenses on the consolidated statements of operations. These management consulting services arrangements were terminated effective September 22, 2009.

Effective September 23, 2009, the Company agreed to pay Daniel Bergstein annual fees of $50,000 for management consulting services provided to the Company. Fees associated with this arrangement are recorded as general and administrative expenses. In addition, the Company granted RSUs to Mr. Bergstein in January 2010, pursuant to which the Company will record $25,000 of compensation expense ratably from January 15, 2010 through October 1, 2010.

Interest Expense — Denham Credit Facility

Denham is a significant stockholder of the Company. As of June 30, 2009, the Company had borrowed the entire $12.0 million available line under the Denham Credit Facility, which bore interest at 9% per annum. In connection with the Restructuring, the entire outstanding balance under the Denham Credit Facility was repaid, including accrued and unpaid interest, and the facility was terminated on September 22, 2009.

Interest Expense — Bridge Financing Loans

Pursuant to the Revolving Credit Agreement, in November 2008, Charter Mx LLC, Denham and four members of the Company’s senior management team agreed to provide Bridge Financing Loans in an aggregate amount of $10.4 million by becoming lenders in a new bridge loan tranche under the Amended Revolving Credit Agreement.

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Bridge Financing Loan amounts were as follows: (1) $5.0 million each from Charter Mx LLC and Denham; and (2) $0.1 million each from the Company’s Chief Executive Officer, former Chief Operating Officer, Executive Vice President and Chief Financial Officer. An upfront fee of 2% of the respective loan amount was paid to each Bridge Financing Loans lender upon closing. Interest accrued to each Bridge Financing Loans as follows: (1) 16% per annum from the closing date through April 6, 2009; (2) 18% per annum from April 7, 2009 through July 6, 2009; (3) 20% per annum from July 7, 2009 through October 6, 2009; and (4) 22% per annum thereafter until the Bridge Financing Loans were repaid.

The Bridge Financing Loan from Charter Mx LLC was repaid, with accrued interest, in April 2009. The remaining Bridge Financing Loans from all other lenders were repaid, with accrued interest, in connection with the Restructuring.

Note 18. Commitments and Contingencies

Capacity Commitments

As of June 30, 2009, the Company had entered into agreements to transport and store natural gas. Since the demand for natural gas in the winter is high, the Company agreed to pay for certain capacity on the transportation systems utilized for up to a twelve-month period. These take-or-pay agreements obligate the Company to pay for the capacity committed even if it does not use the capacity. For contracts outstanding as of June 30, 2009, the total committed capacity charges were approximately $6.6 million. These agreements generally were due to expire during various months during the fiscal year ending June 30, 2010, and would have been replaced with new contracts as necessary.

The terms of the ISDA Master Agreements require that the Company release natural gas transportation and delivery capacity to RBS Sempra and for RBS Sempra to perform certain transportation and storage nominations. During fiscal year 2010, the Company 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. Under the terms of the ISDA Master Agreements, the Company is obligated to reimburse RBS Sempra for various direct costs associated with transportation and storage capacity that RBS Sempra is managing on the Company’s behalf.

Physical Commodity Purchase Commitments

The Commodity Supply Facility provides for the exclusive supply of physical natural gas and electricity, other than as needed for balancing purposes for the Company’s required balanced book of commodity and related hedging activity. Under the Commodity Supply Facility, the Company is obligated to purchase a minimum of 130,000,000 MMBtus of natural gas from RBS Sempra, for physical delivery in accordance with the following schedule: (1) 39,000,000 MMBtus during the first contract year; (2) 44,000,000 MMBtus during the second contract year; and (3) 47,000,000 MMBtus during the third contract year. In addition, the Company is obligated to purchase a minimum of 1,850,000 MWhrs of electricity from RBS Sempra, for physical delivery in accordance with the following schedule: (1) 500,000 MWhrs during the first contract year; (2) 650,000 MWhrs during the second contract year; and (3) 700,000 MWhrs during the third contract year. The Company will be obligated to pay a volumetric fee for any unused balance of the minimum volume purchase requirement for any contract year, or if the agreement is terminated prior to the end of the contract. The excess of actual commodity purchases from RBS Sempra over the minimum purchase requirement for any contract year, if any, will be deducted from the minimum purchase requirement for the subsequent contract year. As of March 31, 2010, commodity expected to be purchased by the Company for delivery to its customers during the first contract year of the Commodity Supply Facility is expected to exceed the minimum purchase obligations for both natural gas and electricity.

Additionally, in connection with RBS Sempra’s responsibility to manage the Company’s storage capacity under the Commodity Supply Facility, during the nine months ended March 31, 2010, the Company sold approximately 2.2 million MMBtus of natural gas inventory to RBS Sempra for its weighted-average cost of $12.0 million, which more than offset normal seasonal activity to increase storage inventory in anticipation of customer demand for the upcoming winter season. Under the terms of the Commodity Supply Facility, the Company is required to re-acquire such natural gas from RBS Sempra as necessary to meet customer demand during the upcoming winter months for the price at which the inventory was sold to RBS Sempra. The Company has executed physical forward natural gas purchase contracts with RBS Sempra to comply with this requirement. The value of such contracts is included in unrealized gains and losses from risk management activities on the consolidated balance sheets.

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Legal Proceedings and Environmental Matters

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

The Company does 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. In addition, title to the natural gas sold to customers is passed at the same point at which the Company accepts title from its natural gas suppliers. Therefore, the Company does not believe that it has significant exposure to legal claims or other liabilities associated with environmental concerns.

Note 19. Business Segments

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

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

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Three Months Ended March 31,	Natural Gas			Electricity			Total
	(in thousands)
2010:
Sales	$	208,253		$	25,383		$	233,636
Cost of goods sold (excluding unrealized gains (losses) from risk management activities, net) (1)	(146,595		)	(19,671		)	(166,266		)
Gross profit (excluding unrealized gains (losses) from risk management activities, net) (1)	$	61,658		$	5,712		67,370

Add (less) items to reconcile total segment gross profit to income before income tax expense:
Unrealized gains (losses) from risk management activities, net							(26,001		)
Operating expenses							(24,768		)
Interest expense, net of interest income							(7,778		)
Income before income tax benefit							$	8,823

Assets and liabilities allocated to business segments at period end:
Accounts receivable, net	$	86,660		$	12,980		$	99,640
Natural gas inventories	6,625			—			6,625
Goodwill	3,810			—			3,810
Customer acquisition costs, net	17,392			8,731			26,123
Total assets allocated to business segments	$	114,487		$	21,711		$	136,198

2009:
Sales	$	279,351		$	25,757		$	305,108
Cost of goods sold (excluding unrealized gains (losses) from risk management activities, net) (1)	(216,707		)	(19,114		)	(235,821		)
Gross profit (excluding unrealized gains (losses) from risk management activities, net) (1)	$	62,644		$	6,643		69,287

Add (less) items to reconcile total segment gross profit to income before income tax expense:
Unrealized gains (losses) from risk management activities, net							(11,462		)
Operating expenses							(30,855		)
Interest expense, net of interest income							(12,244		)
Loss before income tax benefit							$	14,726

Assets and liabilities allocated to business segments at period end:
Accounts receivable	$	124,627		$	11,477		$	136,104
Natural gas inventories	15,647			—			15,647
Goodwill	3,810			—			3,810
Customer acquisition costs, net	24,803			6,739			31,542
Total assets allocated to business segments	$	168,887		$	18,216		$	187,103

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

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Nine Months Ended March 31,	Natural Gas			Electricity			Total
	(in thousands)
2010:
Sales	$	393,817		$	68,560		$	462,377
Cost of goods sold (excluding unrealized gains (losses) from risk management activities, net) (1)	(293,839		)	(52,329		)	(346,168		)
Gross profit (excluding unrealized gains (losses) from risk management activities, net) (1)	$	99,978		$	16,231		116,209

Add (less) items to reconcile total segment gross profit to income before income tax expense:
Unrealized gains (losses) from risk management activities, net							2,451
Operating expenses							(67,133		)
Interest expense, net of interest income							(28,942		)
Income before income tax benefit							$	22,585

2009:
Sales	$	589,780		$	97,593		$	687,373
Cost of goods sold (excluding unrealized gains (losses) from risk management activities, net) (1)	(498,200		)	(80,382		)	(578,582		)
Gross profit (excluding unrealized gains (losses) from risk management activities, net) (1)	$	91,580		$	17,211		108,791

Add (less) items to reconcile total segment gross profit to income before income tax expense:
Unrealized gains (losses) from risk management activities, net							(113,396		)
Operating expenses							(83,290		)
Interest expense, net of interest income							(34,604		)
Loss before income tax benefit							$	(122,499	)

Note 20. Condensed Consolidating Financial Information

Each of the following wholly owned domestic subsidiaries of Holdings (the “Guarantor Subsidiaries”) jointly, severally and unconditionally guarantee the Fixed Rate Notes due 2014 on a senior secured basis and the Floating Rate Notes due 2011 on a senior unsecured basis:

· MXenergy Capital Holdings Corp.

· MXenergy Capital Corp.

· Online Choice Inc.

· MXenergy Gas Capital Holdings Corp.

· MXenergy Gas Capital Corp.

· MXenergy Inc.

· MXenergy Electric Capital Holdings Corp.

· MXenergy Electric Capital Corp.

· MXenergy Electric Inc.

· MXenergy Services Inc.

· Infometer.com Inc.

The only wholly owned subsidiary that is not a guarantor for the Fixed Rate Notes due 2014 and Floating Rate Notes due 2011 (the “Non-guarantor Subsidiary”) is MXenergy (Canada) Ltd.

Consolidating balance sheets, consolidating statements of operations and consolidating statements of cash flows for Holdings, the combined Guarantor Subsidiaries and the Non-guarantor Subsidiary are provided in the following tables. Elimination entries necessary to consolidate the entities are also presented.

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MXENERGY HOLDINGS INC.

Consolidating Balance Sheet

March 31, 2010

(in thousands)

	MXenergy Holdings Inc.			Non-guarantor Subsidiary			Guarantor Subsidiaries			Eliminations			Consolidated

Assets
Current assets:
Cash and cash equivalents	$	—		$	358		$	2,495		$	—		$	2,853
Restricted cash	—			—			2,748			—			2,748
Intercompany accounts receivable	105,989			—			—			(105,989		)	—
Accounts receivable, net	—			50			99,590			—			99,640
Accounts receivable, net — RBS Sempra	—			—			14,700			—			14,700
Natural gas inventories	—			—			6,625			—			6,625
Income taxes receivable	—			—			7,185			—			7,185
Deferred income taxes	—			—			4,674			—			4,674
Fixed Rate Notes Escrow Account	8,977			—			—			—			8,977
Other current assets	13			144			17,177			—			17,334
Total current assets	114,979			552			155,194			(105,989		)	164,736
Goodwill	—			—			3,810			—			3,810
Customer acquisition costs, net	—			6			26,117			—			26,123
Fixed assets, net	—			1			2,390			—			2,391
Deferred income taxes	—			—			10,097			—			10,097
Deferred debt issue costs	—			—			13,754			—			13,754
Intercompany notes receivable	73,706			—			—			(73,706		)	—
Investment in subsidiaries	(43,526		)	—			—			43,526			—
Other assets	—			52			489			—			541
Total assets	$	145,159		$	611		$	211,851		$	(136,169	)	$	221,452

Liabilities and stockholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	28		$	338		$	31,152		$	—		$	31,518
Intercompany accounts payable	—			1,719			104,270			(105,989		)	—
Current portion of unrealized losses from risk management activities, net	—			—			39,006			—			39,006
Deferred revenue	—			—			1,605			—			1,605
Total current liabilities	28			2,057			176,033			(105,989		)	72,129
Unrealized losses from risk management activities, net	—			—			4,192			—			4,192
Long-term debt	57,830			—			—			—			57,830
Intercompany notes payable	—			—			73,706			(73,706		)	—
Total liabilities	57,858			2,057			253,931			(179,695		)	134,151

Commitments and contingencies	—			—			—			—			—

Stockholders’ equity (deficit):
Class A Common Stock	339			—			—			—			339
Class B Common Stock	40			—			—			—			40
Class C Common Stock	164			—			—			—			164
Common stock	—			1			—			(1		)	—
Additional paid-in-capital	138,348			—			—			—			138,348
Class A Treasury stock	(99		)	—			—			—			(99		)
Accumulated other comprehensive loss	(196		)	(196		)	—			196			(196		)
Accumulative deficit	(51,295		)	(1,251		)	(42,080		)	43,331			(51,295		)
Total stockholders’ equity	87,301			(1,446		)	(42,080		)	43,526			87,301
Total liabilities and stockholders’ equity	$	145,159		$	611		$	211,851		$	(136,169	)	$	221,452

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MXENERGY HOLDINGS INC.

