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Table of Contents

 

 

 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

(Mark One)

 

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

 

For the fiscal year ended June 30, 2009

 

OR

 

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

 

For the transition period from               to             

 

Commission File Number 333-138425

 

MXENERGY HOLDINGS INC.

(Exact Name of Registrant as Specified in Its Charter)

 

Delaware

 

20-2930908

(State or Other Jurisdiction of

 

(I.R.S. Employer Identification No.)

Incorporation or Organization)

 

 

 

 

 

595 Summer Street, Suite 300

 

 

Stamford, Connecticut

 

06901

(Address of Principal Executive Offices)

 

(Zip Code)

 

(203) 356-1318

(Registrant’s telephone number, including area code)

 


 

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

 

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

 

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

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes o No o

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    x

 

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

 

Large accelerated filer o

 

Accelerated filer o

 

 

 

Non-accelerated filer x

 

Smaller reporting company o

(Do not check if a smaller reporting company)

 

 

 

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

 

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

 

As of September 30, 2009, there were 54,305,112 shares of the Registrant’s common stock, par value $0.01 per share, outstanding.

 

Documents incorporated by reference: None

 

 

 



Table of Contents

 

MXENERGY HOLDINGS INC.

ANNUAL REPORT ON FORM 10-K

FOR THE FISCAL YEAR ENDED JUNE 30, 2009

 

TABLE OF CONTENTS

 

Item
Number

 

Page
Number

 

 

 

PART I

 

1.

Business

4

1A.

Risk Factors

19

1B.

Unresolved Staff Comments

28

2.

Properties

28

3.

Legal Proceedings

28

4.

Submission of Matters to a Vote of Security Holders

28

 

 

 

PART II

 

5.

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

29

6.

Selected Financial Data

30

7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

35

7A.

Quantitative and Qualitative Disclosures about Market Risk

62

8.

Financial Statements and Supplementary Data

65

9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

113

9A(T).

Controls and Procedures

113

9B.

Other Information

116

 

 

 

PART III

 

10.

Directors, Executive Officers and Corporate Governance

117

11.

Executive Compensation

122

12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholders Matters

138

13.

Certain Relationships and Related Transactions, and Director Independence

141

14.

Principal Accountant Fees and Services

146

 

 

 

PART IV

 

15.

Exhibits and Financial Statement Schedules

147

 

 

 

SIGNATURES

148

 

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Table of Contents

 

FORWARD-LOOKING STATEMENTS

 

Some statements in this Annual Report on Form 10-K (the “Annual Report”) are known as “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”).  Forward-looking statements include, but are not limited to, statements about our plans, objectives, expectations and intentions and other statements contained in the Annual Report that are not historical facts and may relate to, among other things:

 

·                  future performance generally;

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

·                  our post-acquisition integration of acquired businesses;

·                  expectations concerning future operations, margins, profitability, attrition, bad debt, 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 Annual 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,” 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;

·                  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 Annual 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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Table of Contents

 

PART I

 

ITEM 1.  BUSINESS

 

Definitions

 

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

 

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

 

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

 

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

 

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

 

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

 

Company Overview and History

 

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

 

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

 

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Table of Contents

 

 

Our Core Businesses and Products

 

Our core business is the retail sale of natural gas and electricity to end-use customers in deregulated markets in the U.S. and Canada.  Accordingly, our business is classified into two reportable business segments: natural gas and electricity.  Through these business units, natural gas and electricity are generally sold at contracted prices based on usage by customers. We buy natural gas and electricity in the wholesale market in time and location specific, bulk or block quantities at fixed and indexed prices.

 

We sell natural gas and electricity at variable or market-based prices that, in most cases, change monthly or at fixed prices for a forward term that generally does not exceed two years.  In the case of variable sales contracts as well as most mid-market commercial sales, we purchase natural gas or electricity at the time of sale.  In the case of fixed price retail customers, we purchase natural gas and electricity in advance of sales.  Costs are marked up with a reasonable profit margin.

 

For fixed price sales contracts, the cost of the commodity is hedged in the forward markets with financial swaps and physical forward contracts that settle monthly.  The natural gas and electricity is then purchased at the time such swaps and forward contracts settle.  We regularly calculate the amount of the commodity required to meet our expected customer deliveries and balance this against the quantity hedged or purchased for such customers.  Differences between expected customer deliveries and commodity purchases are managed by adjusting natural gas deliveries from storage and buying any shortfall or selling any excess in the spot market.

 

We market variations of two basic products:

 

·                              Fixed price contractsGenerally with terms of up to two years for natural gas and electricity, fixed rate products provide consumers with price protection against fluctuations in natural gas and electricity prices.  In marketing this product, we do not promise savings as a consumer could pay more if prices offered by a local utility or other competitor, which are based on variable market conditions, fall during the term of the fixed rate contract.

 

We have a risk management policy that is intended to reduce our financial exposure related to changes in the price

 

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of natural gas and electricity.  Under this policy, our objective is to hedge a minimum of 100% of the anticipated natural gas commodity purchases required to meet expected customer demand for all accounts served under fixed price contracts.  Any difference between actual consumption and our purchased commodity volume results in pricing risk for the month.

 

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

 

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

 

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

 

The natural gas and electricity sold is metered and delivered to customers by LDCs.  Except in our Georgia natural gas and Texas electricity markets and for certain of our commercial customers, LDCs generally provide billing and collection services on our behalf for residential and small commercial customers.  In the case of our Georgia and Texas retail markets, we bill and collect directly from customers the price of delivered commodity plus the charges associated with the local utility’s distribution costs, the latter of which is remitted to such utility.

 

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

 

 

 

Fiscal Year Ended June 30,

 

 

 

2009

 

2008

 

2007

 

 

 

Sales

 

% of
Total

 

Sales

 

% of
Total

 

Sales

 

% of
Total

 

 

 

($ in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas

 

$

670,584

 

85

 

$

669,522

 

89

 

$

680,811

 

97

 

Electricity

 

119,196

 

15

 

82,761

 

11

 

23,115

 

3

 

Total sales

 

$

789,780

 

100

 

$

752,283

 

100

 

$

703,926

 

100

 

 

Recent Developments and Trends

 

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 natural gas inventory component of the available borrowing base under our revolving credit facility with a syndicate of banks (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 our principal commodity hedge facility (the “Hedge Facility”). Such amendments had the following material direct impacts on our liquidity position:

 

·                  The maturity dates of the Revolving Credit Facility and Hedge Facility were extended to September 2009.

·                  The maximum amount that could be borrowed under the Revolving Credit Facility was reduced from $280.0 million at June 30, 2008 to $115.0 million at June 30, 2009, and $94.0 million effective July 31, 2009.

·                  We were required to actively seek a new facility to replace the Revolving Credit Facility and Hedge Facility.

 

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·                  Through June 30, 2009, we paid approximately $8.7 million of fees related to all amendments and extensions, which were deferred on the consolidated balance sheet and are being amortized as an increase to interest expense over the remaining lives of the Revolving Credit Facility and Hedge Facility.  During fiscal year 2009, we recorded approximately $7.5 million of incremental interest expense resulting from amortization of these deferred costs.

 

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 an equity and debt restructuring (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.  In particular, the Restructuring included, among other things, the transactions discussed below.

 

Amendment and Restatement of Corporate Documents

 

Effective September 22, 2009, our Certificate of Incorporation and Bylaws were amended and restated, and we entered into a new stockholder agreement with holders of various classes of our newly authorized common stock.  These documents contain customary provisions, including provisions relating to certain approval rights, preemptive rights, share transfer restrictions, rights of first refusal, tag-along rights and drag-along rights.

 

Additionally, the amended and restated Certificate of Incorporation authorized the issuance of 200,000,000 shares of Common Stock, consisting of 50,000,000 shares of Class A Common Stock, 10,000,000 shares of Class B Common Stock, 40,000,000 shares of Class C Common Stock and 100,000,000 shares of Class D Common Stock.  Prior to the consummation of the Restructuring, we had 4,681,219 shares of common stock issued and outstanding.  Those shares of common stock were exchanged for 4,499,588 shares of newly authorized Class C Common Stock, which represented 8.29% of the aggregate shares of common stock outstanding after the consummation of the Restructuring.  Additional shares of Class A Common Stock, Class B Common Stock and Class C Common Stock were issued to various parties as a result of the Restructuring, as described separately below.

 

As a result of amendments and restatements to our corporate documents, effective September 22, 2009, our board of directors increased to nine members from eight members prior to consummation of the Restructuring.  The composition of the new board of directors (the “Board of Directors”) is described below:

 

·                  Holders of the Class A Common Stock are entitled to nominate and elect five directors, at least two of whom shall be independent and qualify as a “financial expert.”

·                  The holder of Class B Common Stock is entitled to nominate and elect one director (the “Class B Director”).

·                  Holders of Class C Common Stock are entitled to nominate and elect two directors (the “Class C Directors”).

·                  The ninth Director is Holdings’ president and chief executive officer.

 

Refer to Part III of this Annual Report for the names and backgrounds of members of the Board of Directors.

 

Exchange of Floating Rate Notes due 2011 for Cash, Fixed Rate Notes due 2014 and Class A Common Stock

 

As of June 30, 2009, we had $165.2 million aggregate principal amount of Floating Rate Notes due 2011 outstanding (the “Floating Rate Notes due 2011”).  On September 22, 2009, we consummated an exchange offer pursuant to which we exchanged $158.8 million aggregate principal amount of Floating Rate Notes due 2011 for $26.7 million of cash, $67.8 million aggregate principal amount of new 13.25% Senior Subordinated Secured Notes due 2014 (the “Fixed Rate Notes due 2014”) and 33,940,683 shares of newly authorized Class A Common Stock.  The shares of Class A Common Stock issued to the holders of the Fixed Rate Notes due 2014 represented 62.5% of the aggregate shares of common stock outstanding after consummation of the Restructuring.  The Fixed Rate Notes due 2014 were issued at a discount, which will be recorded as a reduction from the Fixed Rate Notes due 2014 on our consolidated balance sheet 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.

 

Holders of $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 on our consolidated balance sheets until their maturity date in August 2011 unless acquired or retired by us on an earlier date.  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.

 

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New Master Hedge and Supply Agreement

 

As of June 30, 2009, we relied on the following credit, commodity hedging and commodity supply arrangements 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;

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

·                  Arrangements with numerous commodity suppliers to supply natural gas and electricity necessary for customer consumption in the markets that we serve.

 

Effective September 22, 2009, the Revolving Credit Facility and Hedge Facility were replaced by a new exclusive supply and commodity hedging agreement (the “Commodity Supply Facility”) with Sempra Energy Trading LLC (“RBS Sempra”), which effectively replaced the separate credit, hedging and supply arrangements outlined above.  As a condition to the entry into the agreements governing the Commodity Supply Facility, we issued 4,002,290 shares of newly authorized Class B Common Stock to RBS Sempra, which represented 7.37% of our aggregate shares of common stock outstanding after consummation of the Restructuring.  The aggregate fair value of the common stock issued to RBS Sempra was recorded as deferred financing costs in other assets on the consolidated balance sheets during the first quarter of fiscal year 2010 and will be amortized over the remaining term of the Commodity Supply Facility.

 

Conversion of Redeemable Convertible Preferred Stock to Class C Common Stock

 

As of June 30, 2009, we had 1,451,310 shares of Series A convertible preferred stock (the “Preferred Stock”) outstanding, which was recorded at its estimated redemption value of $54.6 million on the consolidated balance sheets.  On September 22, 2009, all outstanding shares of redeemable convertible preferred stock were exchanged for 11,862,551 shares of newly authorized Class C Common Stock, which represented 21.84% of the aggregate shares of our common stock outstanding after consummation of the Restructuring.  The excess of the redemption value over the aggregate fair value of common stock issued to the holders of Preferred Stock was reclassified to stockholders’ equity on the consolidated balance sheets during the first quarter of fiscal year 2010.  In connection with the Restructuring, we filed an amended and restated Certificate of Incorporation that does not authorize any preferred stock.

 

Termination of the Credit Agreement with Denham Commodity Partners LP (“Denham”)

 

As of June 30, 2009, we had a $12.0 million outstanding balance under a credit agreement with Denham Commodity Partners LP (the “Denham Credit Facility”).  On September 22, 2009, all amounts previously borrowed, including accrued and unpaid interest, were repaid and the Denham Credit Facility was terminated.