Consolidating Balance Sheet

June 30, 2009

(in thousands)

	MXenergy Holdings Inc.			Non-guarantor Subsidiary			Guarantor Subsidiaries			Eliminations			Consolidated

Assets:
Current assets:
Cash and cash equivalents	$	—		$	262		$	23,004		$	—		$	23,266
Restricted cash	—			—			75,368			—			75,368
Intercompany accounts receivable	20,939			—			—			(20,939		)	—
Accounts receivable, net	—			56			47,542			—			47,598
Natural gas inventories	—			—			29,415			—			29,415
Current portion of unrealized gains from risk management activities, net	—			—			294			—			294
Income taxes receivable	—			—			6,461			—			6,461
Deferred income taxes	—			—			9,020			—			9,020
Other current assets	—			87			11,997			—			12,084
Total current assets	20,939			405			203,101			(20,939		)	203,506

Goodwill	—			—			3,810			—			3,810
Customer acquisition costs, net	—			28			27,922			—			27,950
Fixed assets, net	—			1			3,727			—			3,728
Deferred income taxes	—			—			15,089			—			15,089
Deferred debt issue costs	—			—			4,475			—			4,475
Intercompany notes receivable	165,200			—			—			(165,200		)	—
Investment in subsidiaries	(40,169		)	—			—			40,169			—
Other assets	—			—			513			—			513
Total assets	$	145,970		$	434		$	258,637		$	(145,970	)	$	259,071

Liabilities and stockholders’ equity:
Current liabilities:
Accounts payable and accrued liabilities	$	12		$	160		$	42,975		$	—		$	43,147
Intercompany accounts payable	—			1,845			19,094			(20,939		)	—
Current portion of unrealized losses from risk management activities, net	—			—			34,224			—			34,224
Deferred revenue	—			—			4,271			—			4,271
Bridge Financing loans payable	—			—			5,400			—			5,400
Denham Credit Facility	—			—			12,000			—			12,000
Total current liabilities	12			2,005			117,964			(20,939		)	99,042
Unrealized losses from risk management activities, net	—			—			14,071			—			14,071
Long-term debt	163,476			—			—			—			163,476
Intercompany notes payable	—			—			165,200			(165,200		)	—
Total liabilities	163,488			2,005			297,235			(186,139		)	276,589

Commitments and contingencies	—			—			—			—			—

Redeemable convertible preferred stock	54,632			—			—			—			54,632

Stockholders’ equity:
Common stock	47			1			—			(1		)	47
Additional paid-in-capital	18,275			—			—			—			18,275
Contributed capital	—			(1		)	24,386			(24,385		)	—
Accumulated other comprehensive loss	(3		)	(3		)	—			3			(3		)
Accumulated deficit	(90,469		)	(1,568		)	(62,984		)	64,552			(90,469		)
Total stockholders’ equity	(72,150		)	(1,571		)	(38,598		)	40,169			(72,150		)
Total liabilities and stockholders’ equity	$	145,970		$	434		$	258,637		$	(145,970	)	$	259,071

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MXENERGY HOLDINGS INC.

Consolidating Statement of Operations

For The Three Months Ended March 31, 2010 and 2009

(in thousands)

	Three Months Ended March 31, 2010
	MXenergy Holdings Inc.			Non-guarantor Subsidiary			Guarantor Subsidiaries			Eliminations			Consolidated

Sales of natural gas and electricity	$	—		$	141		$	233,495		$	—		$	233,636
Cost of goods sold (excluding depreciation and amortization):
Cost of natural gas and electricity sold	—			104			164,893			—			164,997
Realized losses from risk management activities	—			—			1,269			—			1,269
Unrealized losses from risk management activities	—			—			26,001			—			26,001
	—			104			192,163			—			192,267
Gross profit	—			37			41,332			—			41,369

Operating expenses:
General and administrative expenses	1,175			(16		)	13,295			—			14,454
Advertising and marketing expenses	—			—			1,707			—			1,707
Reserves and discounts	—			—			2,628			—			2,628
Depreciation and amortization	—			9			5,970			—			5,979
Equity in operations of consolidated subsidiaries	(6,435		)	—			—			6,435			—
Total operating expenses	(5,260		)	(7		)	23,600			6,435			24,768

Operating profit	5,260			44			17,732			(6,435		)	16,601
Interest expense, net	—			—			7,778			—			7,778
Income before income tax expense	5,260			44			9,954			(6,435		)	8,823
Income tax expense	—			—			(3,563		)	—			(3,563		)
Net income	$	5,260		$	44		$	6,391		$	(6,435	)	$	5,260

	Three Months Ended March 31, 2009
	MXenergy Holdings Inc.			Non-guarantor Subsidiary			Guarantor Subsidiaries			Eliminations			Consolidated

Sales of natural gas and electricity	$	—		$	168		$	304,940		$	—		$	305,108
Cost of goods sold (excluding depreciation and amortization):
Cost of natural gas and electricity sold	—			92			214,797			—			214,889
Realized losses from risk management activities	—			—			20,932			—			20,932
Unrealized losses from risk management activities	—			—			11,462			—			11,462
	—			92			247,191			—			247,283
Gross (loss) profit	—			76			57,749			—			57,825

Operating expenses:
General and administrative expenses	180			130			15,404			—			15,714
Advertising and marketing expenses	—			—			417			—			417
Reserves and discounts	—			—			4,415			—			4,415
Depreciation and amortization	—			7			10,302			—			10,309
Equity in operations of consolidated subsidiaries	(9,563		)	—			—			9,563			—
Total operating expenses	(9,383		)	137			30,538			9,563			30,855

Operating loss	9,383			(61		)	27,211			(9,563		)	26,970
Interest expense, net	—			—			12,244			—			12,244
Loss before income tax benefit	9,383			(61		)	14,967			(9,563		)	14,726
Income tax benefit	—			—			(5,343		)	—			(5,343		)
Net loss	$	9,383		$	(61	)	$	9,624		$	(9,563	)	$	9,383

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MXENERGY HOLDINGS INC.

Consolidating Statement of Operations

For The Nine Months Ended March 31, 2010 and 2009

(in thousands)

	Nine Months Ended March 31, 2010
	MXenergy Holdings Inc.			Non-guarantor Subsidiary			Guarantor Subsidiaries			Eliminations			Consolidated

Sales of natural gas and electricity	$	—		$	417		$	461,960		$	—		$	462,377
Cost of goods sold (excluding depreciation and amortization):
Cost of natural gas and electricity sold	—			236			311,428			—			311,664
Realized losses from risk management activities	—			—			34,504			—			34,504
Unrealized losses from risk management activities	—			—			(2,451		)	—			(2,451		)
	—			236			343,481			—			343,717
Gross profit	—			181			118,479			—			118,660
Operating expenses:
General and administrative expenses	1,231			(165		)	40,300			—			41,366
Advertising and marketing expenses	—			—			2,449			—			2,449
Reserves and discounts	—			—			6,443			—			6,443
Depreciation and amortization	—			25			16,850			—			16,875
Equity in operations of consolidated subsidiaries	(14,480		)	—			—			14,480			—
Total operating expenses	(13,249		)	(140		)	66,042			14,480			67,133

Operating profit	13,249			321			52,437			(14,480		)	51,527
Interest expense, net	—						28,942			—			28,942
Income before income tax expense	13,249			321			23,495			(14,480		)	22,585
Income tax expense	—			—			(9,336		)	—			(9,336		)
Net income	$	13,249		$	321		$	14,159		$	(14,480	)	$	13,249

	Nine Months Ended March 31, 2009
	MXenergy Holdings Inc.			Non-guarantor Subsidiary			Guarantor Subsidiaries			Eliminations			Consolidated

Sales of natural gas and electricity	$	—		$	203		$	687,170		$	—		$	687,373
Cost of goods sold (excluding depreciation and amortization):
Cost of natural gas and electricity sold	—			295			536,133			—			536,428
Realized losses from risk management activities	—			—			42,154			—			42,154
Unrealized losses from risk management activities	—			—			113,396			—			113,396
	—			295			691,683			—			691,978
Gross loss	—			(92		)	(4,513		)	—			(4,605		)
Operating expenses:
General and administrative expenses	278			634			42,749			—			43,661
Advertising and marketing expenses	—			—			1,694			—			1,694
Reserves and discounts	—			—			9,279			—			9,279
Depreciation and amortization	—			23			28,633			—			28,656
Equity in operations of consolidated subsidiaries	75,038			—			—			(75,038		)	—
Total operating expenses	75,316			657			82,355			(75,038		)	83,290

Operating loss	(75,316		)	(749		)	(86,868		)	75,038			(87,895		)
Interest expense, net	—			—			34,604			—			34,604
Loss before income tax benefit	(75,316		)	(749		)	(121,472		)	75,038			(122,499		)
Income tax benefit	—			—			47,183			—			47,183
Net loss	$	(75,316	)	$	(749	)	$	(74,289	)	$	75,038		$	(75,316	)

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MXENERGY HOLDINGS INC.

Consolidating Statement of Cash Flows

Nine Months Ended March 31, 2010

(in thousands)

	MXenergy Holdings Inc.			Non-guarantor Subsidiary			Guarantor Subsidiaries			Eliminations			Consolidated
Operating activities:
Net income	$	13,249		$	321		$	14,159		$	(14,480	)	$	13,249
Adjustments to reconcile net income to net cash provided by operating activities:
Unrealized gains from risk management activities	—			—			(2,451		)	—			(2,451		)
Stock compensation expense	1,009			—			—			—			1,009
Provision for doubtful accounts	—			—			4,661			—			4,661
Depreciation and amortization	—			—			16,875			—			16,875
Deferred tax expense (benefit)	—			—			9,338			—			9,338
Non-cash interest expense, primarily unrealized (gains) losses on interest rate swaps and amortization of debt issuance costs	—			—			7,975			—			7,975
Amortization of customer contracts acquired	—			25			(75		)	—			(50		)
Equity in operations of consolidated subsidiaries	(14,480		)	—			—			14,480			—
Changes in assets and liabilities:
Restricted cash	—			—			72,620			—			72,620
Accounts receivable	—			6			(56,709		)	—			(56,703		)
Due from Sempra	—			—			(14,700		)	—			(14,700		)
Natural gas inventories	—			—			22,790			—			22,790
Income taxes receivable	—			—			(724		)	—			(724		)
Fixed Rate Notes Escrow Account	(8,977		)	—			—			—			(8,977		)
Other assets	—			(252		)	(5,917		)	—			(6,169		)
Accounts payable and accrued liabilities	(16		)	52			(11,615		)	—			(11,579		)
Deferred revenue	—			—			(2,666		)	—			(2,666		)
Net cash provided by operating activities	(9,215		)	152			53,561			—			44,498

Investing activities:
Customer acquisition costs	—			(56		)	(13,110		)	—			(13,166		)
Purchases of fixed assets	—			—			(545		)	—			(545		)
Net cash used in investing activities	—			(56		)	(13,655		)	—			(13,711		)

Financing activities:
Repayment of Floating Rate Notes due 2011	(26,700		)	—			—			—			(26,700		)
Repayment of Floating Rate Notes due 2014	(423		)	—			—			—			(423		)
Repayment of Denham Credit Facility	—			—			(12,000		)	—			(12,000		)
Repayment of Bridge Financing under the Revolving Credit Facility	—			—			(5,400		)	—			(5,400		)
Net intercompany transfers	36,766			—			(36,766		)	—			—
Debt issuance costs	—			—			(6,249		)	—			(6,249		)
Acquisition of Class A treasury stock	(99		)	—			—			—			(99		)
Stock issuance costs	(329		)	—			—			—			(329		)
Net cash used in financing activities	9,215			—			(60,415		)	—			(51,200		)

Net increase (decrease) in cash and cash equivalents	—			96			(20,509		)	—			(20,413		)
Cash and cash equivalents at beginning of period	—			262			23,004			—			23,266
Cash and cash equivalents at end of period	$	—		$	358		$	2,495		$	—		$	2,853

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MXENERGY HOLDINGS INC.

Consolidating Statement of Cash Flows

Nine Months Ended March 31, 2009

(in thousands)

	MXenergy Holdings Inc.			Non-guarantor Subsidiary			Guarantor Subsidiaries			Eliminations			Consolidated
Operating activities:
Net loss	$	(75,316	)	$	(749	)	$	(74,289	)	$	75,038		$	(75,316	)
Adjustments to reconcile net loss to net cash used in operating activities:
Unrealized losses from risk management activities, net	—			—			98,269			—			98,269
Stock compensation expense	185			—			—			—			185
Provision for doubtful accounts	—			—			6,958			—			6,958
Depreciation and amortization	—			23			28,633			—			28,656
Deferred tax expense (benefit)	—			—			(50,830		)	—			(50,830		)
Non-cash interest expense, primarily unrealized (gains) losses on interest rate swaps and amortization of debt issuance costs	—			—			11,878			—			11,878
Amortization of customer contracts acquired	—			—			(620		)	—			(620		)
Equity in operations of consolidated subsidiaries	75,038			—			—			(75,038		)	—
Changes in assets and liabilities:
Restricted cash	—			—			197			—			197
Accounts receivable	—			(40		)	(55,349		)	—			(55,389		)
Natural gas inventories	—			—			50,277			—			50,277
Income taxes receivable	—			—			8,061			—			8,061
Other assets	—			551			(7,744		)	—			(7,193		)
Accounts payable and accrued liabilities	105			(695		)	(29,738		)	—			(30,328		)
Deferred revenue	—			—			(2,433		)	—			(2,433		)
Net cash used in operating activities	12			(910		)	(16,730		)	—			(17,628		)

Investing activities:
Purchase of assets of Catalyst Natural Gas LLC	—			—			(1,609		)	—			(1,609		)
Customer acquisition costs	—			90			(11,989		)	—			(11,899		)
Purchases of fixed assets	—			—			(744		)	—			(744		)
Net cash provided by (used in) investing activities	—			90			(14,342		)	—			(14,252		)

Financing activities:
Proceeds from Denham Credit Facility	—			—			12,000			—			12,000
Proceeds from Bridge Financing Loans under the Revolving Credit Facility	—			—			10,400			—			10,400
Proceeds from cash advances under the Revolving Credit Facility	—			—			30,000			—			30,000
Repayment of cash advances under the Revolving Credit Facility	—			—			(30,000		)	—			(30,000		)
Debt issuance costs	—			—			(7,218		)	—			(7,218		)
Purchase and cancellation of treasury shares	(12		)	—			—			—			(12		)
Net cash provided by financing activities	(12		)	—			15,182			—			15,170

Net decrease in cash and cash equivalents	—			(820		)	(15,890		)	—			(16,710		)
Cash and cash equivalents at beginning of period	—			970			70,988			—			71,958
Cash and cash equivalents at end of period	$	—		$	150		$	55,098		$	—		$	55,248

Note 21. Subsequent Events

The Company has evaluated subsequent events for the period from April 1, 2010 through the date on which these condensed consolidated financial statements were issued. Based upon this evaluation, other than described below, there were no material events or transactions during this period that required recognition or disclosure in these condensed consolidated financial statements.

In April 2010, the Company 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, the Company will receive a NYMEX-referenced wholesale price plus a retail price adjustment for natural gas delivered by the LDC to its customers. As of April 1, 2010, based upon estimates received directly from the LDC, the Company expects to deliver to the LDC approximately 11.0 million MMBtus of natural gas annually as a provider under the SSO Program.

Effective May 14, 2010, Carole R. (“Robi”) Artman-Hodge, the Company’s Executive Vice President, was no longer employed by the Company. The Company will pay Ms. Artman-Hodge approximately $1.3 million during the three months ended June 30, 2010, which includes a severance payment described in her employment agreement with the Company, dated as of April 1, 1999, and a pro rated bonus for fiscal year 2010.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A)

Definitions

References in this Quarterly 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. 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.

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EXECUTIVE OVERVIEW

Our income before income tax expense was $8.8 million for the three months ended March 31, 2010, which represented a $5.9 million decrease from our income before income tax expense of $14.7 million for the three months ended March 31, 2009. Lower gross profit was partially offset by lower operating expenses and lower interest expense.

Income before income tax expense was $22.6 million for the nine months ended March 31, 2010, which was $145.1 million higher than the loss before income tax benefit of $122.5 million for the same period in the prior fiscal year. Higher net income before income tax expense during fiscal year 2010 was primarily due to the positive comparative impact of changes in the market price of natural gas during the respective reporting periods. Significant decreases in market prices for natural gas during an unusually short period resulted in decreases in the market values of derivative instruments utilized as economic hedges to reduce our exposure to changes in natural gas prices resulted in significant unrealized losses from risk management activities included in cost of goods sold during the first nine months of fiscal year 2009.

Lower operating expenses and lower interest expense also contributed to improved operating results for the first nine months of fiscal year 2010.

We utilize a measure referred to as Adjusted EBITDA to evaluate our operating performance and liquidity position (see “Adjusted EBITDA” below). Adjusted EBITDA excludes interest, taxes, depreciation, amortization, stock compensation expense and unrealized (gains) losses from risk management activities. Adjusted EBITDA improved slightly to $49.7 million for the three months ended March 31, 2010, as compared with $48.9 million for the same period in the prior fiscal year. Adjusted EBITDA improved to $67.0 million for the nine months ended March 31, 2010, as compared with $54.3 million for the same period in the prior fiscal year. Significant activity affecting Adjusted EBITDA for the three months and nine months ended March 31, 2010 is summarized in the following table. The increases (decreases) reflected in the table are addressed below under “RESULTS OF OPERATIONS.”

	Three Months Ended March 31, 2010			Nine Months Ended March 31, 2010
	(in thousands)

Adjusted EBITDA for period ended March 31, 2009	$	48,883		$	54,342
Increases (decreases) in Adjusted EBITDA due to:
Higher (Lower) gross profit (excluding unrealized (gains) losses from risk management activities):
Natural gas	(986		)	8,398
Electricity	(931		)	(980		)
Lower operating expenses (excluding depreciation, amortization and stock compensation expense)	2,741			5,200
Adjusted EBITDA for period ended March 31, 2010	$	49,707		$	66,960

On September 22, 2009, we consummated a debt and equity restructuring (the “Restructuring”), which included various transactions (refer to “Debt and Equity Restructuring” section below). Management believes that the Restructuring has improved our financial and liquidity position, while eliminating operating constraints previously imposed on us under the Revolving Credit Facility and Hedge Facility. We now have a single partner for providing commodity supply, economic hedging instruments and necessary credit support for our natural gas and electricity businesses. We have developed a growth and marketing plan for the remainder of fiscal year 2010 that includes strategic initiatives within our current markets using our traditional marketing channels and new approaches to build brand awareness. In addition, we are identifying potential new markets to enter and will evaluate acquisition opportunities for customer portfolios that are consistent with our overall growth strategy, our operating and information systems environments, our risk management policy, and our supply, hedging and financing capabilities.

Adjusted EBITDA

Management believes that Adjusted EBITDA, which is not a financial measure recognized under accounting principles generally accepted in the United States (“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

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EBITDA, as used herein, is not necessarily comparable to similarly titled measures of other companies.

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

Management uses Adjusted EBITDA for a variety of purposes, including assessing our performance and liquidity, allocating our resources for operational initiatives (e.g., establishing margins on sales initiatives), allocating our resources for business growth strategies (e.g., considering acquisition opportunities), determining new marketing initiatives, determining 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 are 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. Some of these limitations are:

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

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

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

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

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

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

· Other companies, including other companies in our industry, may calculate these measures differently than as presented in this Quarterly 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.

Selected consolidated financial data and reconciliations of net income (loss) calculated in accordance with U.S. GAAP to EBITDA and Adjusted EBITDA for the three months and nine months ended March 31, 2010 are summarized in the following table. The financial data included in the following table was derived from our consolidated financial statements, which are included elsewhere in this Quarterly Report. 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.

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		Three Months Ended March 31,						Nine Months ended March 31,
		2010			2009			2010			2009
		(in thousands)

Sales of natural gas and electricity		$	233,636		$	305,108		$	462,377		$	687,373
Cost of goods sold		192,267			247,283			343,717			691,978
Gross profit (loss)		41,369			57,825			118,660			(4,605		)
Operating expenses		24,768			30,855			67,133			83,290
Operating income (loss)		16,601			26,970			51,527			(87,895		)
Interest expense, net of interest income		7,778			12,244			28,942			34,604
Income (loss) before income tax (expense) benefit		8,823			14,726			22,585			(122,499		)
Income tax (expense) benefit		(3,563		)	(5,343		)	(9,336		)	47,183
Net income (loss)		5,260			9,383			13,249			(75,316		)

Items to reconcile net income (loss) to EBITDA :
Add (less):	Interest expense, net of interest income	7,778			12,244			28,942			34,604
	Depreciation and amortization	5,979			10,309			16,875			28,656
	Income tax benefit (expense)	3,563			5,343			9,336			(47,183		)
EBITDA		22,580			37,279			68,402			(59,239		)

Items to reconcile EBITDA to Adjusted EBITDA:
Add (less):	Stock compensation expense	1,126			142			1,009			185
	Unrealized (gains) losses from risk management activities, net	26,001			11,462			(2,451		)	113,396
Adjusted EBITDA		$	49,707		$	48,883		$	66,960		$	54,342

Selected Operating Data

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

	Three Months Ended March 31,				Nine Months Ended March 31,
	2010		2009		2010		2009
Natural Gas:
RCEs at period end	438,000		520,000		438,000		520,000
Average RCEs during the period	439,000		542,000		456,000		572,000
MMBtus sold during the period	21,068,000		24,226,000		39,220,000		47,744,000
Sales per MMBtu sold during the period	$	9.88	$	11.53	$	10.04	$	12.35
Gross profit per MMBtu sold during the period	$	2.93	$	2.59	$	2.55	$	1.92
Heating degree days	2,456		2,343		4,101		4,030

Electricity:
RCEs at period end	130,000		74,000		130,000		74,000
Average RCEs during the period	106,000		82,000		87,000		92,000
MWhrs sold during the period	227,000		196,000		608,000		670,000
Sales per MWhr sold during the period	$	111.82	$	131.42	$	112.76	$	145.66
Gross profit per MWhr sold during the period	$	25.16	$	33.90	$	26.70	$	25.69
Cooling degree days	9		61		868		915

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

	Activity For the Twelve Months Ended
	March 31, 2010		December 31, 2009		September 30, 2009		June 30, 2009		March 31, 2009

Customer renewal percentage (1)	93	%	92	%	90	%	84	%	86	%
In-contract attrition percentage (2)	25	%	29	%	33	%	34	%	32	%

(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. The percentage is calculated for the twelve months preceding the period-end date.
(2)		In-contract customer attrition percentage is defined as: (1) the percentage of loss of fixed rate customers before their contract term officially expires; and (2) the percentage of loss of any variable rate customers, whose contracts generally do not have expiration dates. The percentage is calculated for the twelve months preceding the period-end date.

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.

Natural gas average RCEs declined 19% and 20% during the three months and nine months ended March 31, 2010, as compared with the same periods in the prior fiscal year. We experienced customer attrition over the twelve months ended March 31, 2010 that more than offset additions to our customer portfolio over the same period.

Electricity average RCEs increased 29% during the three months ended March 31, 2010 and declined 5% during the nine months ended March 31, 2010, as compared with the same periods in the prior fiscal year. Electricity RCEs include customers added as a result of our expansion into a new electricity market in Pennsylvania, effective in February 2010. Actual electricity RCEs at March 31, 2010 included approximately 32,000 RCEs in this new market. Excluding the customers within this new market, Electricity average RCEs within our existing markets increased 12% during the three months ended March 31, 2010 and declined 11% during the nine months ended March 31, 2010, as compared with the same periods in the prior fiscal year. During fiscal year 2010, we have focused on growth in our electricity customer portfolio in order to improve the seasonal cash flow associated with the electricity business segment and reduce risks associated with commodity and geographic concentrations.

During fiscal year 2009 and the first three months of fiscal year 2010, our marketing activities and hedging capabilities were constrained under our amended 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 resulted in credit-related attrition that was higher than historical levels during fiscal year 2009 and the first three months of fiscal year 2010. This was particularly the case in certain of our larger markets, where LDCs do not guarantee our customer accounts receivable, such as our Georgia natural gas and Texas electricity markets, and in certain LDC-guaranteed markets, such as our Ohio, Michigan and Indiana natural gas markets. During this period, we also initiated aggressive actions to disconnect service to delinquent customers in certain of our markets and to enhance credit standards for all existing and prospective customers. 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. Our enhanced credit standards also resulted in an increase in the number of potential new customers that were disqualified due to credit quality concerns. During the quarters ended December 31, 2009 and March 31, 2010, we experienced lower credit-related attrition due to a more stable credit environment in most of our markets.

During the final six months of the fiscal year ended June 30, 2008, natural gas commodity prices were increasing, and contract rates that we offered to our customers were highly competitive in many of our markets. We experienced significant sales of new customer contracts, particularly for fixed rate and introductory variable rate products, during that period and into the first quarter of fiscal year 2009. During the first nine months of fiscal year 2009 however, commodity prices decreased significantly, and many of our customers migrated to market rates that were lower than their original fixed rates or their post-

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introductory period variable rates with us. In addition, for many of our markets during fiscal year 2009 and the first quarter of fiscal year 2010, we could not offer new competitive rates to customers who indicated their intention to terminate their contract. The result was in-contract customer attrition during the twelve months ended September 30, 2009 that was incrementally higher than in-contract attrition experienced for the twelve months ended December 31, 2009 and March 31, 2010.

During fiscal year 2010, we have 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 lower in-contract attrition in most of our natural gas and electricity markets and customer growth in certain of our electricity markets.

Seasonality of Operations

Natural gas and electricity sales accounted for approximately 85% and 15%, respectively, of our total sales for the nine months ended March 31, 2010. 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 collections from natural gas customers peak in the spring of each calendar year, while cash collections from electricity customers peak 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.

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. In addition, budget billing programs and payment terms of LDCs can cause timing differences between the billing and collection of accounts receivable and the recording of revenues.

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 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.