 

New Management Incentive Plan and Bonuses

 

In connection with the Restructuring, we anticipate that our board of directors will authorize the creation of a new management incentive plan (the “Management Incentive Plan”) pursuant to which they may issue Class C Common Stock not to exceed 10% of our outstanding common stock (on a fully diluted basis) after giving effect to the Restructuring.  We expect that the Management Incentive Plan will provide the board of directors the flexibility to make awards to employees, officers, directors, consultants and advisors and will permit, among other things, the grant of options to purchase shares of common stock that are intended to qualify as incentive stock options under Section 422 of the Internal Revenue Code, grants of options to purchase shares of common stock that will not so qualify, grants of stock appreciation rights, and grants of common stock at incentive prices or for free.

 

In addition, the compensation committee of the board of directors approved a total bonus pool equal to $750,000, which was paid to 19 of our executive officers and employees, including our chief executive officer and chief financial officer, upon consummation of the Restructuring.

 

Settlement and Cancellation of Existing Options and Warrants

 

As of June 30, 2009, we had options and warrants outstanding which were, or may be, 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 our common stock exceeded the current fair value of the common stock).  Pursuant to the Restructuring, we terminated the existing share-based

 

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compensation plans and offered a cash settlement to holders of options and warrants to cancel and terminate such options and warrants.  As a result, all outstanding options and warrants were cancelled and terminated.  The total amount paid for such cash settlement payments was approximately $0.2 million, which was recorded as a general and administrative expense during the first quarter of fiscal year 2010.

 

Our Customer Portfolio

 

Our customer base consists of residential and small and mid-market commercial customers.  We have limited exposure to high concentrations of sales volumes to individual customers.  For the fiscal years ended June 30, 2009, 2008 and 2007, our largest customer accounted for approximately 2% of total sales volume.

 

The following graph illustrates changes in our average annual RCE count from fiscal year 2005 through fiscal year 2009.

 

 

The reduction in average RCEs during fiscal year 2009 resulted primarily from liquidity-related limitations placed on our ability to obtain new customers and to retain existing customers and from high credit-related attrition in certain of our markets.  Volatility in natural gas prices negatively impacted our liquidity position and resulted in amendments to our Revolving Credit Facility, which placed formal constraints on the term and type of contracts that we could offer to new customers and to existing customers who informed us of their intent to terminate their contract before its termination date.

 

In order to conserve cash, we also reduced direct mail marketing and advertising expenditures and scaled back our use of certain sales channels during fiscal year 2009, which had a negative impact on brand awareness and our ability to acquire new customers.  As our overall liquidity position improves as a result of the Restructuring, we expect to return to our customary sales and marketing practices and channels.

 

Deteriorating economic conditions during fiscal year 2009 resulted in credit-related attrition that was higher than historical levels.  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 fiscal year 2009, we also initiated aggressive actions to disconnect service to delinquent customers in all of our markets and to enhance credit standards for all existing and prospective customers, which resulted in an increase in the number of potential new customers that were disqualified due to credit quality concerns.

 

During the final six months of the fiscal year ended June 30, 2008, natural gas commodity prices were increasing, and contract rates offered to our customers during this period were highly competitive within 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,

 

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commodity prices decreased significantly, and many of our customers migrated to current market rates that are lower than their original fixed rates or their post-introductory period variable rates with us.  In addition, for many of our markets during fiscal year 2009, we did not offer new competitive rates to customers who indicated their intention to terminate their contract.  The result was higher in-contract attrition during fiscal year 2009 than that experienced in prior years.

 

As of June 30, 2009, most of our current customers have been acquired organically through door-to-door, telemarketing, direct mail and internet sales channels.  While customer attrition is a natural part of our business, the marketing and customer care teams have focused efforts on customer retention via superior customer service and win back and loyalty initiatives.

 

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

 

Acquiring New Customers

 

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

 

In order to conserve cash, we significantly reduced direct mail marketing, advertising and overall marketing expenditures during fiscal year 2009, as compared to the prior fiscal year.  We also scaled back our use of certain sales channels, which had a negative impact on brand awareness and new customer acquisitions during fiscal year 2009.

 

Retaining and Winning Back Customers

 

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

 

Customer Renewals and Attrition

 

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

 

 

 

Fiscal Year Ended June 30,

 

 

 

2009

 

2008

 

2007

 

 

 

 

 

 

 

 

 

Customer renewal percentage (1)

 

84.1

%

84.9

%

89.8

%

In-contract attrition percentage (2)

 

34.0

 

19.7

 

25.6

 

 


(1)          At the end of each customer contract term, customer contracts in most of our markets are renewed upon notification by the marketers unless the customer indicates otherwise.  Customer renewal percentages in the table represent the percentage of customers who received such notification that ultimately continued their relationship with us.

(2)          In-contract customer attrition percentage is defined as: (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 customer renewal percentage for the fiscal year ended June 30, 2008 includes the impact of a large municipal aggregation of customers that did not renew its contract with us at the end of its contract term due to regulatory changes in the Ohio market.  Excluding this impact, the customer renewal percentage was approximately 87.9% for the fiscal year ended June 30, 2008.

 

Higher in-contract attrition during fiscal year 2009 resulted from several factors:

 

·                  The loss of any variable rate customer is included is the in-contract attrition rate.  Therefore, as the percentage of our variable rate customers increased from 40% at June 30, 2008 to 55% at June 30, 2009, the in-contract attrition rate rose as well.

·                  Deteriorating economic conditions during fiscal year 2009 resulted in credit-related attrition that was higher than historical levels.  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-

 

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guaranteed markets, such as our Ohio, Michigan and Indiana natural gas markets.  During fiscal year 2009, we initiated aggressive actions to disconnect service to delinquent customers in all of our markets and to enhance credit standards for all existing and prospective customers.  Credit-related attrition was particularly high in Georgia, 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 final six months of the fiscal year ended June 30, 2008, natural gas commodity prices were increasing, and contract rates offered to our customers during this period 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 current market rates that were lower than their original fixed rates or their post-introductory period variable rates with us.  In addition, for many of our markets during fiscal year 2009, we did not offer new competitive rates to customers in many of our markets who indicated their intention to terminate their contract.  The result was higher in-contract attrition during fiscal year 2009.

 

·                  Volatility in natural gas prices negatively impacted our liquidity position, which resulted in amendments to the Revolving Credit Facility that placed formal constraints on the term and type of contracts that we could offer to our customers.  As such, our ability to offer long-term fixed rate products to customers was severely limited.  Additionally, when customers informed us of their intent to terminate their contract before its termination date, our options for offering new contracts were limited, which contributed to attrition.

 

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 in RCEs in any of our markets does not necessarily correlate directly with customer attrition.

 

Customer Contract Concentrations

 

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

 

As of June 30, 2009 and 2008, approximately 45% and 60%, respectively, of our natural gas customer portfolio had fixed rate contracts while the remaining 55% and 40%, respectively, had variable rate contracts.  We have a risk management policy that is intended to reduce our financial exposure related to changes in the price of natural gas and electricity.  Under this policy, our objective is to hedge a minimum of 100% of the anticipated natural gas commodity purchases required to meet expected customer demand for all accounts served under fixed price contracts.  We also have a natural gas hedging facility that limits our exposure to mark-to-market margin payments.  As of June 30, 2009, contracts with our fixed price natural gas customers have an average remaining life of approximately 9 months.

 

As of June 30, 2009 and 2008, approximately 36% of our electricity customer portfolio had fixed rate contracts while the remaining 64% had variable rate contracts.  Our objective is to hedge 100% of anticipated electricity commodity purchases required to meet expected customer demand for accounts served under fixed rate electricity contracts.   As of June 30, 2009, contracts with our fixed price electricity customers have an average remaining life of approximately 11 months.

 

Market Concentrations

 

Geographic Concentrations

 

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

 

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·                  benefit from a diverse geographic stream of sales;

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

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

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

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

·                  lower the risk of extreme regional weather patterns;

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

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

·                  capitalize on our regional supply and pricing knowledge.

 

Guaranteed and Non-Guaranteed Market Concentrations

 

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

 

Within twenty-nine of the markets that we serve, we operate under a purchase of receivables program whereby all billed receivables are purchased by the LDC.  We refer to these markets as “guaranteed” markets.  For fiscal years 2009 and 2008, 45% and 44%, respectively, of our total sales of natural gas and electricity were within markets where LDCs guarantee customer accounts receivable at a weighted average discount rate of approximately 1%.  Such discount is the cost of service to guarantee the customer accounts receivable.  Within these markets, we are exposed only to the credit risk of the LDC, rather than that of our customers.  We monitor the credit ratings of LDCs and the parent companies of LDCs that guarantee customer accounts receivable.  We also periodically review payment history and financial information for LDCs to ensure that we identify and respond to any deteriorating trends.  As of June 30, 2009, all of our customer accounts receivable in LDC-guaranteed markets was with LDCs with investment grade credit ratings.

 

During the second half of fiscal year 2009, two LDCs in New York that previously did not guarantee our customer accounts receivable began guaranteeing such receivables.  Recent legislation in Massachusetts will also require electricity LDCs to guarantee the accounts receivable of retail suppliers, although the time frame for this implementation is currently unknown.  Newly approved regulations in Maryland require natural gas and electricity utilities to either guarantee supplier receivables or improve the way customer payments are allocated to suppliers.  We anticipate that the two natural gas markets in Maryland where we currently operate will begin guaranteeing suppliers’ receivables during calendar year 2010.

 

These actions by regulators and LDCs to guarantee customer accounts receivable are expected to improve the collectability of customer accounts receivable in our existing markets and should make entry into certain new markets more attractive.

 

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Geographic Market Concentrations

 

RCEs by geographic area as of the end of the fiscal years ended June 30, 2009, 2008 and 2007 are summarized in the following table.

 

 

 

RCEs at June 30,

 

 

 

2009

 

2008

 

2007

 

 

 

 

 

%

 

 

 

%

 

 

 

%

 

 

 

 

 

of

 

 

 

of

 

 

 

of

 

 

 

No.

 

Total

 

No.

 

Total

 

No.

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Southern U.S. (1):

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas

 

197,000

 

 

 

241,000

 

 

 

209,000

 

 

 

Electricity

 

25,000

 

 

 

25,000

 

 

 

12,000

 

 

 

 

 

222,000

 

40

%

266,000

 

38

%

221,000

 

35

%

Northeastern U.S., Mid-Atlantic U.S. and Canada (2):

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas

 

138,000

 

 

 

156,000

 

 

 

139,000

 

 

 

Electricity

 

50,000

 

 

 

73,000

 

 

 

31,000

 

 

 

 

 

188,000

 

33

%

229,000

 

33

%

170,000

 

27

%

Midwestern U.S. (3):

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas

 

152,000

 

 

 

205,000

 

 

 

240,000

 

 

 

Electricity

 

 

 

 

 

 

 

 

 

 

 

 

152,000

 

27

%

205,000

 

29

%

240,000

 

38

%

Total RCEs:

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas

 

487,000

 

 

 

602,000

 

 

 

588,000

 

 

 

Electricity

 

75,000

 

 

 

98,000

 

 

 

43,000

 

 

 

Total

 

562,000

 

100

%

700,000

 

100

%

631,000

 

100

%

 


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

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

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

 

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

 

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

 

Northeastern U.S., Mid-Atlantic U.S. and Canadian markets — Total RCEs within these regions decreased 18% during fiscal year 2009, primarily driven by lower customer counts in our New York and Connecticut electricity markets.  In addition to the impact of liquidity constraints, we were unable to sustain competitive offers due partly to term and pricing restrictions imposed on us by amendments to the Revolving Credit Facility.  A sizeable increase in the number of new retail marketers in New York, New Jersey and Connecticut offering higher commissions to contracted direct marketing personnel adversely impacted direct sales recruitment efforts.

 

Two LDCs in New York that previously did not guarantee customer accounts receivable began guaranteeing such receivables during fiscal year 2009, lowering our credit risk in those markets.

 

Recent legislation in Massachusetts will require electricity LDCs to guarantee the accounts receivable of retail suppliers, although the time frame for this implementation is currently unknown.  Newly approved regulations in Maryland will require natural gas and electricity utilities to either guarantee supplier receivables or improve the way customer payments are allocated to suppliers.  It is anticipated that these changes will be implemented during calendar year 2010.  New initiatives that will increase the attractiveness of certain Pennsylvania electricity and natural gas markets will begin taking effect early in 2010.

 

Midwestern U.S. markets — Total RCEs in this region decreased 26% during fiscal year 2009.  Lower customer counts can be attributed to competitive pressure and sales and marketing budgetary constraints.  Recent retail auction activity in Ohio resulted in extremely favorable LDC pricing, limiting growth potential and increasing attrition for retail marketers.  The

 

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Company’s contract term limitations also significantly impacted growth opportunities in the Michigan market.