Debt and Equity 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 our revolving credit facility (the “Revolving Credit Facility”). The reduced borrowing base strained our 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 our ratings from credit rating agencies and ultimately resulted in us obtaining material waivers of, and amendments to, the agreement that governed the Revolving Credit Facility and our principal commodity hedge facility (the “Hedge Facility”). Such amendments had material direct impacts on our 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, we consummated an equity and debt restructuring (the “Restructuring”), which included various transactions. The Restructuring included a debt exchange transaction that was accounted for as a troubled-debt restructuring in accordance with U.S. GAAP, and therefore did not result in any gain or loss recorded in the consolidated statements of operations. The transactions consummated in connection with the Restructuring had material impacts on various asset, liability and stockholders’ equity accounts, which are summarized in Note 3 of the condensed consolidated Financial Statements included in Part I, Item 1 of this Form 10-Q. Material sources and uses of cash and cash equivalents that resulted from the Restructuring are disclosed below under “RESULTS OF OPERATIONS — Liquidity and Capital Resources.”

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In connection with the Restructuring, we recorded approximately $2.2 million of non-recurring general and administrative expenses during the three months ended September 30, 2009, which are described in greater detail below under “RESULTS OF OPERATIONS — Operating Expenses.”

In connection with the Restructuring, the shareholders agreed to the creation of a new equity-based incentive plan, pursuant to which we may issue Class C Common Stock not to exceed 10% of Holdings’ outstanding common stock (on a fully diluted basis) after giving effect to the Restructuring. In January 2010, Holdings’ Board of Directors authorized a new plan and approved grants of restricted stock units to certain senior executive officers, the directors and a former director of the Company (refer to Note 16 of the consolidated financial statements included in Part I, Item I of this Form 10-Q).

New Accounting Pronouncements

New accounting pronouncements are summarized in Note 2 to the condensed consolidated financial statements included elsewhere in this Quarterly Report. Such disclosure is incorporated herein by reference.

Related Party Transactions

Transactions with related parties are summarized in Note 17 to the condensed consolidated financial statements included elsewhere in this Quarterly Report. Such disclosure is incorporated herein by reference.

Subsequent Events

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, we will receive a NYMEX-referenced wholesale price plus a retail price adjustment for natural gas delivered by the LDC to its customers. As of April 1, 2010, based upon estimates received directly from the LDC, we expect to deliver to the LDC approximately 11.0 million MMBtus of natural gas annually as a provider under the SSO Program.

RESULTS OF OPERATIONS

Our core business is the retail sale of natural gas and electricity to end-use customers. We offer various lengths of contracted service for fixed and variable price products and, in the case of natural gas, several other innovative pricing programs designed to cap prices or manage the risks of energy volatility. The positive difference between the sales price of energy to our customers and the sum of the wholesale cost of our energy supplies, hedging costs, transmission costs and ancillary services costs provides us with a gross profit margin.

Gross profit, excluding the impact of unrealized gains (losses) from risk management activities, is reported and analyzed by business segment. Other operating activity, including unrealized gains (losses) from risk management activities, operating expenses and interest expense, is monitored and reported at the corporate level and is not allocated to business segments.

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

Reconciliations of gross profit by business segment to net income (loss) before income tax (expense) benefit are disclosed in Note 19 to the condensed consolidated financial statements included elsewhere in this Quarterly Report.

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Gross Profit (Before Unrealized Gains (Losses) from Risk Management Activities, Net) by Business Segment

Gross profit (before unrealized gains (losses) from risk management activities, net) by business segment is summarized in the following table.

					2010 versus 2009 Increase (Decrease)
Business Segment	2010		2009		Amount			%
	($ in thousands)

Three months ended March 31:
Natural gas	$	61,658	$	62,644	$	(986	)	(2	)
Electricity	5,712		6,643		(931		)	(14	)
Total gross profit (before unrealized losses from risk management activities, net)	$	67,370	$	69,287	$	(1,917	)	(3	)

Nine months ended March 31:
Natural gas	$	99,978	$	91,580	$	8,398		9
Electricity	16,231		17,211		(980		)	(6	)
Total gross profit (before unrealized losses from risk management activities, net)	$	116,209	$	108,791	$	7,418		7

Natural Gas Gross Profit

Over the course of our fiscal year, natural gas gross profit is impacted by several factors, which include but are not limited to:

· The prices we charge our customers in relation to the cost of natural gas delivered to our customers;

· The volume of natural gas delivered to our customers, which is impacted by the number of customers that we serve, weather conditions in our markets, economic conditions and other factors that may affect customer usage;

· Volatility in the market price of natural gas that we purchase for delivery to our customers; and

· Results of our economic hedging policy which is intended to reduce our financial exposure related to changes in the price of natural gas.

Significant activity affecting natural gas gross profit (before unrealized (gains) losses from risk management activities, net) for the three months and nine months ended March 31, 2010 and 2009 is summarized in the following tables.

	Three Months Ended March 31,
	2010						2009
	Amount			Amount per MMBtu Sold			Amount			Amount per MMBtu Sold
	(in thousands)

Gross profit (before unrealized gains (losses) from risk management activities)	$	61,658		$	2.93		$	62,644		$	2.59
Add (less) the relative cost (benefit) during the period associated with commodity price volatility and economic hedging activity:
Weighted-average cost of gas methodology	485			0.02			(15,807		)	(0.65		)
Realized (gains) losses from risk management activities associated with natural gas inventory at end of period	(10,132		)	(0.48		)	(391		)	(0.02		)
	52,011			2.47			46,446			1.92
Fee income	(4,383		)	(0.21		)	(5,516		)	(0.23		)
Amount attributable to natural gas delivered to customers	$	47,628		$	2.26		$	40,930		$	1.69

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	Nine Months Ended March 31,
	2010						2009
	Amount			Amount per MMBtu Sold			Amount			Amount per MMBtu Sold
	(in thousands)

Gross profit (before unrealized gains (losses) from risk management activities)	$	99,978		$	2.55		$	91,580		$	1.92
Add (less) the relative cost (benefit) during the period associated with commodity price volatility and economic hedging activity:
Increase (decrease) in cost of sales from weighted-average cost of gas inventory valuation methodology	(797		)	(0.02		)	(3		)	—
Realized (gains) losses from risk management activities associated with natural gas inventory at end of period	(10,207		)	(0.26		)	2,996			0.06
	88,974			2.27			94,573			1.98
Fee income	(12,790		)	(0.33		)	(15,060		)	(0.32		)
Amount attributable to natural gas delivered to customers	$	76,184		$	1.94		$	79,513		$	1.66

Impact of Weighted Average Cost of Gas Inventory Valuation Methodology on Cost of Sales

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

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

The impacts described above on the weighted average cost of gas are more pronounced in periods where we inject storage gas and have an increase in storage volume from the beginning to the end of the period. Offsetting net increases or decreases in gross profit are generally realized in future periods as these inventories are sold.

Significantly lower market prices for natural gas during the six months ended December 31, 2008 reduced the carrying value of opening natural gas inventories that are economically hedged by customer contracts and/or derivative instruments and lowered our gross profit by approximately $15.8 million during the six months ended December 31, 2008. This impact was reversed during the three months ended March 31, 2009 as natural gas was consumed by our customers.

Realized Gains and Losses from Risk Management Activities, Net, Associated With Natural Gas Inventories Not Yet Sold

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

Gross Profit Attributable to Natural Gas Delivered to Customers

Lower gross profit attributable to natural gas delivered to customers was due in part to lower volumes of natural gas sold to customers. MMBtus sold decreased 13% and 18% during the three months and nine months ended March 31, 2010, respectively, as compared with the same periods in the prior fiscal year.

Gross profit per MMBtu attributable to natural gas delivered to customers increased 34% and 17% during the three months and nine months ended March 31, 2010, respectively, due to colder than normal weather and a favorable pricing environment in many of our natural gas markets. During fiscal year 2010, as weather-related demand increased, natural gas commodity

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prices remained uncharacteristically low. This allowed us to realize higher than normal gross profit, particularly on the incremental volumes of natural gas delivered to customers during the winter.

Electricity Gross Profit

Lower electricity gross profit for the three months ended March 31, 2010 was primarily driven by a 26% reduction in gross profit per MWhr sold during the period, which was partially offset by a 16% increase in the volume of MWhrs sold during the period, as compared with the same period in the prior fiscal year. Lower gross profit per MWhr primarily resulted from competitive pricing environments in many of our electricity markets, including our new market in Pennsylvania. The higher volume of MWhrs sold was primarily driven by a 29% increase in average electricity RCEs served during the three months ended March 31, 2010.

For the first nine months of fiscal year 2010, lower electricity gross profit was primarily driven by a 9% decrease in the volume of MWhrs sold, which was partially offset by a 4% increase in gross profit per MWhr sold. Average electricity RCEs were 5% lower during the nine months ended March 31, 2010.

Gains and Losses from Risk Management Activities, Net

Realized and unrealized (gains) losses from risk management activities, net included in cost of goods sold are summarized in the following table.

						2010 versus 2009 Increase (Decrease)
	2010			2009		Amount			%
	($ in thousands)

Three months ended March 31:
Realized losses from risk management activities	$	1,269		$	20,932	$	(19,663	)	(94	)
Unrealized (gains) losses from risk management activities	26,001			11,462		14,539			127
Total realized and unrealized (gains) losses from risk management activities, net	$	27,270		$	32,394	$	(5,124	)	(16	)

Nine months ended March 31:
Realized losses from risk management activities	$	34,504		$	42,154	$	(7,650	)	(18	)
Unrealized (gains) losses from risk management activities	(2,451		)	113,396		(115,847		)	(102	)
Total realized and unrealized (gains) losses from risk management activities, net	$	32,053		$	155,550	$	(123,497	)	(79	)

Unrealized gains and losses from risk management activities recorded on the consolidated balance sheets primarily reflect the current market values for commodity derivatives utilized as economic hedges to reduce our exposure to changes in the prices of natural gas and electricity. Changes in such market value during the term of a derivative contract are recorded as unrealized gains and losses from risk management activities on the consolidated statements of operations. As derivative contracts expire and related market values are settled, realized gains and losses are recorded on the consolidated statements of operations.

During the nine months ended March 31, 2009, a significant decrease in natural gas prices resulted in significant decreases in the market values of derivative instruments utilized by us as economic hedges intended to reduce our exposure to changes in natural gas prices. Such changes in market values of derivative instruments resulted in significant realized and unrealized losses from risk management activities during the three months and nine months ended March 31, 2009. During the nine months ended March 31, 2010, we experienced less volatility in natural gas prices that resulted in lower realized losses and relatively minor unrealized gains from risk management activities.

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Operating Expenses

Operating expenses are summarized in the following table.

					2010 versus 2009 Increase (Decrease)
	2010		2009		Amount			%
	($ in thousands)

Three months ended March 31:
General and administrative expenses	$	14,454	$	15,714	$	(1,260	)	(8	)
Advertising and marketing expenses	1,707		417		1,290			309
Reserves and discounts	2,628		4,415		(1,787		)	(40	)
Depreciation and amortization	5,979		10,309		(4,330		)	(42	)
Total operating expenses	$	24,768	$	30,855	$	(6,087	)	(20	)

Nine months ended March 31:
General and administrative expenses	$	41,366	$	43,661	$	(2,295	)	(5	)
Advertising and marketing expenses	2,449		1,694		755			45
Reserves and discounts	6,443		9,279		(2,836		)	(31	)
Depreciation and amortization	16,875		28,656		(11,781		)	(41	)
Total operating expenses	$	67,133	$	83,290	$	(16,157	)	(19	)

General and Administrative Expenses

General and administrative expenses are summarized in the following table.

					2010 versus 2009 Increase (Decrease)
	2010		2009		Amount			%
	($ in thousands)
Three months ended March 31:
Salaries and employee benefits	$	8,863	$	8,626	$	237		3
Professional fees	1,350		2,303		(953		)	(41	)
Other general and administrative expenses	4,241		4,785		(544		)	(11	)
Total general and administrative expenses	$	14,454	$	15,714	$	(1,260	)	(8	)

Nine months ended March 31:
Salaries and employee benefits	$	25,085	$	24,802	$	283		1
Professional fees	4,581		5,101		(520		)	(10	)
Other general and administrative expenses	11,700		13,758		(2,058		)	(15	)
Total general and administrative expenses	$	41,366	$	43,661	$	(2,295	)	(5	)

In connection with the Restructuring, we recorded approximately $2.2 million of non-recurring general and administrative expenses during the three months ended September 30, 2009, including:

· $0.8 million of bonuses, included in salaries and employee benefits, which were paid to management in connection with the consummation of the Restructuring;

· $0.2 million of severance costs, included in salaries and employee benefits, which related to certain employees terminated in September 2009 as part of an initiative to streamline our organizational structure and control operating costs; and

· $1.2 million of professional fees incurred in connection with various potential liquidity events considered during fiscal year 2009 and the first three months of fiscal year 2010.

Excluding incremental costs related to the Restructuring, lower salaries and employee benefits for the three months and nine months ended March 31, 2010 was primarily a result of a reduced number of employees during both periods, as compared with the same periods in the prior fiscal year.

Excluding incremental costs related to the Restructuring, lower professional fees for the three months and nine months ended March 31, 2010 was primarily due to termination of management consulting agreements in connection with the Restructuring, lower consulting fees associated with compliance with the requirements of the Sarbanes-Oxley Act of 2002 and lower external auditor fees.