 

Potential market growth — For fiscal year 2010, we will explore expansion into other LDC markets that are open to competition and appear to provide attractive growth potential.  Rapid market entry can be realized with minimal business disruption by leveraging our existing IT infrastructure and operational platforms, and our existing sales channels.  We continue to monitor existing and new market opportunities.  The decision to enter into new LDC territories will continue to be governed by several factors, including:

 

·                  compatibility with our existing operating systems and supply base;

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

·                  competitive landscape;

·                  mass market consumption profiles;

·                  regulatory climate;

·                  market location and size; and

·                  our ability to provide value to customers.

 

In September 2008, we received our certificate of qualification to conduct business in the State of California.  We are currently evaluating the feasibility of entering this market.

 

Acquisitions

 

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

 

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

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

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

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

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

 

Some of the companies we acquired were located in markets not previously served by us and therefore, provided us with new strategic marketing opportunities.  We intend to continue this strategy when evaluating new acquisition opportunities.

 

Since 2005, we have completed the following acquisitions:

 

Acquisition Date

 

Company / Business Acquired

 

Number and Type of RCEs Acquired

 

 

 

 

 

November 2005

 

Castle Power LLC

 

53,000 natural gas

August 2006

 

Shell Energy Services Company L.L.C.

 

315,000 natural gas

May 2007

 

Vantage Power Services L.P.

 

12,000 electricity

January 2008

 

GasKey division of PS Energy Group, Inc.

 

60,000 natural gas

October 2008

 

Catalyst Natural Gas LLC

 

38,000 natural gas

 

Market Deregulation and Competition

 

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

 

Increasing our market share depends in part on our ability to convince customers to switch to our service.  The local utilities and their affiliates have the advantage of long-standing relationships with their customers, and they may have longer operating histories, greater financial and other resources, and greater name recognition in their markets than we do.  In addition, local utilities have been subject to many years of regulatory oversight and thus have significant experience regarding the regulators’ policy preferences, as well as a critical economic interest in the outcome of proceedings concerning their revenues and terms and conditions of service.  The incumbents’ advantages in many markets are intended to be limited, however, by regulatory structures that, for example, prohibit incumbents from offering non-standard service and pricing structures, minimize the opportunity for the regulated business to subsidize the unregulated business and limit the ability of the utilities to solicit customers that have switched.  In Georgia and Texas, however, the market is fully deregulated where the incumbent utilities no longer use a regulated benchmark price.

 

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

 

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

 

Deregulated Natural Gas Industry

 

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

 

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

 

According to the United States Energy Information Agency (“EIA”), as of December 2008, twenty-one states and the District of Columbia have legislation or programs in place that let residential consumers and other small-volume users purchase natural gas from someone other than their traditional utility company.  As of December 2008, of the approximately 64.4 million total residential natural gas customers in the U.S., nearly 34.9 million have access to choice programs, with approximately 4.7 million (or 13.5% of eligible customers) actually purchasing from residential marketers.  State regulators continue to refine and evaluate existing programs in order to promote a competitive marketplace.  The low penetration rate, coupled with the desire for a competitive marketplace, has created attractive growth opportunities for residential marketers such as us.

 

Deregulated Electricity Industry

 

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

 

As a result of federal and state initiatives, the electric power industry in several states has changed from a structure characterized by highly regulated, vertically integrated local monopolies, which provide their customers with a comprehensive package of electricity services, to a deregulated structure.  The deregulated structure includes independent power producers and unregulated owners of electricity generation, competitive providers like us who supply electricity to end-use customers, and utilities that continue to provide transmission or distribution services as common carriers.  According to the EIA, as of 2008, there are 14 states (Connecticut, Delaware, Illinois, Maine, Maryland, Massachusetts, Michigan, New Hampshire, New Jersey, New York, Ohio, Pennsylvania, Rhode Island, and Texas) and the District of Columbia that operate retail markets in which customers may choose alternative electricity suppliers.

 

Competition

 

We focus on markets that are less susceptible to competitive pressures on profit margins and that lend themselves to mass-market techniques.  As of December 31, 2008, there were approximately 99 licensed and active natural gas marketers serving customers in deregulated states throughout the country.  Marketers competing for the commercial and residential markets fall

 

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into three categories: utility affiliates, national marketers and niche marketers.  The commitment of many of these marketers is often modest, confined to a limited geographic region, and supported by limited capital, personnel and operational infrastructure.

 

The number of active competitive retail marketers ranges from 2 to 13 in most of the states that we serve, with as many as 50 in New York.  In addition to all local utilities, we consider our main retail competitors in natural gas to be Georgia Natural Gas, Direct Energy (an affiliate of UK based Centrica), Gas South, Vectren Source, IDT Energy, Dominion Retail Energy (a deregulated affiliate of Dominion Resources, Inc.), Just Energy and Interstate Gas Services.  For electricity, our primary retail competitors are ConEd Solutions, Direct Energy, Hudson Energy, StarTex Power, TXU Energy, Reliant Energy, Champion Energy Services and Dominion Retail Energy.

 

Seasonality of Operations

 

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

 

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

 

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 operating results for an entire fiscal year may not be materially impacted by such trends due to our commodity hedging and contract pricing strategies, commodity price movements can have material short-term impacts on monthly and quarterly operating results, which should be considered in the context of our entire annual operating cycle.

 

Commodity Supply and Pricing Risk Management

 

Natural Gas Supply

 

Prior to September 22, 2009, we purchased natural gas supply and managed transportation logistics internally.  Historically, we purchased physical supply from more than 50 natural gas producers, marketers, and energy trading firms in either a producing region or at delivery points.  We periodically adjusted our portfolio of purchase/sales contracts, storage and transportation capacity based upon continual analysis of our forecasted load requirements, and determined whether it will be more economical to utilize natural gas from storage or to purchase from the spot market, with consideration given to transportation costs and availability.  Natural gas was delivered to the LDC city-gate or other specified delivery points where the LDC took control of the natural gas and delivered it to individual customers’ locations of use, utilizing its extensive network of small diameter distribution pipe.

 

Effective September 22, 2009, under the Commodity Supply Facility, we purchase natural gas supply from RBS Sempra, as our exclusive natural gas supplier.  RBS Sempra will also manage our interstate pipeline and storage facilities, and will be responsible for delivery of natural gas to LDC city-gates, as directed by us.

 

LDCs provide ancillary services such as billing, meter reading and balancing services.  Because of this extensive transportation infrastructure and the services provided, LDC costs typically make up a significant portion of the end user’s utility bill.

 

Electricity Supply

 

Prior to September 22, 2009, we purchased physical electricity supply from the respective independent system operator (“ISO”), for all our power customers in New York, Connecticut and Massachusetts.  In Texas, we purchased physical electricity directly from various counterparties for delivery to the Electric Reliability Council of Texas (“ERCOT”) based on prices established by the regional transmission organization (“RTO”).

 

Effective September 22, 2009, under the Commodity Supply Facility, we purchase electricity from RBS Sempra, as our exclusive

 

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electricity supplier.

 

Commodity Pricing Risk Management

 

We have a risk management policy that is intended to reduce our financial exposure to changes in the prices of natural gas and electricity.  Under this policy, the Company hedges all anticipated natural gas and electricity commodity purchases required to meet expected customer demand for all accounts served under fixed price contracts.  To manage weather risk, we may hedge up to 110% in the winter months with respect to customer demand in certain natural gas utilities with daily balancing requirements and up to 110% in the summer months with respect to customer on-peak demand in certain electricity utilities.  We also utilize options in order to mitigate both weather and attrition risks.

 

We utilize both physical and derivative instruments to reduce our exposure to fluctuations in the prices of natural gas and electricity.  Natural gas commodity derivatives used as economic hedges typically have included swaps and options executed under our Hedge Facility.  Electricity commodity derivatives used as economic hedges have been executed with a select number of counterparties, including Sempra Energy Trading Corp., Constellation Energy Commodities Group and BP North America.  As of June 30, 2009, our hedge positions extend through December 2011.

 

We utilize New York Mercantile Exchange (“NYMEX”) referenced over-the-counter swaps, basis price swaps and options to economically hedge the risk of variability in the cost of natural gas.  Refer to “Item 7A. Quantitative and Qualitative Disclosures About Market Risk”, for additional commentary regarding commodity price risk management.

 

Foreign Operations

 

Our principal foreign operations are located in Canada.  Foreign operations comprised less than 1% of our consolidated total assets at June 30, 2009 and less than 1% of our consolidated sales of natural gas and electricity for the fiscal year ended June 30, 2009.

 

Management Team and Employees

 

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

 

As of June 30, 2009, we had approximately 215 full-time equivalent employees in the United States and Canada.  None of our employees are subject to a collective bargaining agreement, and we believe that our relationship with our employees is good.

 

Committed and Knowledgeable Equity Ownership

 

Our equity ownership has changed as a result of the Restructuring consummated on September 22, 2009.  Refer to Part III of this Annual Report for additional information.

 

As of June 30, 2009, our primary stockholders included Denham Commodity Partners Fund LP (“Denham”), Charterhouse Group Inc. (“Charterhouse”) and Greenhill Capital Partners (“GCP”).  These stockholders have made equity investments that have provided us with sufficient financial capital to grow and support our business.  In addition, these stockholders have an in-depth understanding of the energy and financial markets, and provide strength and insight for our activities and strategy.

 

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

 

Charterhouse is a New York-based, middle-market private equity investment firm with a focus on buyouts, build-ups and growth capital financings.  Charterhouse made an initial investment in us in 2004.  Charterhouse invests in the business services (including the energy services sub-sector), consumer, and healthcare services sectors.  Established in 1973, Charterhouse has invested over $2 billion in equity capital in various companies, including us.

 

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GCP is an affiliate of Greenhill & Co., Inc. (“Greenhill”), an independent global investment banking firm publicly traded on the New York Stock Exchange.  GCP manages several private equity funds which total approximately $1.8 billion in capital, focusing on the energy, financial services, for-profit education and telecommunications industries.  Greenhill was founded in 1996 and provides financial advisory and merchant banking fund management services through its offices in the U.S., Europe and Japan.

 

Environmental Matters

 

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

 

Where You Can Find More Information

 

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

 

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

 

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ITEM 1A.   RISK FACTORS

 

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

 

Risks Related to Our Business

 

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

 

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

 

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

 

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

 

Although our fixed price contracts with residential customers generally have terms of up to two years, those customers may terminate their contracts at any time for a termination fee that, in most cases, is relatively modest and does not bear any relation to our costs or lost profit with respect to the remainder of the contract.  Most of our small and mid-market commercial customers cannot terminate their fixed price contracts without triggering a damages provision designed to cover costs related to the termination of those contracts.  For larger commercial customers, we utilize various means to ensure that we recover our costs, including legal remedy if appropriate. We depend on our hedging strategies to cover the costs related to terminations by residential and small commercial customers.  To hedge effectively against terminations, we must, at the inception of the contracts, attempt to accurately forecast the number of residential and small commercial customers that will terminate their contracts prior to the end of their term.  If we experience a number of cancellations greater than originally forecasted or if we are not able to replace terminating customers with new customers, our financial results may be negatively impacted.  Conversely, if forecasted attrition is higher than actual realized attrition, we are at risk for having to source additional hedges or supply at potentially higher market prices where no price increase can be passed on to customers through the duration of their contract terms.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

We bear direct credit risk related to our customers located in Georgia, Texas and Florida, and for our mid-market commercial customers located in New York, New Jersey and Ohio.  This group of customers represented approximately 55% of our sales of natural gas and electricity during the fiscal year ended June 30, 2009.  With the exception of customers in Georgia and Texas, we have the ability to terminate our agreement with customers in the event of non-payment, but we cannot terminate their electric or gas service.  Even if we terminate service to customers who fail to pay their utility bill, we remain liable to our suppliers of electricity and natural gas for the cost of those commodities.  Furthermore, in the Georgia and Texas markets, we are responsible for billing the distribution charges for the local utility and are at risk for these charges, in addition to the cost of the commodity, in the event customers fail to pay their bills.  Changing economic factors, such as

 

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rising unemployment rates and energy prices also result in a higher risk of customers being unable to pay their bills when due.

 

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

 

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

 

In certain markets, we rely on the utilities to guarantee customer accounts receivable and to perform timely and accurate billing.  These guaranteed markets represented approximately 45% of our sales of natural gas and electricity during the fiscal year ended June 30, 2009. As our business grows, the proportion of customers we serve that are billed by utilities could increase.  The bankruptcy of a utility could result in a default in such utility’s payment obligations to us.

 

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

 

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

 

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

 

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

 

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

 

·                  our internal marketing, pricing and customer operations functions;

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

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

 

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

 

·                  inaccurate and/or untimely bills sent to customers;

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

·                  customer complaints; and

·                  increased regulatory scrutiny.

 

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

 

Prior to the consummation of the Restructuring, we purchased natural gas from more than 50 natural gas producers, marketers and energy trading firms in either a producing region or at delivery points.  These numerous suppliers ensured a competitive pricing environment in which we could seek the lowest possible price for our business.  Effective September 22, 2009, we are required to purchase a minimum amount of natural gas annually from RBS Sempra under an exclusive supply

 

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arrangement.  As a result, competitive bidding between potential suppliers may be reduced, which may result in higher commodity costs and lower gross profit per MMBtu sold to our customers.

 

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

 

Prior to the consummation of the Restructuring, we managed gas supply, storage capacity and transportation logistics internally.  We have well-trained management and staff who have developed strong expertise and effective working relationships related to these functions.  Effective September 22, 2009, RBS Sempra now manages these functions in connection with the Commodity Supply Facility.  If RBS Sempra fails to effectively manage these functions, or to appropriately utilize our expertise, deliveries of natural gas to LDCs, and ultimately to our customers, could become less reliable, which could have a negative impact on our reputation and results of operations.

 

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

 

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

 

We also depend on local utilities for maintenance of the infrastructure through which we deliver electricity and natural gas to our customers.  We are unable to control the level of service the utilities provide to our customers.  Any infrastructure failure that interrupts or impairs delivery of electricity or natural gas to our customers could cause customer dissatisfaction, which could adversely affect our business.  If transportation or transmission is disrupted, or if transportation or transmission capacity is inadequate, our ability to sell and deliver products may be hindered.  Such disruptions could also hinder our providing electricity or natural gas to our customers and adversely impact our risk management policies, hedge contracts and financial results and condition.

 

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

 

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

 

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

 

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

 

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

 

We depend on continued state and federal regulation to permit us to operate in deregulated segments of the natural gas and electricity industries.  If competitive restructuring of the natural gas and electricity utility industries are

 

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altered, reversed, discontinued or delayed, our business prospects and financial results could be materially adversely affected.

 

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

 

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

 

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

 

We intend to continue to assess new product offerings, apply new technologies for our business development and make investments in acquisitions of complementary companies.  If we buy a company or business, we may experience difficulty integrating that company’s personnel and operations, or key personnel of the acquired company may decide not to work for us.  Furthermore, if we acquire the residential or small commercial businesses of an incumbent utility or other energy provider in a particular market, the customers of that entity may not be under any obligation to use our services.  If we make other types of acquisitions, we may experience difficulty in assimilating the acquired technology or products into our operations or information systems.  These difficulties could disrupt our ongoing business, distract our management and employees, and increase our expenses.

 

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

 

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

 

Expanding our operations also may require continued development of our operating and financial controls and may place additional stress on our management and operational resources.  If we are unable to manage our growth and development successfully, our operating results, financial condition and internal controls over financial reporting could be adversely affected.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

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

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

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

 

Such failures to perform by our business counterparties could have an adverse effect on our business, results of operations and financial condition.

 

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

 

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

 

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

 

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

 

·                  higher customer complaints and attrition;

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

·                  damage to our reputation with customers and regulators.

 

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

 

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

 

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

·                  inaccurate or non-timely customer billing information;

·                  customer complaints;

·                  increased regulatory scrutiny;

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

 

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

 

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

 

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

 

We have a business continuity plan that is periodically reviewed and enhanced to ensure that the effects of such disruptions on our operations result in minimal impact on service provided to our customers and on our results of operations.  If our business continuity plan does not function as planned, our operations, financial position and results of operations may be negatively impacted.

 

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

 

The power generation and transmission infrastructure in the U.S. is very complex.  Maintaining reliability of the infrastructure requires appropriate oversight by regulatory agencies, careful planning and design, trained and skilled operators, sophisticated information technology and communication systems, ongoing monitoring and, where necessary, improvements to various components of the infrastructure.  Despite extensive oversight and development of numerous safeguards, major electric power blackouts are possible, which could disrupt electrical service for extended periods of time to large geographic regions of the U.S. and Canada.  If such a major blackout were to occur, we may be unable to deliver electricity to our customers in the affected region, which would have an adverse impact on our results of operations.

 

We identified a material weakness in the design and operation of our internal controls over financial reporting as of June 30, 2009.  Although we have developed a remediation plan for the material weakness, there can be no assurance that such controls will effectively prevent material misstatements in our consolidated financial statements in future periods.

 

In connection with the preparation of our financial statements for fiscal year 2009, we reported to the Audit Committee of our Board of Directors that certain significant deficiencies in internal controls over financial reporting existed at June 30, 2009 that, when evaluated in the aggregate, we concluded to be a material weakness in the design and operation of internal control over financial reporting at June 30, 2009.  Therefore, we have concluded that, as of June 30, 2009, the Company’s internal control over financial reporting was not effective.

 

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 identified as of June 30, 2009 relates to certain significant deficiencies that we identified 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.  These significant deficiencies resulted in adjustments to our accounting records at June 30, 2009 that 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.

 

To remedy this material weakness, we have identified certain controls or processes that have been, or will be, put into place with the intent to mitigate the risk of potential future misstatements from the identified significant deficiencies.  While we believe that these new controls and processes will remedy the material weakness, we have not yet tested our newly implemented controls and there can be no assurance that such controls will effectively prevent material misstatements in our consolidated financial statements in future periods.

 

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Risks Related to Liquidity, Indebtedness and Capital Structure

 

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

 

Our business requires substantial capital to fund growth through organic marketing or acquisition, for supporting working capital, for the purchase of natural gas and electricity supply to meet our customers’ needs, and for the credit requirements of forward physical supply.  We may need to incur additional debt or obtain additional letter of credit capacity in order to fund working capital, finance other acquisitions or for other purposes.  Our ability to obtain new financing will be constrained by the current economic conditions affecting financial markets and by the restrictive covenants contained in the agreements that govern the Commodity Supply Facility and the Fixed Rate Notes due 2014.  Specifically, the recent credit crisis and other related trends affecting the banking industry have caused significant operating losses and failures throughout the banking industry.  Many lenders and institutional investors have ceased to provide funding to worthy borrowers.  We may be unable to take advantage of opportunities to acquire customer portfolios or operations of other retail energy businesses, to finance our existing operations or to otherwise expand our business as planned.  We cannot be certain that we will be able to obtain such additional financing on favorable terms or at all.  If we need additional debt or letter of credit capacity and cannot raise it on acceptable terms, our financial condition and business will be adversely affected.

 

We will require a significant amount of cash to service our debt obligations.  Our ability to generate sufficient cash to service debt depends on the ability of our primary operating subsidiaries to generate adequate cash flow.  We are limited in our ability to utilize the proceeds from new debt and equity issuances to prepay and repay the Fixed Rate Notes due 2014.

 

Holdings has no material operating activities.  Accordingly, Holdings’ only material source of cash, including cash to service the Commodity Supply Facility, Fixed Rate Notes due 2014 and the Floating Rate Notes due 2011, comes from Holdings’ ownership interests in its primary operating subsidiaries.  Available distributions from our operating subsidiaries may depend on factors out of our control, which may include:

 

·                  the financial performance of our operating subsidiaries;

·                  covenants contained in our debt agreements;

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

·                  business and tax considerations; and

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

 

Our ability to make payments on and to refinance our debt, and to fund planned capital expenditures and expansion efforts and any strategic acquisitions we may make in the future, if any, will depend on our ability to generate cash in the future.  This, to a certain extent, is subject to general economic, financial, competitive and other factors that are beyond our control.  There can be no assurance that our business will generate sufficient cash flow from operations in the future, that our currently anticipated growth in net sales and cash flow will be realized or that future borrowings will be available to us in an amount sufficient to enable us to repay indebtedness.  Additionally, the terms of the Commodity Supply Facility limit our ability to incur additional indebtedness.  We may need to refinance all or a portion of our indebtedness on or before maturity.  There can be no assurance that we will be able to refinance any of our indebtedness on commercially reasonable terms or at all.

 

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

 

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

 

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

 

Our substantial debt obligations could have important consequences, which could include:

 

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

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

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

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

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

·                  limiting our ability to borrow additional funds.

 

Significant increases in energy prices or other adverse industry or financial trends that are outside of our direct control could cause us to draw down on a portion or all of our available credit.  We may require additional indebtedness in the future.  Our ability to obtain new debt is limited by the agreements governing the Commodity Supply Facility, the Fixed Rate Notes due 2014 and the Floating Rate Notes due 2011.  If new debt is added to current debt levels, the related risks described above could intensify. If such debt financing is not available when required or is not available on acceptable terms, we may be unable to grow our business, take advantage of business opportunities, respond to competitive pressures or refinance maturing debt, any of which could have a material adverse effect on our operating results and financial condition.

 

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

 

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

 

·                  incur additional indebtedness;

·                  create liens on assets;

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

·                  make investments;

·                  transfer or sell assets;

·                  guarantee debt;

·                  restrict dividends and other payments;

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

·                  engage in unrelated businesses.

 

In addition, under the Commodity Supply Facility, Holdings and its subsidiaries will be required to maintain a collateral coverage ratio.  If we breach any of the covenants contained in the agreements that govern the Commodity Supply Facility or the indenture that governs the Fixed Rate Notes due 2014, the principal of, and accrued interest on, the applicable debt could become due and payable.  In addition, that default could constitute a cross-default under our other indebtedness.  Although any default under the Fixed Rate Notes due 2014 is subject to certain standstill provisions, if such a default or cross-default were to occur, we would not be able to satisfy our debt obligations, which would have a substantial material adverse impact on our ability to continue as a going concern.  We cannot assure you that we will be able to comply with these restrictions in the future or that our compliance would not cause us to forego opportunities that might otherwise be beneficial to us.

 

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

 

The change in ownership and the change in composition of our board of directors, as well as the separate approval rights of holders of our Class A Common Stock, Class B Common Stock and Class C Common Stock, and their respective directors, could have an impact on the future direction of the Company, including decisions regarding financing arrangements, capital structure, senior management appointments and business operations.  The interests of the holders of the various classes of our common stock and their respective directors following consummation of the Restructuring may not be compatible with the interests of other shareholders and directors, or with the strategic objectives of senior management of the Company.

 

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Table of Contents

 

ITEM 1B.  UNRESOLVED STAFF COMMENTS

 

None.

 

ITEM 2.  PROPERTIES

 

Our corporate headquarters, which are comprised of executive, finance, marketing, risk management, internal audit and legal functions, are located in Stamford, Connecticut.  Several of our operational functions, including pricing, information technology, customer operations and data solutions, accounting operations, collections, and certain human resources functions are located in Houston, Texas, where most of our employees currently work.  We also have electricity operations and customer care staff located in Annapolis Junction, Maryland.

 

We lease all of our properties.  As of June 30, 2009, we believe that all properties are suitable and adequate for the business conducted therein, are being appropriately used and have sufficient capacity for the present intended purposes.

 

ITEM 3.  LEGAL PROCEEDINGS

 

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

 

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

 

We did not submit any matters to a vote of security holders during the fourth quarter of fiscal year 2009.

 

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Table of Contents

 

PART II.

 

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

 

There is no established trading market for our common stock, par value $.01 per share.  As of September 22, 2009, there were 47 holders of record of our Class A Common Stock, 1 holder of our Class B Common Stock and 66 holders or our Class C Common Stock.

 

Dividend Policy and Restrictions

 

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

 

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

 

Securities Authorized for Issuance Under Equity Compensation Plans

 

The table below provides information, as of June 30, 2009, concerning securities authorized for issuance under our equity compensation plans.

 

Plan Category

 

Number
of
securities
to be issued
upon
exercise of
outstanding
options (2)

 

Weighted
average
exercise
price of
outstanding
options

 

Number of
securities
remaining
available
for future
issuance
under equity
compensation
plans (3)

 

 

 

 

 

 

 

 

 

Equity compensation plans approved by security holders (1)

 

981,270

 

$

29.31

 

396,462

 

 


(1)          As of June 30, 2009, all of our equity compensation plans were approved by security holders.

(2)          Excludes 27,500 warrants issued to employees that were not issued under any equity compensation plan.  As of June 30, 2009, the weighted average exercise price for these warrants was $26.86.  Pursuant to the Restructuring, we offered a cash settlement to holders of options and warrants to cancel and terminate such options and warrants.  As of September 22, 2009, all options and warrants were terminated.

(3)          Excludes securities reflected in the first column.

 

Recent Sales of Unregistered Securities

 

On September 22, 2009, we consummated an exchange of $158.8 million aggregate principal amount of outstanding Floating Rate Notes due 2011 for $26.7 million of cash, $67.8 million of Fixed Rate Notes due 2014 and 33,940,683 shares of newly authorized Class A Common Stock.  The shares of Class A Common Stock issued to the holders of the Fixed Rate Notes due 2014 represented 62.5% of the total aggregate shares of common stock outstanding after consummation of the Restructuring.  Additionally, in connection with the Restructuring and as a condition of the agreements governing the Commodity Supply Facility, we issued 4,002,290 shares of newly authorized Class B Common Stock to RBS Sempra, which represented 7.37% of our total aggregate shares of common stock outstanding after consummation of the Restructuring.