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Lower other general and administrative expenses during the three months and nine months ended March 31, 2010 were primarily due to lower customer care and billing related expenses as a result of generally lower numbers of customers served in our natural gas and electricity business segments.

Advertising and Marketing Expenses

Higher advertising and marketing expenses for fiscal year 2010, as compared with the prior fiscal year, reflects our return to a more normal marketing environment subsequent to the Restructuring. As part of an overall corporate strategy to manage our liquidity position, and in response to amendments to our Revolving Credit Facility and Hedge Facility that placed limitations on amounts that we could spend on marketing activities and on the products we could offer to our customers, we curtailed our level of sales and marketing activity, resulting in significantly lower advertising and marketing expenses during the second half of fiscal year 2009 and the first three months of fiscal year 2010.

As a result of the Restructuring, we now have the ability to market a wider variety of products to current and potential customers using our traditional marketing channels. Since the Restructuring, we have implemented various elements of our fiscal year 2010 growth and marketing plan, which will include strategic marketing initiatives in our current markets as well as incremental marketing expenses related to new markets that are compatible with our overall growth strategy. In December 2009, we initiated a marketing campaign in a new electricity market in Pennsylvania, which we anticipate will result in incremental marketing expenses for the remainder of fiscal year 2010.

Reserves and Discounts

Reserves and discounts are summarized in the following table.

					2010 versus 2009 Increase (Decrease)
	2010		2009		Amount			%
	($ in thousands)
Three months ended March 31:
Provision for doubtful accounts	$	1,565	$	3,245	$	(1,680	)	(52	)
Contractual discounts for LDC guarantees of customer accounts receivable (1)	1,063		1,170		(107		)	(9	)
Total reserves and discounts	$	2,628	$	4,415	$	(1,787	)	(40	)

Nine months ended March 31:
Provision for doubtful accounts	$	4,661	$	6,958	$	(2,297	)	(33	)
Contractual discounts for LDC guarantees of customer accounts receivable (1)	1,782		2,321		(539		)	(23	)
Total reserves and discounts	$	6,443	$	9,279	$	(2,836	)	(31	)

(1) By agreement, certain LDCs guarantee the collection of customer accounts receivable. Contractual discounts charged by various LDCs average approximately 1% of collections, which is effectively the cost to guarantee the customer accounts receivable.

The lower provision for doubtful accounts during the three months and nine months ended March 31, 2010 was primarily due to the following factors:

· Sales of natural gas and electricity in markets where customer accounts receivable are not guaranteed by LDCs decreased 26% and 35% during the three months and nine months ended March 31, 2010, as compared with the same period in the prior fiscal year;

· The aging of our customer accounts receivable deteriorated in certain of our larger markets in Georgia, Texas and the northeastern U.S. during fiscal year 2009, which resulted in charge-offs of customer accounts receivable and provisions for doubtful accounts that were higher than our historical levels. Credit environments have generally stabilized in our markets during fiscal year 2010;

· Incremental reserves against customer accounts receivable deemed uncollectible and charge-offs of customer accounts receivable related to customer accounts acquired from Catalyst Natural Gas, LLC in October 2008 contributed to the higher provision for doubtful accounts in our Georgia natural gas market during fiscal year 2009 and the first quarter of fiscal year 2010. There were no purchase acquisitions of customer accounts during the nine months ended March 31, 2010 that resulted in incremental charge-offs or provisions for doubtful accounts; and

· During fiscal year 2009, we initiated more stringent credit standards for our new and existing customers, which have resulted in generally higher credit quality in our customer portfolio.

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We continuously monitor economic conditions and collections experience in our markets in order to assess appropriate levels of our allowance for doubtful accounts. Refer to Item 3, “Quantitative and Qualitative Disclosures About Market Risk,” for additional commentary regarding our management of credit risk.

Lower contractual discounts for LDC guarantees of customer accounts receivable during the three months and nine months ended March 31, 2010 were due to generally lower sales of natural gas and electricity within our LDC-guaranteed markets. The weighted-average contractual discount rates for the three months and nine months ended March 31, 2010 were comparable to the rates for the same periods in the prior fiscal year.

Depreciation and Amortization

Depreciation and amortization is summarized in the following table.

					2010 versus 2009 Increase (Decrease)
	2010		2009		Amount			%
	($ in thousands)
Three months ended March 31:
Depreciation of fixed assets	$	463	$	1,931	$	(1,468	)	(76	)
Amortization of customer acquisition costs	5,516		8,376		(2,860		)	(34	)
Other amortization expense	—		2		(2		)	(100	)
Total depreciation and amortization	$	5,979	$	10,309	$	(4,330	)	(42	)

Nine months ended March 31:
Depreciation of fixed assets	$	1,905	$	5,903	$	(3,998	)	(68	)
Amortization of customer acquisition costs	14,968		22,745		(7,777		)	(34	)
Other amortization expense	2		8		(6		)	(75	)
Total depreciation and amortization	$	16,875	$	28,656	$	(11,781	)	(41	)

In connection with our purchase of Shell Energy Services Company LLC in August 2006, we acquired software, fixed assets and customer contracts, the aggregate cost of which was depreciated or amortized over a three year period. Lower depreciation and amortization expenses during the three months and nine months ended March 31, 2010 was primarily due to these acquired assets being fully depreciated or amortized as of August 2009.

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Interest Expense, net

Significant components of interest expense, net are summarized in the following table.

							2010 versus 2009 Increase (Decrease)
	2010			2009			Amount			%
	($ in thousands)
Three months ended March 31:
Interest related to debt instruments:
Floating Rate Notes due 2011	$	129		$	3,984		$	(3,855	)	(97	)
Fixed Rate Notes due 2014	2,194			—			2,194			—
Denham Credit Facility	—			266			(266		)	(100	)
	2,323			4,250			(1,927		)	(45	)
Interest and fees related to supply and hedging facilities:
Commodity Supply Facility	2,615			—			2,615			—
Revolving Credit Facility	11			3,595			(3,584		)	(100	)
Hedge Facility	—			1,510			(1,510		)	(100	)
	2,626			5,105			(2,479		)	(49	)

Change in value of interest rate swaps (1)	626			106			520			NM
Amortization of deferred financing costs and original debt issue discount	2,229			2,744			(515		)	(19	)
Other	33			45			(12		)	(27	)
Total interest expense	7,837			12,250			(4,413		)	(36	)
Less: interest income	(59		)	(6		)	(53		)	NM
Interest expense, net	$	7,778		$	12,244		$	(4,466	)	(36	)

Nine months ended March 31:
Interest related to debt instruments:
Floating Rate Notes due 2011	$	3,550		$	12,964		$	(9,414	)	(73	)
Fixed Rate Notes due 2014	4,688			—			4,688			—
Denham Credit Facility	246			544			(298		)	(55	)
	8,484			13,508			(5,024		)	(37	)
Interest and fees related to supply and hedging facilities:
Commodity Supply Facility	5,771			—			5,771			—
Revolving Credit Facility	1,184			6,131			(4,947		)	(81	)
Hedge Facility	1,788			2,604			(816		)	(31	)
	8,743			8,735			8			—

Change in fair market value of interest rate swaps (1)	2,017			5,372			(3,355		)	(62	)
Amortization of deferred financing costs and original debt issue discount	9,628			6,713			2,915			43
Other	186			618			(432		)	(70	)
Total interest expense	29,058			34,946			(5,888		)	(17	)
Less: interest income	(116		)	(342		)	226			66
Interest expense, net	$	28,942		$	34,604		$	(5,662	)	(16	)

	(1)		Includes mark-to-market adjustments and interest expense associated with interest rate swap agreements utilized to manage exposure to interest rate fluctuations on the Floating Rate Senior Notes due 2011 and the Commodity Supply Facility.
	NM		Not meaningful.

Interest Related to Debt Instruments

Lower total interest expense associated with debt instruments for the three months and nine months ended March 31, 2010 is primarily due to decreased total debt balances resulting from the Restructuring. The total aggregate principal balance outstanding under debt instruments decreased from approximately $177.2 million prior to the Restructuring to $74.2 million after the Restructuring.

Lower interest expense associated with the Floating Rate Notes due 2011 for the three months and nine months ended March 31, 2010 was due to a combination of lower debt balances and lower interest rates for both periods. As a result of the Restructuring, the average aggregate outstanding principal balance of Floating Rate Notes due 2011 decreased to approximately $6.4 million and $54.5 million for the three months and nine months ended March 31, 2010, respectively, from $165.2 million for the same periods in the prior fiscal year. The weighted-average interest rate for the Floating Rate Notes due 2011 also decreased to 8.07% and 8.39% for the three months and nine months ended March 31, 2010, respectively, from 9.65% and 10.31% for the same periods in the prior fiscal year, respectively.

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The $67.8 million aggregate principal amount of Fixed Rate Notes due 2014 issued in connection with the Restructuring bears interest at 13.25%, which is higher than the average interest rates on outstanding debt instruments prior to the Restructuring. The higher interest rate on the Floating Rate Notes due 2014 partially offset the impact of lower average debt balances for the three months and nine months ended March 31, 2010.

Interest and Fees Related to Supply and Hedging Facilities

In connection with the Restructuring, the Commodity Supply Facility replaced the Revolving Credit Facility and Hedge Facility effective September 22, 2009. During the three months ended September 30, 2009, we incurred significant fees related to extension and winding down of the Hedge Facility and Revolving Credit Facility prior to the Restructuring. Excluding these incremental fees, fees associated with our supply and hedging activities are generally lower under the Commodity Supply Facility than those under the former Revolving Credit Facility and Hedge Facility.

Amortization of Deferred Financing Costs and Original Debt Issue Discount

Higher amortization of deferred debt issue costs and original issue discount during the nine months ended March 31, 2010 was due to the following activity.

· During fiscal year 2009 and the first three months of fiscal year 2010, we negotiated several amendments to our Hedge Facility and our Revolving Credit Facility. Approximately $9.1 million of total fees associated with these amendments were deferred during fiscal year 2009 and the first three months of fiscal year 2010, which were amortized through the September 21, 2009 maturity date of the Revolving Credit Facility and Hedge Facility. Incremental interest expense associated with amortization of these costs was approximately $1.6 million for the three months ended September 30, 2009.

· In connection with the Restructuring, approximately $158.8 million aggregate principal amount of Floating Rate Notes due 2011 were exchanged for cash, Fixed Rate Notes due 2014 and Class A Common Stock. As a result, we recorded incremental interest expense of $3.1 million, which represents accelerated amortization equivalent to a pro rata portion of the original issue discount and deferred debt issue costs associated with the Floating Rate Notes due 2011 that were exchanged in connection with the Restructuring.

Income Taxes

Our effective income tax rate was a charge of 40.4% and 36.3% for the three months ended March 31, 2010 and 2009, respectively. The change in the effective tax rate for the three months ended March 31, 2010 was primarily due to:

· an increase in the effective tax rate for non-recovery of state tax losses due to certain states not allowing tax loss carrybacks; and

· changes in permanent differences.

· reporting taxable net income for the current period, as compared with a net loss for the same period in the prior fiscal year;

· an increase in the effective rate for non-recovery of state tax losses due to certain states not allowing tax loss carrybacks; and

· changes in permanent differences.

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amount of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Our policy is to establish a valuation allowance if it is “more likely than not” that the related tax benefits will not be realized. As of March 31, 2010 and June 30, 2009, we determined, based on available evidence, including historical financial results for the prior three years, that it is “more likely than not” that a portion of these items may not be recoverable in the future. Accordingly, we recorded valuation allowances at March 31, 2010 and June 30, 2009 related to non-recovery of deferred tax assets.

The Worker, Homeownership and Business Assistance Act of 2009, which was signed into law on November 6, 2009, contains a number of tax law changes, including a provision that permits companies to elect to carry back certain net operating losses for up to five years. As of March 31, 2010, we expect to carry back the amount of any tax loss for fiscal year 2010.

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Liquidity and Capital Resources

Our principal sources of liquidity for our ongoing operations are cash collected from sales of natural gas and electricity to customers and borrowings under our credit facilities. Our primary liquidity requirements arise primarily from our seasonal working capital needs, including purchases of natural gas inventories, collateral requirements related to supplier, LDC, transportation and storage arrangements, acquisition of customers and debt service obligations. Because we sell natural gas and electricity, we are subject to material variations in short-term indebtedness under our credit facilities on a seasonal basis, due to the timing and price of commodity purchases to meet customer demands.

As of June 30, 2009, and through September 21, 2009, we relied on the following credit and commodity hedging arrangements to provide the liquidity necessary for operation of our natural gas and electricity businesses:

· The Revolving Credit Facility was used primarily to post letters of credit required to effectively operate within the markets that we serve;

· The Hedge Facility was used as our primary facility to economically hedge variability in the cost of natural gas; and

· Commodity derivative arrangements with various counterparties were used to economically hedge variability in the cost of electricity.