 

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Table of Contents

 

ITEM 6.  SELECTED FINANCIAL DATA

 

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 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 for the reporting periods.  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 and electricity under the customer contracts and the associated realized gain (loss) on risk management activity.

 

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

 

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

 

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

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

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

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

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

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

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

 

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

 

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Table of Contents

 

The financial data included in the following table was derived from our consolidated financial statements, which are included elsewhere in this Annual Report.  The table includes a reconciliation from net income (loss) calculated on a U.S. GAAP basis to EBITDA and Adjusted EBITDA.  The financial information in the table should be read in conjunction with, and is qualified by reference to, our consolidated financial statements and notes thereto and commentary included in this section.

 

 

 

Fiscal Year Ended June 30,

 

 

 

2009

 

2008

 

2007

 

2006

 

2005

 

 

 

(in thousands)

 

Selected statement of operations data:

 

 

 

 

 

 

 

 

 

 

 

Sales of natural gas and electricity (1)

 

$

789,780

 

$

752,283

 

$

703,926

 

$

362,561

 

$

277,196

 

Cost of goods sold (1)

 

757,146

 

569,585

 

602,146

 

389,526

 

202,112

 

Gross profit (loss)

 

32,634

 

182,698

 

101,780

 

(26,965

)

75,084

 

Operating expenses

 

114,779

 

106,645

 

91,015

 

36,618

 

30,996

 

Operating (loss) profit

 

(82,145

)

76,053

 

10,765

 

(63,583

)

44,088

 

Interest expense, net of interest income

 

45,305

 

34,105

 

33,058

 

3,200

 

2,858

 

(Loss) income before income tax benefit (expense)

 

(127,450

)

41,948

 

(22,293

)

(66,783

)

41,230

 

Income tax benefit (expense)

 

27,249

 

(17,155

)

8,495

 

27,001

 

(18,142

)

Net (loss) income

 

(100,201

)

24,793

 

(13,798

)

(39,782

)

23,088

 

 

 

 

 

 

 

 

 

 

 

 

 

Items to reconcile net (loss) income to EBITDA:

 

 

 

 

 

 

 

 

 

 

 

Add:

Interest expense, net of interest income

 

45,305

 

34,105

 

33,058

 

3,200

 

2,858

 

 

Depreciation and amortization

 

37,575

 

32,698

 

27,730

 

8,504

 

6,166

 

 

Income tax (benefit) expense

 

(27,249

)

17,155

 

(8,495

)

(27,001

)

18,142

 

EBITDA

 

(44,570

)

108,751

 

38,495

 

(55,079

)

50,254

 

 

 

 

 

 

 

 

 

 

 

 

 

Items to reconcile EBITDA to Adjusted EBITDA:

 

 

 

 

 

 

 

 

 

 

 

Add (less):

Stock compensation expense

 

519

 

3,358

 

4,539

 

911

 

2,033

 

 

Unrealized losses (gains) from risk management activities, net (2)

 

87,575

 

(67,168

)

17,079

 

79,897

 

(16,004

)

Adjusted EBITDA

 

$

43,524

 

$

44,941

 

$

60,113

 

$

25,729

 

$

36,283

 

 

 

 

 

 

 

 

 

 

 

 

 

Selected balance sheet data (period-end balances):

 

 

 

 

 

 

 

 

 

 

 

Total current assets

 

$

203,506

 

$

271,973

 

$

257,708

 

$

67,517

 

$

157,122

 

Customer acquisition costs, net

 

27,950

 

41,693

 

38,954

 

10,822

 

7,171

 

Total assets

 

259,071

 

355,752

 

335,644

 

97,969

 

191,592

 

Total current liabilities

 

99,042

 

108,276

 

91,686

 

29,894

 

74,640

 

Long-term debt (3)

 

163,476

 

162,648

 

185,404

 

 

21,379

 

Redeemable convertible preferred stock (4)

 

54,632

 

48,779

 

29,357

 

29,357

 

29,357

 

Total stockholders’ equity

 

(72,150

)

33,210

 

25,611

 

35,393

 

75,920

 

 


(1)

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

(2)

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

(3)

The Floating Rate Notes due 2011 (net of original issue discount) were issued during the fiscal year ended June 30, 2007 primarily to provide financing for the acquisition of Shell Energy Services Company L.L.C. in August 2006 (the “SESCo Acquisition”), with the balance being used for working capital needs. Pursuant to the Restructuring, $158.8 million aggregate principal amount of Floating Rate Notes due 2011 were exchanged for cash, common stock and the Fixed Rate Notes due 2014.

(4)

On or after the fifth anniversary of the issuance of the Preferred Stock, if the fair market value of Holdings’ common stock was not at a level that would have provided the affiliates of Charterhouse and GCP (the “Preferred Investors”) with an annual rate of return of at least 25%, compounded annually, for the five-year period ending June 30, 2009, the Preferred Investors could have required that the Company make a redemption election. If the holders of the Preferred Stock required the Company to make a redemption election, and if the Company elected to redeem the Preferred Stock, the redemption amount would have been payable in cash equal to the greater of: (1) the fair market value of the shares of common stock into which the Preferred Stock could have been converted on the date of the redemption election notice; or (2) the original issue price of $21.36 per share, plus any accrual of dividends. If the Company elected not to redeem the Preferred Stock, it would have been required to grant the Preferred Investors effective control over Holding’s Board of Directors. As of June 30, 2009, if the holders of Preferred Stock had requested that the Company make a redemption election, the Company did not have the intent or the ability to redeem the Preferred Stock due to limitations included in the agreements that governed the Revolving Credit Facility, the Hedge Facility and the Floating Rate Notes due 2011. However, since the Preferred Investors would have effectively controlled the Company’s Board of Directors in the event that the Company did not elect to redeem the Preferred Stock, the Company has determined that, in accordance with U.S. GAAP, the Preferred Stock was redeemable at the option of the Preferred Investors and that it was probable that the Preferred Stock became redeemable at June 30, 2009. Therefore the carrying value of the Preferred Stock was recorded outside of stockholders’ equity on the consolidated balance sheets was adjusted to its redemption value as of June 30, 2009. As of June 30, 2009, the holders of Preferred Stock did not make an election to redeem the Preferred Stock. Pursuant to the Restructuring, the Preferred Stock was converted to Class C Common Stock on September 22, 2009.

 

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

 

 

 

Fiscal Year Ended June 30,

 

 

 

2009

 

2008

 

2007

 

2006

 

2005

 

 

 

 

 

 

 

 

 

 

 

 

 

Adjusted EBITDA

 

$

43,524

 

$

44,941

 

$

60,113

 

$

25,729

 

$

36,283

 

Interest expense, net of interest income

 

(45,305

)

(34,105

)

(33,058

)

(3,200

)

(2,858

)

Income tax benefit (expense)

 

27,249

 

(17,155

)

8,495

 

27,001

 

(18,142

)

Stock compensation expense

 

 

(1,654

)

 

 

 

Deferred tax (benefit) expense

 

(23,406

)

18,187

 

(14,449

)

(32,764

)

6,552

 

Unrealized losses on interest rate swaps and amortization of deferred financing fees

 

16,233

 

10,836

 

7,906

 

1,057

 

349

 

Amortization of customer contracts acquired

 

(634

)

(762

)

11,891

 

(3,276

)

 

Change in assets and liabilities, net of effects of acquisition:

 

 

 

 

 

 

 

 

 

 

 

Restricted cash

 

(74,781

)

463

 

(623

)

6,953

 

2,195

 

Accounts receivable

 

40,075

 

(30,181

)

3,453

 

(13,003

)

3,271

 

Natural gas inventories

 

36,509

 

(7,308

)

(1,712

)

(2,685

)

(72

)

Income taxes receivable

 

1,063

 

(7,173

)

5,184

 

(5,535

)

 

Option premiums

 

1,571

 

1,191

 

1,835

 

(1,834

)

 

Other assets

 

(20,509

)

609

 

(993

)

2,645

 

895

 

Accounts payable and accrued liabilities

 

(46,553

)

17,882

 

31,555

 

(5,320

)

1,283

 

Deferred revenue

 

(3,164

)

(4,352

)

9,384

 

865

 

1,538

 

Net cash (used in) provided by operating activities

 

$

(48,128

)

$

(8,581

)

$

88,981

 

$

(3,367

)

$

31,294

 

Net cash used in investing activities

 

$

(17,953

)

$

(33,941

)

$

(132,920

)

$

(18,825

)

$

(8,296

)

Net cash provided by (used in) financing activities

 

$

17,389

 

$

(22,462

)

$

174,788

 

$

(25,345

)

$

24,396

 

 

32



Table of Contents

 

Selected Data for Business Segments

 

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

 

Fiscal Year ended June 30,

 

Natural Gas

 

Electricity

 

Total

 

 

 

 

 

(in thousands)

 

 

 

2009:

 

 

 

 

 

 

 

Sales

 

$

670,584

 

$

119,196

 

$

789,780

 

Cost of goods sold (excluding unrealized gains (losses) from risk management activities, net) (1)

 

(572,616

)

(96,955

)

(669,571

)

Gross profit (excluding unrealized gains (losses) from risk management activities, net) (1)

 

$

97,968

 

$

22,241

 

120,209

 

 

 

 

 

 

 

 

 

Items to reconcile total segment gross profit to income before income tax expense:

 

 

 

 

 

 

 

Unrealized gains (losses) from risk management activities, net

 

 

 

 

 

(87,575

)

Operating expenses

 

 

 

 

 

(114,779

)

Interest expense, net of interest income

 

 

 

 

 

(45,305

)

 

 

 

 

 

 

 

 

Loss before income tax benefit

 

 

 

 

 

$

(127,450

)

 

 

 

 

 

 

 

 

2008:

 

 

 

 

 

 

 

Sales

 

$

669,522

 

$

82,761

 

$

752,283

 

Cost of goods sold (excluding unrealized gains (losses) from risk management activities, net) (1)

 

(564,219

)

(72,534

)

(636,753

)

Gross profit (excluding unrealized gains (losses) from risk management activities, net) (1)

 

$

105,303

 

$

10,227

 

115,530

 

 

 

 

 

 

 

 

 

Items to reconcile total segment gross profit to loss before income tax benefit:

 

 

 

 

 

 

 

Unrealized gains (losses) from risk management activities, net

 

 

 

 

 

67,168

 

Operating expenses

 

 

 

 

 

(106,645

)

Interest expense, net of interest income

 

 

 

 

 

(34,105

)

 

 

 

 

 

 

 

 

Income before income tax expense

 

 

 

 

 

$

41,948

 

 

 

 

 

 

 

 

 

2007:

 

 

 

 

 

 

 

Sales

 

$

680,811

 

$

23,115

 

$

703,926

 

Cost of goods sold (excluding unrealized gains (losses) from risk management activities, net) (1)

 

(565,531

)

(19,536

)

(585,067

)

Gross profit (excluding unrealized gains (losses) from risk management activities, net) (1)

 

$

115,280

 

$

3,579

 

118,859

 

 

 

 

 

 

 

 

 

Items to reconcile total segment gross profit to loss before income tax benefit:

 

 

 

 

 

 

 

Unrealized gains (losses) from risk management activities, net

 

 

 

 

 

(17,079

)

Operating expenses

 

 

 

 

 

(91,015

)

Interest expense, net of interest income

 

 

 

 

 

(33,058

)

 

 

 

 

 

 

 

 

Loss before income tax benefit

 

 

 

 

 

$

(22,293

)

 


(1)

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

 

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Table of Contents

 

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

 

 

 

Fiscal Year Ended June 30,

 

 

 

2009

 

2008

 

2007

 

2006

 

2005

 

Natural Gas:

 

 

 

 

 

 

 

 

 

 

 

RCEs at period end

 

487,000

 

601,000

 

588,000

 

375,000

 

337,000

 

Average RCEs during the period

 

554,000

 

588,000

 

595,000

 

380,000

 

338,000

 

MMBtus sold during the period

 

54,806,000

 

54,339,000

 

57,064,000

 

35,488,000

 

32,957,000

 

Sales per MMBtu sold during the period

 

$

12.24

 

$

12.32

 

$

11.93

 

$

9.74

 

$

8.03

 

Gross profit per MMBtu during the period (1)

 

$

1.79

 

$

1.94

 

$

2.02

 

$

1.38

 

$

1.75

 

Heating degree days

 

4,460

 

4,249

 

 

(3)

 

(3)

 

(3)

 

 

 

 

 

 

 

 

 

 

 

 

Electricity:

 

 

 

 

 

 

 

 

 

 

 

RCEs at period end

 

75,000

 

98,000

 

43,000

 

12,000

 

11,000

 

Average RCEs during the period

 

87,000

 

68,000

 

20,000

 

12,000

 

12,000

 

MWhrs sold during the period

 

851,000

 

636,000

 

193,000

 

120,000

 

130,000

 

Sales per MWhr sold during the period

 

$

140.07

 

$

130.13

 

$

119.77

 

$

141.10

 

$

97.69

 

Gross profit per MWhr during the period (1)

 

$

26.14

 

$

16.08

 

$

18.54

 

$

32.58

 

$

11.54

 

Cooling degree days

 

1,361

 

1,267

 

 

(2)

 

(2)

 

(2)

 


(1)

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

(2)

Information is not meaningful due to the relative small size of the electricity customer portfolio and related volumes in relation to consolidated operations.