A sharp drop in natural gas market prices during the six months ended December 31, 2008 resulted in a significant reduction in the natural gas inventory component of the available borrowing base under the Revolving Credit Facility. The reduced borrowing base strained our 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 our credit ratings and ultimately resulted in our seeking and obtaining material waivers of debt covenants and defaults and amendments to the agreement that governed the Revolving Credit Facility and the Hedge Facility. Such amendments had significant impacts on our liquidity position and on our operations during fiscal year 2009 and during the first quarter of fiscal year 2010 (refer to “Revolving Credit Facility” section below).

Given the negative conditions in the economy generally and the credit markets in particular, there was substantial uncertainty that we would be able to secure a refinancing of the Revolving Credit Facility without a material restructuring of our debt and equity position. On September 22, 2009, we consummated the Restructuring, which was intended to reduce our debt exposure and interest expense, improve our liquidity and improve our financial and operational flexibility in order to allow us to compete more effectively. As a result of the Restructuring, we significantly decreased our outstanding debt obligations, which will result 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.

The Commodity Supply Facility provides for cash borrowings of up to $45.0 million that we may access to finance seasonal working capital requirements, provided that we are in compliance with the Collateral Coverage Ratio requirement, as described below. These cash borrowings will accrue interest at the greater of: (1) RBS Sempra’s cost of funds plus 5%; or (2) LIBOR plus 5%. Outstanding credit support (e.g., letters of credit and/or guarantees) provided by RBS Sempra will accrue interest at LIBOR plus 3%, with a minimum rate of 4% except that, if the cash held in certain collateral accounts exceeds all outstanding settlement payments under the Commodity Supply Facility by $27.0 million, interest will accrue at a reduced rate of 1% on the amount of outstanding credit support in excess of $27.0 million.

In accordance with the terms of the ISDA Master Agreements, we are required to maintain a minimum collateral coverage ratio (the “Collateral Coverage Ratio”) of 1.25:1.00 for the months of October through March (inclusive) and 1.40:1.00 for any other calendar month. The Collateral Coverage Ratio is calculated as the ratio of: (1) certain of our assets, primarily including cash, amounts due from RBS Sempra representing our operating cash, accounts receivable from our customers and LDCs and natural gas inventories; to (2) certain of our liabilities, primarily arising from exposure and/or amounts due to RBS Sempra as a result of our agreements (including amounts due for the purchase of natural gas and electricity, accrued but unpaid financing fees and settlements arising from derivative contracts).

As of March 31, 2010, we had a Collateral Coverage Ratio of approximately 2.34:1.00. The calculation of the Collateral Coverage Ratio as of March 31, 2010 reflected available liquidity of approximately $82.7 million. At March 31, 2010, we had no outstanding cash advances and had $39.2 million of letters of credit outstanding under the Commodity Supply Facility.

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Cash Flow

During the nine months ended March 31, 2010, our cash and cash equivalents decreased $20.4 million to a balance of $2.9 million at the end of the period. Approximately $44.5 million of cash was provided by operating activities during the period, which reflects a $62.1 million change from the $17.6 million used in operations for the nine months ended March 31, 2009. The overall increase in cash provided by operating activities during the nine months ended March 31, 2010 primarily resulted from the net impact of the following activity:

· Higher net income (after adjustment for non-cash operating items such as unrealized gains and losses from risk management activities, depreciation and amortization expense, deferred income tax expense, provision for doubtful accounts and stock compensation expense) resulting from higher gross profit (excluding unrealized gains and losses from risk management activities), lower operating expenses (excluding non-cash expenses) and lower interest expense (excluding non-cash expenses); and

· Release of $75.0 million of restricted cash to cash and cash equivalents upon termination of the Revolving Credit Facility in September 2009; offset by

· Higher use of operating cash for working capital items, mostly as a result of various transactions and activity related to the Restructuring.

The Restructuring also resulted in the following material uses of cash and cash equivalents for investing and financing activities:

· $26.7 million was paid to bondholders in partial exchange for their Floating Rate Notes due 2011;

· $12.0 million of principal outstanding, plus accrued and unpaid interest, under the Denham Credit Facility was repaid and the Denham Credit Facility was terminated;

· $5.4 million of principal outstanding, plus accrued and unpaid interest, of Bridge Financing Loans were repaid and the Bridge Financing Loans were terminated.

In addition, the Company used approximately $13.2 million and $0.5 million of cash and cash equivalents for acquisition of customers and fixed assets, respectively.

Commodity Supply Facility

The Commodity Supply Facility is governed by separate International Swap Dealers Association, Inc. (“ISDA”) master agreements (the “ISDA Master Agreements”) for natural gas and electricity. On September 28, 2009, MXenergy Inc. and MXenergy Electric Inc. entered into amendments to the ISDA Master Agreements for natural gas and electricity, respectively, with the Company and certain of its subsidiaries, as guarantors, and RBS Sempra. Pursuant to the terms of the these amendments, the definition of “Adjusted Consolidated Tangible Net Worth” in the ISDA Master Agreements was amended to allow us to adjust for non-cash charges associated with any deferred tax valuation allowances. The Company must maintain a consolidated tangible net worth, as defined in the ISDA Master Agreements, of at least $60.0 million. As of March 31, 2010, we were in compliance with all provisions of the ISDA Master Agreements.

Under the Commodity Supply Facility, the primary obligors are Holdings’ two significant operating subsidiaries, MXenergy Inc. and MXenergy Electric Inc. All obligations under the Commodity Supply Facility are guaranteed by Holdings and its other domestic subsidiaries and are secured by a first priority lien on substantially all existing and future assets of Holdings and its domestic subsidiaries that are not restricted as to use under bondholder agreements. The maturity date of the Commodity Supply Facility is August 31, 2012, provided that RBS Sempra will have the right to extend such maturity date by one year in its sole discretion, if notice is provided by RBS Sempra no later than April 30, 2011.

The Commodity Supply Facility provides for the exclusive supply of physical (other than as needed for balancing) and financial natural gas and electricity, credit support (including letters of credit and guarantees) for certain collateral needs, cash advances for natural gas inventory and seasonal financing as needed, and associated hedging transactions in order to maintain the matched trading book required by our risk management policies. The Commodity Supply Facility provides for certain volumetric fees for all natural gas and electricity purchases.

Under the supply 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

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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 and unless 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.

Under the Commodity Supply Facility, we are obligated to purchase a minimum of 130,000,000 MMBtus of natural gas from RBS Sempra, for physical delivery in accordance with the following schedule: (1) 39,000,000 MMBtus during the first contract year; (2) 44,000,000 MMBtus during the second contract year; and (3) 47,000,000 MMBtus during the third contract year. In addition, we are obligated to purchase a minimum of 1,850,000 MWhrs of electricity from RBS Sempra, for physical delivery in accordance with the following schedule: (1) 500,000 MWhrs during the first contract year; (2) 650,000 MWhrs during the second contract year; and (3) 700,000 MWhrs during the third contract year. The estimated total value of these purchases will depend upon the market price of natural gas at the time of purchase. We will be obligated to pay a volumetric fee for any unused balance of the minimum volume purchase requirement for any contract year, or if the agreement is terminated prior to the end of the contract. The excess of actual commodity purchases from RBS Sempra over the minimum purchase requirement for any contract year, if any, will be deducted from the minimum purchase requirement for the subsequent contract year. As of March 31, 2010, commodity that we expect to purchase for delivery to our customers during the first contract year of the Commodity Supply Facility is expected to exceed the minimum purchase obligation for natural gas and electricity.

The Commodity Supply Facility provides that we will release natural gas transportation and delivery capacity to RBS Sempra and for RBS Sempra to perform certain transportation and storage nominations. The Commodity Supply Facility also will provide for RBS Sempra to act on our behalf to satisfy the requirements of regional electricity transmission operators for capacity rights and ancillary services.

Under the hedging terms of the Commodity Supply Facility, our aggregate outstanding notional amount of fixed price physical and/or financial hedges is limited to $260.0 million. Fixed price hedges will be limited to a contract length term of 24 months. In addition, the fixed price portfolio of hedges will be limited to a weighted-average volume tenor not to exceed 14 months in duration.

With regards to our fixed price customer mix, we may not enter into any fixed price contracts, excluding renewals of existing fixed price contracts, if:

· During any twelve-month period, more than 75% of all RCEs have been added under fixed price contracts;

· During any twelve-month period, more than 235,000 RCEs have been added under fixed price contracts; and

· Our fixed price RCEs exceed 325,000 at any time.

In connection with the Commodity Supply Facility, during the nine months ended March 31, 2010, certain of our natural gas hedge agreements under the former Hedge Facility and all of our existing electricity swap agreements with other counterparties were novated to RBS Sempra. Additionally, certain of our forward physical agreements for the purchase of natural gas and all of our forward physical agreements for the purchase of electricity were novated to RBS Sempra. Such novations did not have any impact on our rights, obligations or risks associated with the agreements.

The ISDA Master Agreements contain customary covenants that restrict certain activities including, among other things, the Company’s ability to:

· incur additional indebtedness;

· create or incur liens;

· guarantee obligations of other parties;

· engage in mergers, consolidations, liquidations and dissolutions;

· create subsidiaries;

· make acquisitions;

· engage in certain asset sales;

· enter into leases or sale-leasebacks;

· make equity distributions;

· make capital expenditures;

· make loans and investments;

· make certain dividend, debt and other restricted payments;

· engage in a different line of business;

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· amend, modify or terminate certain material agreements in a manner that is adverse to the lenders; and

· engage in certain transactions with affiliates.

The ISDA Master Agreements also include customary events of default, including:

· payment defaults;

· breaches of representations and warranties;

· covenant defaults;

· cross defaults to certain other indebtedness (including the Fixed Rate Notes due 2014) in excess of specified amounts;

· certain events of bankruptcy and insolvency;

· ERISA defaults;

· judgments in excess of specified amounts;

· failure of any guaranty or security document supporting the Commodity Supply Facility to be in full force and effect;

· the termination or cancellation of any material contract which termination or cancellation could reasonably be expected to have a material adverse effect on us; and

· the occurrence of a change of control.

The ISDA Master Agreements include provisions that allow for net settlement of amounts due from and due to RBS Sempra. Accordingly, we report amounts due from and due to RBS Sempra net on the consolidated balance sheets. At March 31, 2010, the net $15.0 million amount due from RBS Sempra is reported as accounts receivable, net — RBS Sempra on the condensed consolidated balance sheets.

Revolving Credit Facility

At June 30, 2009, the total availability under the Revolving Credit Facility was $147.8 million, of which the maximum we could utilize was $115.0 million. As of June 30, 2009, $96.3 million of availability was utilized in the form of outstanding letters of credit.

The sharp drop in natural gas market prices during the first six months of fiscal year 2009 resulted in a significant reduction in the available borrowing base under the Revolving Credit Facility, which strained our ability to post letters of credit as collateral with suppliers and hedge providers, resulting in waivers obtained from lenders related to certain provisions included in the agreement that governs the Revolving Credit Facility, and ultimately resulting in material amendments to the agreement that governs the Revolving Credit Facility (the “2009 Amendments”).

As a result of these amendments, we were required to seek a new facility to replace the Revolving Credit Facility and Hedge Facility. Various milestone events and dates were established by the 2009 Amendments that led to the consummation of the Restructuring on September 22, 2009. The Revolving Credit Facility was replaced by the Commodity Supply Facility effective September 22, 2009.

Hedge Facility

As of June 30, 2009, and through September 21, 2009, although we engaged in economic hedging activities with various counterparties for electricity, we utilized the Hedge Facility as our primary natural gas hedge facility. The Hedge Facility, which was governed by a master transaction agreement (the “Master Transaction Agreement”), was originally entered into on August 1, 2006 by and among MXenergy Inc., MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, and the hedge provider, and had an initial term of two years with subsequent one-year renewal terms.

Under the Hedge Facility, we utilized NYMEX-referenced over-the-counter swaps, basis price swaps and options to hedge the risk of variability in the cost of natural gas. Until the termination of the Hedge Facility, we had the ability to enter into NYMEX and basis swaps through June 2010. Fees under the Hedge Facility included an annual management fee, a volumetric fee based on the tenor of the swap and other fees which allow the hedge provider to mitigate the potential risks arising from material declines of natural gas market prices based on our overall hedge position with the provider.

During fiscal year 2009, the Master Transaction Agreement was amended several times to conform to provisions of various amendments to the Revolving Credit Facility, including those relating to milestone events that led to the consummation of the Restructuring. In addition, these amendments resulted in our total outstanding hedging positions being limited to a maximum of 12.0 million MMBtus as of May 29, 2009, 11.0 million MMBtus effective July 31, 2009, and to 10.0 million MMBtus

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effective August 31, 2009. This limitation was eliminated upon termination of the Hedge Facility on September 21, 2009.

As of June 30, 2009, the Company had posted a $35.0 million letter of credit as collateral for its mark-to-market exposure under the Hedge Facility. The requirement to post collateral was cancelled when the Hedge Facility expired on September 21, 2009.

The Hedge Facility was replaced by the Commodity Supply Facility effective September 22, 2009. On September 22, 2009, certain of our hedging transactions under the Hedge Facility were novated or otherwise transferred to RBS Sempra. In addition, the Commodity Supply Facility requires us to unwind certain existing physical and financial forward swaps subsequent to closing, with RBS Sempra providing any credit support necessary to liquidate those positions.