(3)

Data not available.

 

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Table of Contents

 

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

 

Executive Overview

 

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

 

 

 

Fiscal Year Ended June 30,

 

 

 

2009

 

2008

 

2007

 

2006

 

2005

 

 

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

Adjusted EBITDA for prior fiscal year

 

$

44,941

 

$

60,113

 

$

25,729

 

$

36,283

 

$

15,830

 

Increases (decreases) in Adjusted EBITDA resulting from:

 

 

 

 

 

 

 

 

 

 

 

Changes in gross profit, excluding unrealized (gains) losses from risk management activities, due to:

 

 

 

 

 

 

 

 

 

 

 

Natural gas

 

(7,335

)

(9,977

)

66,258

 

(8,568

)

29,004

 

Electricity

 

12,014

 

6,648

 

(331

)

2,420

 

703

 

Higher operating expenses, excluding depreciation, amortization and stock compensation expense

 

(6,096

)

(11,843

)

(31,543

)

(4,406

)

(9,254

)

Adjusted EBITDA for current fiscal year

 

$

43,524

 

$

44,941

 

$

60,113

 

$

25,729

 

$

36,283

 

 

Balance Sheet Overview

 

Guaranteed and Non-Guaranteed Customer Accounts Receivable

 

Accounts receivable, net is summarized in the following table.

 

 

 

Balances at June 30,

 

 

 

2009

 

2008

 

 

 

(in thousands)

 

Billed customer accounts receivable:

 

 

 

 

 

Guaranteed by LDCs

 

$

7,768

 

$

17,085

 

Non-guaranteed by LDCs

 

26,679

 

32,966

 

 

 

34,447

 

50,051

 

Unbilled customer accounts receivable:

 

 

 

 

 

Guaranteed by LDCs

 

5,737

 

9,803

 

Non-guaranteed by LDCs

 

10,547

 

19,905

 

 

 

16,284

 

29,708

 

Total customer accounts receivable

 

50,731

 

79,759

 

Less: Allowance for doubtful accounts

 

(7,344

)

(5,154

)

Customer accounts receivable, net

 

43,387

 

74,605

 

Imbalance settlements and other receivables, net

 

4,211

 

13,068

 

Accounts receivable, net

 

$

47,598

 

$

87,673

 

 

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

 

Our credit risk is limited as certain LDCs guarantee billed and unbilled customer accounts receivable or amounts due for delivered gas and electricity.  In cases where receivables are guaranteed by the LDC, we are exposed only to the credit risk of the LDC, rather than that of our actual customers.  As of June 30, 2009 and 2008, all of our billed and unbilled customer accounts receivable in guaranteed markets were guaranteed by LDCs with investment grade credit ratings.  We periodically review payment history, credit ratings and financial information for LDCs to ensure that we identify and respond to any deteriorating trends.

 

In the market areas where the LDC does not guarantee customer accounts receivable, we maintain an allowance for doubtful accounts that is based upon the credit risk of our customers, historical trends and other information.  Refer to Note 6 of the consolidated financial statements included elsewhere in this Annual Report for additional analysis of our allowance for doubtful accounts.  Bad debt expense associated with non-guaranteed accounts receivable was approximately 3% of related sales of natural gas and electricity for fiscal year 2009 and 1% of related sales of natural gas and electricity for fiscal years 2008 and 2007.

 

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Imbalance settlements represent differences between the natural gas or electricity delivered to LDCs or ISOs for consumption by our customers and actual usage by our customers.  Such imbalances are expected to be settled with cash within the fiscal year following the balance sheet date.  Imbalance settlements will fluctuate from period to period depending on the market price for natural gas and electricity, weather patterns and other factors that affect customer consumption, and the timing of cash remittances from LDCs.  These receivables are due from LDCs with investment grade credit ratings.  Historically, we have collected 100% of these imbalance settlement receivables.  However, as a result of a bankruptcy filing by a retail marketer in Georgia in October 2008, the collection of our imbalance receivable position in Georgia was placed at risk.  A preliminary settlement proposal offered in March 2009 for resolution of the imbalance receivable resulted in us recording an incremental provision for bad debt expense of approximately $0.6 million during fiscal year 2009, which is included in our allowance for doubtful accounts at June 30, 2009.

 

We operate in 39 market areas located in 14 U.S. states and 2 Canadian provinces.  Our 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, we have limited exposure to risk associated with high concentrations of sales volumes with individual customers.  For the fiscal years ended June 30, 2009, 2008 and 2007, our largest customer accounted for approximately 2% of total sales of natural gas.

 

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

 

Natural Gas Inventories

 

Natural gas inventories are summarized in the following table.

 

 

 

Balances at June 30,

 

 

 

2009

 

2008

 

 

 

(in thousands)

 

 

 

 

 

 

 

Storage inventory for delivery to customers

 

$

24,457

 

$

52,807

 

Imbalance settlements in-kind (1)

 

4,958

 

12,195

 

Other

 

 

4

 

Total

 

$

29,415

 

$

65,006

 

 


(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.

 

After reaching record highs during the three months ended June 30, 2008, natural gas market prices dropped sharply during fiscal year 2009, which resulted in a 60% decrease in our weighted-average cost per MMBtu of natural gas included in natural gas storage inventory from June 30, 2008 to June 30, 2009.  The resulting decrease in natural gas inventories was partially offset by a 14% increase in MMBtus of natural gas held in storage over the same period.

 

Unrealized Gains and Losses from Risk Management Activities, Net

 

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.

 

Market Prices for natural gas decreased sharply during fiscal year 2009, which resulted in lower forward commodity contract prices as compared with the average prices on related open hedge contracts for natural gas entered into to match customer contracts for future sales of natural gas.  As a result, total unrealized gains from risk management activities included in current and long-term assets on the consolidated balance sheets decreased to approximately $0.3 million at June 30, 2009 from $49.1 million at June 30, 2008.  Market prices for natural gas decreased sharply during fiscal year 2009, which resulted in lower forward commodity contract prices as compared with the average prices on related open hedge contracts for natural gas entered into to match customer contracts for future sales of natural gas.  Total unrealized losses from risk management activities included in current and long-term liabilities increased to approximately $48.3 million at June 30, 2009 from $5.8

 

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million at June 30, 2008.  Additionally, on the consolidated statements of operations, both realized and unrealized losses from risk management activities increased significantly during fiscal year 2009.

 

Long-Term Debt

 

Exchange of Floating Rate Notes due 2011 for Fixed Rate Notes due 2014, Cash and Class A Common Stock

 

As of June 30, 2009, we had $165.2 million aggregate principal amount of Floating Rate Notes due 2011 outstanding.  On September 22, 2009, we consummated an exchange offer pursuant to which we exchanged $158.8 million aggregate principal amount of 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.  The shares of Class A Common Stock issued to the holders of the Fixed Rate Notes due 2014 represented 62.5% of the total aggregate shares of common stock outstanding after consummation of the Restructuring.  The Fixed Rate Notes due 2014 were issued at a discount, which will be recorded as a reduction from the Fixed Rate Notes due 2014 on our consolidated balance sheet, and which will be amortized over the remaining life of the Fixed Rate Notes due 2014.

 

Holders of $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 on our consolidated balance sheets until acquired or retired by us or until their maturity date in August 2011.

 

Denham Credit Facility

 

Denham is a significant stockholder of the Company.  Denham had extended a $12.0 million line of credit to us, which bore interest at 9% per annum.  The termination date for the Denham Credit Facility was May 19, 2010. At June 30, 2008, there was no balance outstanding under the Denham Credit Facility.  In September 2008, we borrowed the entire $12.0 million available under the Denham Credit Facility, the entire balance of which was outstanding at June 30, 2009.  The entire balance of the Denham Credit Facility, plus accrued interest, was repaid and the Denham Credit Facility was terminated on September 22, 2009.

 

Bridge Financing Loans

 

Pursuant to the Third Amended and Restated Revolving Credit Agreement, dated November 17, 2008 (the “Amended Revolving Credit Agreement”), Charter Mx LLC, Denham and four members of our senior management team agreed to provide bridge financing in an aggregate amount of $10.4 million by becoming lenders in a new bridge loan tranche under the Amended Revolving Credit Agreement (the “Bridge Financing”).  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 Jeffrey A. Mayer, Chief Executive Officer; Steven Murray, Chief Operating Officer; Carole R. Artman-Hodge, Executive Vice President; and Chaitu Parikh, Chief Financial Officer.  An upfront fee of 2% of the respective loan amount was paid to each Bridge Financing lender upon closing.

 

The Bridge Financing loan from Charter Mx LLC was repaid in April 2009.  The remaining Bridge Financing loans were repaid on September 22, 2009.

 

Redeemable Convertible Preferred Stock

 

On June 30, 2004, MXenergy Inc. entered into a purchase agreement (the “Preferred Stock Purchase Agreement”) with Preferred Investors to issue 1,451,310 shares of Preferred Stock at a purchase price of $21.36 per share.  In 2005, as part of a corporate reorganization, MXenergy Inc. merged with and into a subsidiary of Holdings to become a wholly owned subsidiary of Holdings and stockholders of MXenergy Inc. became stockholders of Holdings.  Total related offering expenses of approximately $1.6 million were deducted from the carrying value of the Preferred Stock, which resulted in a net carrying value of approximately $29.4 million at June 30, 2007.

 

On or after the fifth anniversary of the issuance of the Preferred Stock, if the fair market value of our common stock is at a level that would not provide the Preferred Investors with an annual rate of return of at least 25%, compounded annually, for the five-year period ending June 30, 2009, the Preferred Investors had the right to require that we make a redemption election.  If the holders of the Preferred Stock required us to make a redemption election, and if we elected to redeem the Preferred Stock, the redemption amount would have been payable in cash equal to the greater of: (1) the fair market value of the shares of common stock into which the Preferred Stock could have been converted on the date of the redemption election notice; or (2) the original issue price of $21.36 per share, plus any accrual of dividends.  If we elected not to redeem the Preferred Stock, we would have been required to grant the Preferred Investors effective control over Holding’s Board of

 

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Directors.  As of June 30, 2009 and 2008, if the holders of Preferred Stock were to request that we make a redemption election, we did not have the intent or the ability to redeem the Preferred Stock due to limitations included in the agreements that governed the Revolving Credit Facility, the Hedge Facility and the Floating Rate Notes due 2011.  We determined that the Preferred Stock was redeemable at the option of the Preferred Investors and that it is probable that the Preferred Stock became redeemable at June 30, 2009.  Therefore the carrying value of the Preferred Stock was recorded outside of stockholders’ equity on the consolidated balance sheet and was adjusted to its estimated redemption value of $54.6 million as of June 30, 2009.  As of June 30, 2009, the holders of Preferred Stock did not make an election to redeem the Preferred Stock.

 

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 our common stock outstanding after consummation of the Restructuring.  The excess of the redemption value over the aggregate fair value of common stock issued to the holders of Preferred Stock was recorded as an increase to retained earnings on the consolidated balance sheets on the consummation date of the Restructuring.