Fixed Rate Notes due 2014

In connection with the Restructuring consummated on September 22, 2009, we issued $67.8 million aggregate principal amount of Fixed Rate Notes due 2014. Interest on the Fixed Rate Notes due 2014 accrues at the rate of 13.25% per annum and is payable semi-annually in cash on February 1 and August 1 of each year, commencing on February 1, 2010. The Fixed Rate Notes due 2014 will mature on August 1, 2014.

The Fixed Rate Notes due 2014 were issued at a discount of approximately $17.8 million, which was recorded as a reduction of the aggregate principal balance of Fixed Rate Notes due 2014 on our consolidated balance sheets during the first quarter of fiscal year 2010, and which will be amortized as an increase to interest expense over the remaining life of the Fixed Rate Notes due 2014. During fiscal year 2009 and the three months ended September 30, 2009, we incurred approximately $5.3 million of legal fees, consulting fees and other costs directly related to the Fixed Rate Notes due 2014, which were deferred on the consolidated balance sheet and are being amortized as an increase to interest expense over the remaining term of the Fixed Rate Notes due 2014.

The Fixed Rate Notes due 2014 are senior subordinated secured obligations of the Company, subordinated in right of payment to obligations of the Company under the Commodity Supply Facility. The Fixed Rate Notes due 2014 are senior in priority to our unsecured senior obligations, including the Floating Rate Notes due 2011, to the extent that the value of the assets securing the Fixed Rate Notes due 2014 is in excess of the aggregate amount of the outstanding Commodity Supply Facility obligations.

The Fixed Rate Notes due 2014 are jointly, severally, fully and unconditionally guaranteed by all domestic subsidiaries of Holdings.

The Fixed Rate Notes due 2014 are secured by a first priority security interest in the Fixed Rate Notes Escrow Account, which is maintained as security for future interest payments to holders of the Fixed Rate Notes due 2014, and by a second priority security interest in substantially all other existing and future assets of the Company. The Fixed Rate Notes Escrow Account was funded with approximately $9.0 million in September 2009, which approximates the interest payable by us on the Fixed Rate Notes due 2014 for a twelve-month period.

At any time, or from time to time, on or prior to August 1, 2011, we may, at our option, use the net cash proceeds of equity offerings, if any, to redeem either: (1) 100% of the outstanding principal amount of the Fixed Rate Notes due 2014; or (2) up to 35% of the outstanding principal amount of the Fixed Rate Notes due 2014, in each case at a redemption price of 113.250% of the principal amount thereof, plus accrued and unpaid interest thereon, if any, to the date of redemption, provided that:

· if we redeem less than all of the Fixed Rate Notes due 2014, at least 65% of the principal amount of the Fixed Rate Notes due 2014 issued under the Indenture remains outstanding immediately after any such redemption; and

· we make such redemption not more than 90 days after the consummation of any such equity offering.

After August 11, 2011, we may redeem the Fixed Rate Notes due 2014 at our option, in whole or in part, upon not less than 30 days’ or more than 60 days’ notice, at the redemption prices specified in the indenture that governs the Fixed Rate Notes due 2014.

Upon a change of control of the Company, we would be required to make an offer to purchase each holder’s Fixed Rate Notes due 2014 at a price of 101% of the then outstanding principal amount thereof, plus accrued and unpaid interest.

The indenture governing the Fixed Rate Notes due 2014 contains restrictions on Holdings and its subsidiaries with regard to

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declaring or paying any dividend or distribution on Holdings capital stock. As of March 31, 2010, the Company was in compliance with all provisions of the indenture governing the Fixed Rate Notes due 2014.

Floating Rate Notes due 2011

On August 4, 2006, Holdings issued $190.0 million aggregate principal amount of Floating Rate Notes due 2011, which mature on August 1, 2011. The notes were issued at 97.5% of par value and bear interest at LIBOR plus 7.5% per annum. Interest is reset and payable semi-annually on February 1st and August 1st of each year. During fiscal years 2007 and 2008, we purchased $24.8 million aggregate principal amount of the outstanding Floating Rate Notes due 2011, plus accrued interest, from noteholders for amounts less than face value.

In connection with the Restructuring, $158.8 million aggregate principal amount of outstanding Floating Rate Notes due 2011 were exchanged for $26.7 million of cash, $67.8 million aggregate principal amount of Fixed Rate Notes due 2014 and 33,940,683 shares of newly authorized Class A Common Stock. Holders of approximately $6.4 million aggregate principal amount of Floating Rate Notes due 2011 did not tender their notes pursuant to the Restructuring. These Floating Rate Notes due 2011 will remain outstanding until their maturity date in August 2011 unless acquired or retired by us sooner. The indenture governing the Floating Rate Notes due 2011 was amended to eliminate substantially all of the restrictive covenants and certain events of default from such indenture.

The interest rate on the Floating Rate Notes due 2011 was 7.88% and 9.13% at March 31, 2010 and June 30, 2009, respectively. The weighted-average interest rate was 8.39% and 10.31% for the nine months ended March 31, 2010 and 2009, respectively.

Original issue discount and deferred debt issue costs associated with the Floating Rate Notes due 2011 have been reduced by the pro rata portion of discount and deferred costs associated with our purchases of Floating Rate Notes due 2011 during fiscal years 2007 and 2008 and by the pro rata portion of discount and deferred costs associated with the Floating Rate Notes due 2011 exchanged in connection with the Restructuring. As of March 31, 2010, the remaining $0.2 million aggregate unamortized balance of original issue discount and deferred debt issue costs associated with the Floating Rate Notes due 2011 is being amortized as increases to interest expense ratably over the term of the Floating Rate Notes due 2011.

Denham Credit Facility

The Denham Credit Facility was a $12.0 million line of credit that bore interest at 9% per annum. The termination date for the Denham Credit Facility was May 19, 2010, at which time any outstanding principal balance would have become due.

In accordance with the September 30, 2008 amendment and restatement of our Revolving Credit Facility, we were required to borrow any available balance under the Denham Credit Facility prior to November 7, 2008, and to maintain such balance outstanding until the Revolving Credit Facility expired. In September 2008, we borrowed the entire $12.0 million balance available under the Denham Credit Facility, the entire amount of which was still outstanding at June 30, 2009. On September 22, 2009, the outstanding balance under the Denham Credit Facility was repaid, including accrued and unpaid interest, and the Denham Credit Facility was terminated.

Redeemable Convertible Preferred Stock

Prior to the consummation of the Restructuring, Holdings was authorized to issue 5,000,000 shares of Preferred Stock. On June 30, 2004, MXenergy Inc. entered into a purchase agreement (the “Preferred Stock Purchase Agreement”) with affiliates of Charterhouse Group Inc. and Greenhill Capital Partners LLC (collectively, the “Preferred Investors”) to issue 1,451,310 shares of Preferred Stock at a purchase price of $21.36 per share.

As of June 30, 2009, we determined that the Preferred Stock was redeemable at the option of the Preferred Investors as a result of the redemption provisions included in the Preferred Stock Purchase Agreement. Therefore, the Preferred Stock was recorded outside of stockholders’ equity on the consolidated balance sheets at its estimated $54.6 million redemption value.

On September 22, 2009, all outstanding shares of Preferred Stock were exchanged for 11,862,551 shares of newly authorized Class C Common Stock, which represented 21.84% of the aggregate total shares of the Company’s common stock outstanding as of the consummation date of the Restructuring. The excess of the redemption value over the aggregate fair value of common stock issued to the preferred shareholders was reclassified to stockholders’ equity on the consolidated balance sheets during the first quarter of fiscal year 2010. In connection with the Restructuring, Holdings filed an amended and restated Certificate of Incorporation that does not authorize the issuance of any preferred stock.

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Contractual Obligations

The Commodity Supply Facility provides for the exclusive supply of physical (other than as needed for balancing) and financial natural gas and electricity, credit support (including letters of credit and guarantees) for certain collateral needs, payment extension financing and/or storage financing as needed, and associated hedging transactions in order to maintain the matched trading book required by our risk management policies.

Under the Commodity Supply Facility, we are obligated to purchase a minimum of 130,000,000 MMBtus of natural gas from RBS Sempra, for physical delivery in accordance with the following schedule: (1) 39,000,000 MMBtus during the first contract year; (2) 44,000,000 MMBtus during the second contract year; and (3) 47,000,000 MMBtus during the third contract year. In addition, we are obligated to purchase a minimum of 1,850,000 MWhrs of electricity from RBS Sempra, for physical delivery in accordance with the following schedule: (1) 500,000 MWhrs during the first contract year; (2) 650,000 MWhrs during the second contract year; and (3) 700,000 MWhrs during the third contract year. The estimated total value of these purchases will depend upon the market price of natural gas at the time of purchase. During fiscal year 2009, our price of natural gas ranged from a high of approximately $12.75 per MMBtu in July 2008 to a low of approximately $3.25 per MMBtu in May 2009. The Company will be obligated to pay a volumetric fee for any unused balance of the minimum volume purchase requirement for any contract year, or if the agreement is terminated prior to the end of the contract. The excess of actual commodity purchases from RBS Sempra over the minimum purchase requirement for any contract year, if any, will be deducted from the minimum purchase requirement for the subsequent contract year. As of March 31, 2010, commodity that we expect to purchase for delivery to our customers during the first contract year of the Commodity Supply Facility is expected to exceed the minimum purchase obligation for natural gas and electricity.

Off-Balance Sheet Arrangements

As of March 31, 2010, we did not have any off-balance sheet arrangements.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

Commodity price risk is the risk of exposure to fluctuations in the price of natural gas and electricity. Because our contracts require that we deliver full commodity requirements to many of our customers and because our customers’ usage is impacted by factors such as weather, we are exposed to fluctuations in customer load requirements. We typically purchase commodity equal to expected customer consumption assuming normal weather patterns. We may purchase additional commodity volumes for the summer in the case of electricity and for the winter in the case of natural gas in order to protect against a potential demand increase in peak seasons. As a result of the natural swing in customer consumption related to weather changes, we may have to buy or sell additional volumes, and therefore may be exposed to price volatility in that event. 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 and physical basis hedges; and (2) for electricity: ISO zone specific swaps, basis swaps, physical hedges and physical basis hedges.

Economic hedges are also utilized to cover inventory injection and withdrawal as well as to cover utility over/under delivery obligations. For fixed price customers, both inventory and imbalances caused by utility over/under delivery obligations are hedged using derivatives or physical hedges. For variable price customers, inventory is generally hedged using derivative instruments or physical commodity hedges and utility imbalances are hedged either through the utilization of derivatives, physical hedges, or through a monthly price adjustment as published and billed to the customer each month. The fair values of these hedges, which are recorded in unrealized gains (losses) from risk management activities on the consolidated balance sheet, will settle during each specific month to mirror our planned injections and withdrawals, as well as over/under delivery obligations.

The natural gas swap instruments are generally settled against the closing price for the last trading day of each month for natural gas listed on the NYMEX Henry Hub futures contract. In the case of electricity swap instruments, settlement is based on ISO settlement prices during the month. The financial basis swaps are typically settled against the first of the month published index prices at various trading points that relate to locations where we have customer obligations. Basis swaps are

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priced based on the NYMEX price on the last day of the month plus or minus an agreed-upon premium or discount. All of the natural gas swaps have been executed “over-the-counter” on a bilateral basis under the Hedge Facility or with other credit-worthy counterparties. We also enter into financial swaps with other counterparties in order to meet electricity requirements. These are settled based on the index price for the appropriate ISO. We only execute financial swaps with entities with investment grade credit ratings. As of March 31, 2010, our hedge positions expire at various times through March 2012.

We have adopted a risk management policy to measure and limit market and credit risk associated with our customer portfolio. The risk policy requires that we maintain a balanced position at all times and does not permit speculative trading. None of our employees are compensated on the basis of his or her trading activities. In marketing products to residential and small commercial customers, we hedge in advance of anticipated contract sales (adjusted to reflect attrition). When marketing to larger commercial accounts, the hedge is executed at the time of the contract sale. Our current risk policy requires that the following exposures be promptly mitigated: (1) for natural gas, any exposure in excess of $1.0 million related to the volumetric difference between commitments to deliver natural gas to customers and the related hedge positions must be brought back in compliance within three business days; and (2) for electricity, any exposure greater than $750,000 related to the volumetric difference between commitments to deliver electricity to customers and related hedge positions must be brought back in compliance within three business days.

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

We utilize an internally developed modified variance/co-variance value-at-risk “VAR,” model to estimate potential loss in the fair value of our natural gas portfolio. For our VAR model, we utilize the higher of 10-day and 30-day NYMEX volatility on a 2 standard deviation basis (95.45% confidence level). During the three months ended September 30, 2008, volatility in natural gas prices resulted in unusually high potential losses in the fair value of our natural gas portfolio using this VAR model.

The potential losses in the fixed price natural gas portfolio using our actual net open position at the end of each month during the three months and nine months ended March 31, 2010 and 2009 are summarized in the following table. Volatility in natural gas commodity prices during the nine months ended March 31, 2009 resulted in unusually high potential losses in the fair value of our natural gas portfolio for that period using this VAR model.