 

Results of Operations

 

Gross Profit by Business Segment

 

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

 

 

 

 

 

 

 

 

 

2009 versus 2008

 

2008 versus 2007

 

 

 

Fiscal Year Ended June 30,

 

Increase (Decrease)

 

Increase (Decrease)

 

Business Segment

 

2009

 

2008

 

2007

 

Amount

 

%

 

Amount

 

%

 

 

 

($ in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural Gas

 

$

97,968

 

$

105,303

 

$

115,280

 

$

(7,335

)

(7)

 

$

(9,977

)

(9

)

Electricity

 

22,241

 

10,227

 

3,579

 

12,014

 

117

 

6,648

 

186

 

Total gross profit before unrealized losses from risk management activities, net

 

$

120,209

 

$

 115,530

 

$

 118,859

 

$

4,679

 

4

 

$

 (3,329

)

(3

)

 

Fiscal Year Ended June 30, 2009 Versus 2008

 

Natural Gas Gross Profit

 

Realized Losses from Risk Management Activities, Net, That Relate to Natural Gas Inventories Not Yet Sold

 

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

 

During fiscal year 2009, we recorded approximately $13.2 million of realized losses related to settlement of risk management activities associated with natural gas inventories, as compared to realized gains of approximately $4.8 million for fiscal year 2008, resulting in a net $18.0 million ($0.33 per MMBtu of natural gas sold) negative comparative impact on gross profit for the current period.

 

Weighted Average Cost of Gas

 

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

 

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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.

 

Significantly lower market prices for natural gas during fiscal year 2009 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 $0.8 million during fiscal year 2009.  By comparison, higher gross profit of approximately $1.4 million resulted from increased market prices for natural gas during fiscal year 2008.  The comparative net impact was a decrease in natural gas gross profit of approximately $2.2 million ($0.04 per MMBtu sold) for fiscal year 2009.

 

Volume Impact

 

The volume of natural gas MMBtus sold was approximately 1% higher for fiscal year 2009, as compared with the same period in the prior fiscal year.  Lower average RCEs were offset by higher heating degree days during fiscal year 2009.  Higher volumes of natural gas sold resulted in higher natural gas gross profit of approximately $0.7 million for fiscal year 2009, as compared with the prior fiscal year.

 

Fee Income

 

Our gross margin includes fee income charged to customers, primarily in our Georgia natural gas market, for monthly service, late payment and shut-off/reconnect service.  Fee income was $2.0 million higher for fiscal year 2009, as compared with the prior fiscal year, due primarily to increased late payment and service termination fees in these markets.

 

Favorable Price Environment

 

The net impacts described above were partially offset by higher gross profit per MMBtu sold resulting from a favorable pricing environment in many of our markets, particularly for our variable price accounts.

 

Electricity Gross Profit

 

Higher electricity sales and gross profit were primarily driven by higher average electricity RCEs, which increased 28% during fiscal year 2009, as compared with the prior fiscal year, resulting in significantly higher volume of MWhrs sold.  The main driver for higher average RCEs was significant organic customer growth in our Texas, Connecticut and New York market areas, which was largely due to targeted direct sales marketing activities during fiscal year 2008 and the first three months of fiscal year 2009 and a wider range of products offered to customers.  Higher gross profit per MWhr sold also contributed to the overall increase in electricity gross profit.

 

Fiscal Year Ended June 30, 2008 Versus 2007

 

Natural Gas Gross Profit

 

Average natural gas RCEs decreased 1% for fiscal 2008, which was the primary driver for 5% lower volume of natural gas MMBtus sold during fiscal 2008, as compared with the prior fiscal year.  Natural gas gross profit per MMBtu sold decreased 4% for the fiscal year ended June 30, 2008, as compared with the prior fiscal year.  Several factors contributed to the overall decrease in natural gas gross profit and gross profit per MMBtu sold.

 

Volume Impact

 

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

 

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Variable Rate Plan Pricing Impact on Gross Profit

 

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

 

Impact of SESCo Acquisition

 

Our results for fiscal year ended June 30, 2008 include a full twelve months of natural gas gross profit related to the operations of Shell Energy Services Company L.L.C. (“SESCo”), which we acquired in August 2006, while our results for fiscal year 2007 include only eleven months of this activity.

 

Weighted Average Cost of Gas

 

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

 

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

 

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

 

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

 

Realized Losses from Risk Management Activities, Net, That Relate to Natural Gas Inventories Not Yet Sold

 

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

 

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

 

Fee Income

 

Our gross profit includes fee income charged to customers primarily in Georgia, including monthly service fees, late payment fees and shut-off/reconnect service fees.  Fee income was $1.7 million higher for the fiscal year ended June 30, 2008, as compared with the prior fiscal year.  Higher fee income resulted primarily from growth in the number of electricity customers, the GasKey Acquisition in January 2008, and the inclusion of an additional month of SESCo operations in fiscal year 2008 compared to fiscal year 2007.

 

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Electricity Gross Profit

 

Average electricity RCEs grew approximately 240% to approximately 68,000 for fiscal 2008, resulting in significantly higher volume of MWhrs sold.

 

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

 

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

 

In September 2008, Hurricane Ike caused extensive damage to the infrastructure for generating and delivering electricity to residential and commercial end-users along the eastern coast of Texas, which resulted in disruption of electricity service for Houston, Texas and the surrounding area.  Hurricane Ike did not have a material impact on our operations during fiscal year 2009.

 

Operating Expenses

 

Operating expenses are summarized in the following table.

 

 

 

 

 

 

 

 

 

2009 versus 2008

 

2008 versus 2007

 

 

 

Fiscal Year Ended June 30,

 

Increase
(Decrease)

 

Increase
(Decrease)

 

Business Segment

 

2009

 

2008

 

2007

 

Amount

 

%

 

Amount

 

%

 

 

 

($ in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

General and administrative expenses

 

$

59,957

 

$

62,271

 

$

54,516

 

$

(2,314

)

(4

)

$

7,755

 

14

 

Advertising and marketing expenses

 

2,117

 

4,546

 

4,044

 

(2,429

)

(53

)

502

 

12

 

Reserves and discounts

 

15,130

 

7,130

 

4,725

 

8,000

 

112

 

2,405

 

51

 

Depreciation and amortization

 

37,575

 

32,698

 

27,730

 

4,877

 

15

 

4,968

 

18

 

Total operating expenses

 

$

114,779

 

$

 106,645

 

$

91,015

 

$

8,134

 

8

 

$

15,630

 

17

 

 

General and Administrative Expenses

 

General and administrative expenses are summarized in the following table.

 

 

 

 

 

 

 

 

 

2009 versus 2008

 

2008 versus 2007

 

 

 

Fiscal Year Ended June 30,

 

Increase
 (Decrease)

 

Increase
(Decrease)

 

Business Segment

 

2009

 

2008

 

2007

 

Amount

 

%

 

Amount

 

%

 

 

 

($ in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Salaries and employee benefits

 

$

 33,644

 

$

 36,007

 

$

 33,039

 

$

 (2,363

)

(7

)

$

 2,968

 

9

 

Professional fees

 

7,998

 

9,360

 

5,425

 

(1,362

)

(15

)

3,935

 

73

 

Other general and administrative expenses

 

18,315

 

16,904

 

16,052

 

1,411

 

8

 

852

 

5

 

Total general and administrative expenses

 

$

 59,957

 

$

 62,271

 

$

 54,516

 

$

 (2,314

)

(4

)

$

 7,755

 

14

 

 

Fiscal Year Ended June 30, 2009 Versus 2008

 

Throughout fiscal year 2008, we incurred significant incremental general and administrative expenses related to initiatives to enhance our corporate finance, billing, accounting operations, customer service, information technology, marketing and supply functions in support of business growth.  In addition, we increased our staff count and incurred other incremental costs to enhance our overall internal control environment, including our information technology and financial reporting controls, and to develop a formal internal audit function.  A portion of these incremental contracted services and other

 

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incremental costs in fiscal year 2008 have not recurred during fiscal year 2009, resulting in generally lower general and administrative expenses.

 

In March 2008, the Compensation Committee of our Board of Directors approved the issuance of 19,000 total shares of common stock to two of our senior executives.  Total compensation expense related to issuance of these shares was approximately $1.7 million, which included the fair value of the common stock issued and additional compensation to offset the taxable nature of the shares to the employees.  Excluding the impact of the compensation expense from issuance of these shares in fiscal year 2008, salaries and employee benefits decreased $0.7 million (2%) during fiscal year 2009, as compared with the prior fiscal year.  Salaries and employee benefits include the cost of contracted services to supplement our employees in certain departments.  Lower salaries and related expenses during fiscal year 2009 are primarily due to lower contracted services costs.

 

Higher other general and administrative expenses during fiscal year 2009 were primarily due to generally higher customer care and billing related expenses.

 

Fiscal Year Ended June 30, 2008 Versus 2007

 

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

 

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

 

During fiscal year 2008, we incurred an additional month of expenses, as compared to the prior fiscal year, related to the operations of SESCo, which were acquired effective August 1, 2006.

 

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

 

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

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

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

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

 

Advertising and Marketing Expenses

 

Fiscal Year Ended June 30, 2009 Versus 2008

 

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 intentionally curtailed our level of sales and marketing activity, resulting in significantly lower advertising and marketing expenses during fiscal year 2009, as compared with prior fiscal year.

 

Fiscal Year Ended June 30, 2008 Versus 2007

 

During the three months ended September 30, 2007, we incurred significant expenses related to a multi-media campaign

 

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designed to support our direct sales activities in the Georgia market.  Multi-media marketing expenditures slowed significantly during the nine months subsequent to September 30, 2007 after the Georgia campaign was completed.

 

Marketing expenses were lower for the final nine months of fiscal 2008 as a result of higher deferrals of customer acquisition costs, as compared with the prior fiscal year.  During fiscal 2008, we shifted our marketing focus and resources towards direct sales and marketing activities.  Much of the cost associated with these marketing channels are deferred as customer acquisition costs on our consolidated balance sheet and amortized over a three-year estimated benefit period, which resulted in lower marketing expenses and partially offset higher multi-media advertising expenses during the first three months of fiscal year 2008.

 

Reserves and Discounts

 

Reserves and discounts are summarized in the following table.

 

 

 

 

 

 

 

 

 

2009 versus 2008

 

2008 versus 2007

 

 

 

Fiscal Year Ended June 30,

 

Increase
 (Decrease)

 

Increase
(Decrease)

 

Business Segment

 

2009

 

2008

 

2007

 

Amount

 

%

 

Amount

 

%

 

 

 

($ in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Provision for doubtful accounts

 

$

12,009

 

$

5,050

 

$

3,018

 

$

6,959

 

138

 

$

2,032

 

67

 

Contractual discounts for LDC guarantees of customer accounts receivable (1)

 

3,121

 

2,080

 

1,707

 

1,041

 

50

 

373

 

22

 

Total reserves and discounts

 

$

15,130

 

$

7,130

 

$

4,725

 

$

8,000

 

112

 

$

2,405

 

51

 

 

Fiscal Year Ended June 30, 2009 Versus 2008

 

Accounts receivable includes cash imbalance settlements that represent the value of excess natural gas delivered to LDCs for consumption by our customers and actual customer usage.   Historically, we have collected 100% of these imbalance settlement receivables.  However, as a result of a bankruptcy filing by a retail marketer in Georgia in October 2008, the collection of our imbalance receivable position in Georgia was placed at risk.  A preliminary settlement proposal offered in March 2009 for resolution of the imbalance receivable resulted in us recording an incremental provision for bad debt expense of approximately $0.6 million during fiscal year 2009.

 

Excluding the impact of the Georgia imbalance settlement, the higher provision for doubtful accounts for fiscal year 2009 was primarily due to:

 

·                  higher revenue during fiscal year 2009 in our largest non-guaranteed natural gas market in Georgia and in our non-guaranteed electricity market in Texas.  Total sales of natural gas and electricity for these markets increased a combined 7% during fiscal year 2009; and

·                  general deterioration in the aging of customer accounts receivable and higher charge off experience in certain markets, including Georgia and Texas.  The deterioration in Georgia was primarily related to collections activity related to customers acquired from Catalyst Natural Gas, LLC in October 2008.

 

We continue to monitor economic conditions and collections experience in our markets in order to assess appropriate levels of our allowance for doubtful accounts.

 

Higher contractual discounts for LDC guarantees of customer accounts receivable during fiscal year 2009, as compared with the prior fiscal year, are due to generally higher sales of natural gas and electricity within our LDC guaranteed markets and to a higher weighted-average contractual discount rate.  Total revenues within these markets increased approximately 9% during fiscal year 2009, as compared to the prior fiscal year, primarily due to overall organic growth within these markets.  The weighted-average contractual discount rate charged by LDCs also increased by approximately 37%, primarily due to changes in customer market concentrations and increases in the discount rates required by LDCs in certain markets.

 

Fiscal Year Ended June 30, 2008 Versus 2007

 

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

 

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each of the fiscal years ended June 30, 2008 and 2007.

 

Depreciation and Amortization

 

Depreciation and amortization expenses are summarized in the following table.