	Potential Loss During the Period
	2010		2009
	(in thousands)
Three months ended March 31:
Average	$	13	$	58
Maximum	28		92
Minimum	4		25

Nine months ended March 31:
Average	$	31	$	141
Maximum	63		624
Minimum	4		25

There have been no material changes in our methodology or policies regarding commodity price risk management during the nine months ended March 31, 2010.

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Credit Risk

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

We also are exposed to credit risk in our sales activities. For the nine months ended March 31, 2010, approximately 47% of our total sales of natural gas and electricity were within markets where LDCs do not guarantee customer accounts receivable while 53% of our total sales were within markets where LDCs guarantee customer accounts receivable at a weighted average discount rate of approximately 1%. Such discount is the cost incurred to guarantee the customer accounts receivable. In cases where customer accounts receivable are guaranteed by the LDC, we are exposed only to the credit risk of the LDC, rather than that of our actual customers. We monitor the credit ratings of LDCs and the parent companies of LDCs that guarantee our customer accounts receivable. As of March 31, 2010, all of our customer accounts receivable in guaranteed markets was with LDCs with investment grade credit ratings. We also periodically review payment history and financial information for LDCs to ensure that we identify and respond to any deteriorating trends.

The allowance for doubtful accounts represents our estimate of potential credit losses associated with customer accounts receivable in markets where such receivables are not guaranteed by LDCs. We assess the adequacy of our allowance for doubtful accounts through review of the aging of customer accounts receivable and our assessment of the general economic conditions in the markets that we serve. We record a provision for doubtful accounts for the estimated total revenue that is not expected to be collected from customers in non-guaranteed markets. Based upon our review as of March 31, 2010, we believe that the allowance for doubtful accounts is adequate to cover potential credit losses related to customer accounts receivable. The following table provides a summary of the provision for doubtful accounts as a percentage of total sales of natural gas and electricity within these markets.

	2010		2009
Provision for doubtful accounts as a percentage of sales of natural gas and electricity in non-guaranteed markets during the period:
Three months ended March 31	1.37	%	2.10	%
Nine months ended March 31	1.92	%	1.87	%

During the first quarter of fiscal year 2010, we experienced continued deterioration of the aging of billed customer accounts receivable within certain of our markets, particularly in our largest natural gas market in Georgia, which resulted in an increase in the provision for doubtful accounts. We continue to closely monitor economic conditions and actual collections data within all of our markets for signs of any negative long-term trends which could result in higher allowance requirements.

There have been no material changes in our methodology or policies regarding credit risk management during the nine months ended March 31, 2010.

Interest Rate Risk

We are exposed to risk from fluctuations in interest rates under the Commodity Supply Facility and the Floating Rate Notes due 2011. We manage our exposure to interest rate fluctuations by utilizing interest rate swaps to effectively convert the interest rate exposure from a variable rate to a fixed rate of interest. As of March 31, 2010, an $80.0 million swap was outstanding, which expires on August 1, 2011. The fixed-for-floating swap effectively fixes the six-month LIBOR rate at 5.72% per annum. During fiscal year 2010, the $80.0 million interest rate swap agreement was novated to RBS Sempra from the previous counterparty, as required by the terms of the Commodity Supply Facility. Such novation did not have any impact on our rights, obligations, risks or accounting methodology associated with the interest rate swap agreement.

Under the Commodity Supply Facility, we are subject to variable interest rates in connection with cash borrowings and credit support, primarily in the form of letters of credit, provided by RBS Sempra. As of March 31, 2010, approximately $39.2 million of letters of credit were outstanding under the Commodity Supply Facility, in addition to the $6.4 million aggregate principal amount of Floating Rate Notes due 2011.

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Based on the net exposure as of March 31, 2010 resulting from the interest rate swap, the letters of credit outstanding under the Commodity Supply Facility and the outstanding balance of Floating Rate Notes due 2011 on the consolidated balance sheets, the impact of a 1% change in interest rates on interest expense for a twelve-month period is approximately $0.3 million.

As of June 30, 2009, we were not specifically required to provide any collateral or letters of credit in support of interest rate derivative liabilities. At March 31, 2010, we posted $6.0 million of cash as collateral against our mark-to-market exposure related to the outstanding interest rate swap agreement.

We have not designated interest rate swaps as hedges and, accordingly, changes in the market value of the interest rate swaps are charged directly to interest expense. At March 31, 2010, the total unrealized loss from risk management activities on the consolidated balance sheets related to interest rate swaps was approximately $6.0 million.

Item 4T. Controls and Procedures

Disclosure Controls

We maintain a system of internal and disclosure controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Securities and Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported on a timely, accurate and complete basis. Our Board of Directors, operating through its Audit Committee, provides oversight to the financial reporting process.

An evaluation was conducted, with the participation of the Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by our Annual Report for the fiscal year ended June 30, 2009 (the “2009 Annual Report”). Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were not effective, as of the end of the period covered by the 2009 Annual Report, due to the material weakness in our internal control over financial reporting described below.

In designing and evaluating our disclosure controls and procedures, our management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management necessarily is required to apply its judgment in designing and evaluating the controls and procedures. We regularly review our disclosure controls and procedures, and our internal controls over financial reporting, and may from time to time make appropriate changes aimed at enhancing their effectiveness and ensure that our systems evolve with our business.

Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining an adequate system of internal control over financial reporting. Because of its inherent limitations, internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with established policies or procedures may deteriorate.

Our management carried out an evaluation of the effectiveness of our internal control over financial reporting as of the end of the period covered by the 2009 Annual Report, with the participation of our Chief Executive Officer and Chief Financial Officer. Based upon their evaluation, our Chief Executive Officer and Chief Financial Officer concluded that there is a material weakness in our internal control over financial reporting. A material weakness is a deficiency, or a combination of control deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of the Company’s annual or interim financial statements will not be prevented or detected on a timely basis.

The material weakness relates to certain significant deficiencies that were identified by management during our year-end financial statement close process and others that relate to errors identified during the year-end audit for the fiscal year ended June 30, 2009. The most significant of these deficiencies relate to:

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· Errors in our accounting records that were not properly identified by the normal review process within our finance team; and

· Revenue recognition errors resulting from incomplete or inaccurate reports required to reconcile cash receipts to detailed customer records for certain of our markets.

These significant deficiencies resulted in adjustments to our accounting records at June 30, 2009 for amounts that related to quarterly and annual periods previously reported. The amounts of 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 2009 or 2008. However, we concluded that the significant deficiencies, when evaluated in the aggregate, resulted in a material weakness in the design and operation of our internal controls over financial reporting as of June 30, 2009 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. To remedy this material weakness, we have identified certain controls or processes that will be put into place with the intent of mitigating the risk of potential future misstatements from the identified significant deficiencies.

There were no changes in our internal control over financial reporting during the nine months ended March 31, 2010.

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Part II. Other Information

Item 1. Legal Proceedings

From time to time, we are a party to claims and legal proceedings that arise in the ordinary course of business, including investigation of our product pricing and 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 impact on our results of operations, financial position or cash flows.

Item 1A. Risk Factors

There are many risk factors that could materially affect our business, financial condition and results of operations. Except as disclosed below, there have been no material changes to the risk factors disclosed in our 2009 Annual Report.

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

Royal Bank of Scotland Group recently 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.

The Fixed Rate Notes due 2014 must be registered with the SEC.

We are required to file an effective registration statement for the Fixed Rate Notes due 2014 with the SEC within one year from the consummation date of the Restructuring. Failure to do so would result in a 0.25% increase to the interest rate on the Fixed Rate Notes due 2014 for each 90 day period that such registration statement is not filed, up to a maximum 1.0% per annum, which would have a negative impact on our results from operations. We intend to file an effective registration statement on a timely basis in order to avoid any increase in the interest rate on the Fixed Rate Notes due 2014.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. (Removed and Reserved)

None.

Item 5. Other Information

Departure and Appointment of Directors

Denham is a significant holder of Holdings’ Class C Common Stock. Pursuant to the terms of the Company’s Certificate of Incorporation, Denham is entitled to appoint one director to the Company’s Board of Directors. In September 2009, Denham appointed Stuart Porter to serve as its representative on the Board of Directors. Effective May 13, 2010, Denham decided, for internal reasons, to replace Mr. Porter on the board of directors. During his tenure, Mr. Porter served on the Executive, Compensation and Governance Committee and the Risk Oversight Committee of the Board of Directors. Also on May 13, 2010, Denham appointed Carl Adam Carte to serve as its representative on the Board of Directors. Mr. Carte is a

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founding member and partner at Fairlead Advisors LLC, where he provides strategic, commercial, valuation and financial expertise to private equity clients. Mr. Carte is expected to provide financial and operating expertise and insight for the Company’s activities.

Amendment to Employment Agreement of Chief Financial Officer

On May 14, 2010, the Company entered into an amendment (the “Amendment”), effective as of May 17, 2010 (the “Effective Date”), to the employment agreement effective February 13, 2008 with Chaitu Parikh (the “Employment Agreement”), the Company’s Chief Financial Officer. The Amendment (i) provides that Mr. Parikh shall be relocated from the Company’s headquarters in Stamford, Connecticut to Houston, Texas on a mutually agreeable date in 2010, (ii) extends the term of Mr. Parikh’s employment with the Company for a period of three years beginning on the Effective Date and (iii) increases Mr. Parikh’s annual base salary to $450,000. The Amendment also provides that if Mr. Parikh is terminated within the eighteen month period following the substantial completion of his relocation to Houston either (i) involuntarily and without Business Reasons or a Constructive Termination (as such terms are defined in the Employment Agreement), or (ii) following a Change of Control (as such term is defined in the Employment Agreement), then he shall receive a relocation package with terms, conditions and dollar value substantially the same as those provided in connection with his 2010 relocation to Houston in addition to any other compensation to which he is entitled pursuant to his Employment Agreement.

In addition, on May 10, 2010, Mr. Parikh and the Company entered into a relocation agreement (the “Relocation Agreement”) pursuant to which Mr. Parikh agreed to relocate from Stamford, Connecticut to Houston, Texas. The Relocation Agreement provides that the Company shall engage a relocation firm which will purchase Mr. Parikh’s residence for its fair market value, and pay Mr. Parikh an amount equal to the difference between $1,725,000 and the purchase price paid. Pursuant to the terms of the Relocation Agreement, Mr. Parikh shall also be reimbursed by the Company for (i) all reasonable sales expenses related to his residence in Connecticut including, among other things, fees, taxes, attorneys’ fees, inspection and closing costs, (ii) reasonable expenses incurred in connection with purchase of home in Houston including, among other things, temporary housing costs for up to six months, attorneys’ fees, inspection and closing costs, and (iii) reasonable moving and travel costs incurred therewith. The Company shall “gross up” Mr. Parikh for any taxes owed as a result of any payments received pursuant to the terms of the Relocation Agreement. Mr. Parikh shall also receive a lump sum payment of $15,000.

Departure of Executive Vice President

Effective May 14, 2010, Carole R. (“Robi”) Artman-Hodge, the Company’s Executive Vice President, was no longer employed by the Company. We will pay Ms. Artman-Hodge approximately $1.3 million during the three months ended June 30, 2010, which includes a severance payment described in her employment agreement with the Company, dated as of April 1, 1999, and a pro rated bonus for fiscal year 2010.

Item 6. Exhibits

The exhibits filed as part of this Quarterly Report are listed in the exhibit index immediately preceding such exhibits, which is incorporated herein by reference.

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Signatures

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date:	May 17, 2010	MXENERGY HOLDINGS INC.
		(Registrant)

		/s/ Jeffrey A. Mayer
		Jeffrey A Mayer
		President and Chief Executive Officer
		(Principal executive officer)


Date:	May 17, 2010	/s/ Chaitu Parikh
		Chaitu Parikh
		Chief Financial Officer
		(Principal financial officer and principal accounting officer)

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Index to Exhibits

Exhibit Number		Title
3.1		Second Amended and Restated Certificate of Incorporation of MXenergy Holdings Inc. (1)
3.2		Third Amended and Restated Bylaws of MXenergy Holdings Inc. (1)
10.75		Relocation Agreement, dated May 10, 2010, by and between MXenergy Holdings Inc. and Chaitu Parikh *#
10.76		First Amendment to Employment Agreement, dated as of May 14, 2010, by and between MXenergy Holdings Inc. and Chaitu Parikh *#
10.77		Severance Agreement, dated May 14, 2010, by and between MXenergy Holdings Inc. and Carole R. Artman-Hodge *#
31.1		Certification as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 *
31.2		Certification as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 *
32		Certification required by 18 United States Code Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 *†

*		Filed herewith.

†		Pursuant to Securities and Exchange Commission Release No. 33-8238, this certification will be treated as “accompanying” this Quarterly Report and not “filed” as part of such report for purposes of Section 18 of the Securities Exchange Act of 1934, or otherwise subject to the liability of Section 18 of the Securities Exchange Act of 1934 and this certification will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that the registrant specifically incorporates it by reference.

#		Material compensation contract.

(1)		Incorporated by reference to the Company’s Current Report on Form 8-K filed on September 28, 2009.

Attached files

MxEnergy Holdings Inc Reports

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