 

 

 

 

 

 

 

 

 

2009 versus 2008

 

2008 versus 2007

 

 

 

Fiscal Year Ended June 30,

 

Increase
(Decrease)

 

Increase
(Decrease)

 

Business Segment

 

2009

 

2008

 

2007

 

Amount

 

%

 

Amount

 

%

 

 

 

($ in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Depreciation of fixed assets

 

$

7,787

 

$

9,274

 

$

8,179

 

$

(1487

)

(16

)

$

1,095

 

13

 

Amortization of customer acquisition costs

 

29,777

 

23,414

 

19,540

 

6,363

 

27

 

3,874

 

20

 

Other amortization expense

 

11

 

10

 

11

 

1

 

10

 

(1

)

(9

)

Total depreciation and amortization

 

$

37,575

 

$

32,698

 

$

27,730

 

$

4,877

 

15

 

$

4,968

 

18

 

 

Fiscal Year Ended June 30, 2009 Versus 2008

 

During fiscal year 2008, we shifted our marketing focus and resources towards direct sales and marketing activities.  Much of the cost associated with these direct marketing channels during fiscal years 2009 and 2008 were deferred as customer acquisition costs on our consolidated balance sheet and are being amortized over a three-year estimated benefit period.  Higher amortization expense for fiscal year 2009 was primarily due to these higher deferrals of direct marketing costs.

 

Fiscal Year Ended June 30, 2008 Versus 2007

 

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

 

Interest Expense, net

 

Interest expense is summarized in the following table.

 

 

 

 

 

 

 

 

 

2009 versus 2008

 

2008 versus 2007

 

 

 

Fiscal Year Ended June 30,

 

Increase
 (Decrease)

 

Increase
(Decrease)

 

Business Segment

 

2009

 

2008

 

2007

 

Amount

 

%

 

Amount

 

%

 

 

 

($ in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest accrued on Floating Rate Notes due 2011

 

$

16,834

 

$

20,983

 

$

21,222

 

$

(4,149

)

(20

)

$

(239

)

(1

)

Interest rate swaps activity:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Change in fair market value (1)

 

3,693

 

3,291

 

856

 

402

 

12

 

2,435

 

284

 

Interest accrued

 

1,306

 

1,674

 

287

 

(368

)

(22

)

1,387

 

483

 

Interest and fees on Revolving Credit Facility (2)

 

7,809

 

3,021

 

3,052

 

4,788

 

158

 

(31

)

(1

)

Interest and fees on Hedge Facility (3)

 

2,207

 

2,421

 

3,692

 

(214

)

(9

 

(1,271

)

(34

)

Interest accrued on Denham Credit Facility

 

813

 

528

 

565

 

285

 

54

 

(37

)

(7

)

Other, primarily amortization of deferred financing costs

 

13,073

 

5,993

 

7,642

 

7,080

 

118

 

(1,649

)

(22

)

Total interest expense

 

45,735

 

37,911

 

37,316

 

7,824

 

21

 

595

 

2

 

Less: interest income

 

(430

)

(3,806

)

(4,258

)

3,376

 

(89

)

452

 

(11

)

Interest expense, net

 

$

45,305

 

$

34,105

 

$

33,058

 

$

11,200

 

33

 

$

1,047

 

3

 

 


(1)

We utilize interest rate swap agreements to manage exposure to interest rate fluctuations on the Floating Rate Notes due 2011. Mark-to-market adjustments and interest expense associated with these swap arrangements are recorded as adjustments to interest expense, net.

(2)

Includes interest expense associated with cash draws and Bridge Financing loans under the Revolving Credit Facility. In addition, we utilize the Revolving Credit Facility to post letters of credit related to activity under our Hedge Facility, commodity supplier agreements, transportation and storage agreements. Fees and interest expense associated with letters of credit are also recorded as interest expense.

(3)

Represents fees charged by the hedge provider related to forward-hedged commodity volumes under the Hedge Facility.

 

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Fiscal Year Ended June 30, 2009 Versus 2008

 

Lower interest accrued on the Floating Rate Notes due 2011 was primarily due to a lower average interest rate, which decreased to 10.02% for fiscal year 2009 from 11.95% for fiscal year 2008.  The average aggregate balance of Floating Rate Notes due 2011 outstanding also decreased to $165.2 million for fiscal year 2009, as compared to $172.4 million for fiscal year 2008, as a result of our purchases of Floating Rate Notes due 2011 during fiscal year 2008.

 

Higher interest and fees related to the Revolving Credit Facility are due to the following activity:

 

·                  higher interest and fees associated with outstanding obligations under the Revolving Credit Facility, partially due to an increase of approximately 20% in the average balance of cash advances and letters of credit outstanding, and partially due to generally higher letter of credit fees resulting from amendments to the agreement that governs the Revolving Credit Facility during fiscal year 2009; and

·                  new Bridge Financing loans from certain shareholders and members of senior management, as required by amendments to the agreement that governs the Revolving Credit Facility, which resulted in approximately $2.7 million of incremental interest expense for fiscal year 2009.

 

During fiscal year 2009, we negotiated several amendments to our Hedge Facility and our Revolving Credit Facility.  Approximately $8.7 million of fees associated with these amendments were deferred during fiscal year 2009 for amortization over the remaining amended term of the facilities.  Incremental interest expense of $7.5 million for fiscal year 2009 was a direct result of amortization of these deferred costs.

 

Lower interest income was a direct result of lower average cash and cash equivalents and restricted cash balances during fiscal year 2009 as well as a lower average interest rate earned during the year, as compared to the same period in fiscal year 2008.

 

Fiscal Year Ended June 30, 2008 Versus 2007

 

Interest expense associated with the Floating Rate Notes due 2011 increased $3.6 million in fiscal 2008.  The Floating Rate Notes due 2011 were issued in connection with the SESCo Acquisition, which was completed in August 2006.  We incurred a full twelve months of interest expense related to the Floating Rate Notes due 2011 during the fiscal year ended June 30, 2008, as compared with eleven months of interest expense incurred during fiscal 2007, which resulted in approximately $1.9 million of additional interest expense for fiscal year 2008.

 

We utilize interest rate swap agreements to manage exposure to interest rate fluctuations on the Floating Rate Notes due 2011.  Mark-to-market adjustments and interest expense associated with these swap arrangements are recorded as adjustments to interest expense, net.  Changes in the market value and higher interest expense related to interest rate swaps resulted in an overall increase of $3.8 million to interest expense, net for the fiscal year ended June 30, 2008, as compared with the prior fiscal year.

 

Excluding the impacts noted above of the mark-to-market adjustments and interest on the interest rate swaps and the additional month of interest during the fiscal year ended June 30, 2008, interest expense related to the Floating Rate Notes due 2011 decreased approximately $1.7 million during the fiscal year ended June 30, 2008, as compared with the prior fiscal year.  The weighted-average interest rate on the Floating Rate Notes due 2011 decreased to 11.95% for fiscal 2008 from 12.97% for the prior fiscal year.  Lower average debt balances resulting from our purchases of Floating Rate Notes due 2011 during fiscal 2008 and 2007 also resulted in generally lower interest expense on the Floating Rate Notes due 2011 for fiscal 2008.

 

During August 2006, we utilized a bridge loan from two investment banks to finance the SESCo Acquisition.  The bridge loan was repaid with proceeds from the sale of $190.0 million aggregate principal amount of the Floating Rate Notes due 2011.  Fees and interest of $0.8 million associated with the bridge loan were charged to interest expense during the fiscal year ended June 30, 2007.  There was no comparable expense recorded during the fiscal year ended June 30, 2008.

 

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

 

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Income Tax (Expense) Benefit

 

Fiscal Year Ended June 30, 2009 Versus 2008

 

Our effective tax rate for fiscal year 2009 was reduced to a benefit of 21.4% for fiscal year 2009 from a charge of 40.9% for fiscal year 2008, primarily due to the impact of a valuation allowance recorded at June 30, 2009 against deferred tax assets, as described below, and changes in the mix and amounts of permanent differences and to a lower state statutory tax rate as a result of income apportionment for the states in which we do business.

 

The significant components of the Company’s deferred tax assets and liabilities are summarized in the following table.

 

 

 

Balance at June 30,

 

 

 

2009

 

2008

 

 

 

(in thousands)

 

Deferred tax assets:

 

 

 

 

 

Depreciation and amortization

 

$

18,982

 

$

12,877

 

Net unrealized losses from risk management activities

 

18,693

 

 

Allowance for doubtful accounts

 

2,860

 

2,035

 

Tax loss carryforwards

 

2,724

 

 

Accrued bonuses

 

1,707

 

1,090

 

Stock compensation expense

 

1,642

 

1,664

 

Other reserves

 

165

 

122

 

Valuation allowance

 

(22,664

)

 

Total deferred tax assets

 

24,109

 

17,788

 

Deferred tax liabilities:

 

 

 

 

 

Net unrealized gains from risk management activities

 

 

(17,085

)

Total deferred tax liabilities

 

 

(17,085

)

Net deferred tax asset

 

$

24,109

 

$

703

 

 

 

 

 

 

 

Balance sheet classification:

 

 

 

 

 

Current deferred tax asset

 

$

9,020

 

$

 

Long-term deferred tax asset

 

15,089

 

10,503

 

Current deferred tax liability

 

 

(9,800

)

Net deferred tax asset

 

$

24,109

 

$

703

 

 

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.

 

We have deferred tax assets related to unrealized losses from risk management activities.  We anticipate that these deferred tax assets will be realized in future periods when sales of fixed price commodities, to which the unrealized losses from risk management activities relate, occur.  Therefore, we did not establish a valuation allowance for these deferred tax assets.

 

For the remaining deferred tax assets reflected in the table above, we determined based on available evidence including historical financial results for the last 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 of approximately $22.0 million and $0.7 million related to our U.S. and Canadian operations, respectively, as a reduction of the tax benefit recorded for fiscal year 2009.

 

Fiscal Year Ended June 30, 2008 Versus 2007

 

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

 

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

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

 

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 ongoing debt service obligations.  Because we sell

 

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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 the following material direct impacts on our liquidity position:

 

·                  The maturity dates of the Revolving Credit Facility and Hedge Facility were extended to September 2009.

·                  The maximum amount that could be borrowed under the Revolving Credit Facility was reduced from $280.0 million at June 30, 2008 to $115.0 million at June 30, 2009, and $94.0 million effective July 31, 2009.

·                  We were required to actively seek a new facility to replace the Revolving Credit Facility and Hedge Facility.

·                  During fiscal year 2009, we paid approximately $8.7 million of fees related to all amendments and extensions, which were deferred on the consolidated balance sheet and are being amortized as an increase to interest expense over the remaining terms of the Revolving Credit Facility and Hedge Facility.  During fiscal year 2009, we recorded approximately $7.5 million of incremental interest expense resulting from amortization of these deferred costs.

 

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 out 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.  The Commodity Supply Facility provides us with a stable source of liquidity for a minimum of three years with an investment grade counterparty.  Significant terms of the Commodity Supply Facility are described below.

 

Cash Flow

 

During the fiscal year ended June 30, 2009, our cash and cash equivalents decreased $48.7 million to a balance of $23.3 million at the end of the period.  Approximately $48.1 million of cash was used for operating activities during fiscal year 2009, which reflects a $39.5 million change from the $8.6 million used in operations for fiscal year 2008.  As a result of various amendments to the agreement that governs the Revolving Credit Facility during fiscal year 2009, we were required to transfer $75.0 million of cash to a restricted account to maintain as collateral for obligations under the Revolving Credit Facility, which resulted in a corresponding reduction in cash and cash equivalents.  This transfer to restricted cash was partially offset by a $17.6 million increase in cash from operations and by a $9.0 increase in operating cash from changes in customer accounts receivable, natural gas inventories and other working capital activity.

 

During fiscal year 2009, cash was also used in or provided by the following material investing and financing activities:

 

·                  $15.3 million was used for investment in customer acquisition costs throughout fiscal 2009;

·                  $12.0 million was provided by borrowings under the Denham Credit Facility in September 2008;

·                  $10.4 million was provided by Bridge Financing under the Revolving Credit Facility in November 2008, of which $5.0 million was repaid in April 2009.

 

The Restructuring consummated on September 22, 2009 resulted in the following material sources and uses of cash and cash equivalents during the first quarter of fiscal year 2010:

 

·                  $75.0 million of restricted cash was released by the administrative agent under the Revolving Credit Facility and returned to cash and cash equivalents;

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

·                  $18.5 million was transferred from cash and cash equivalents to restricted cash accounts established as collateral for actual and potential mark-to-market liabilities associated with commodity and interest rate economic hedging activities;

·                  $12.5 million of principal and accrued interest was paid to Denham to repay all obligations under the Denham Credit Facility;

·                  $9.0 million was transferred from cash and cash equivalents to a restricted cash account established as escrow for future interest payments related to the Fixed Rate Notes due 2014;

·                  $6.6 million of principal and interest was paid to the Bridge Financing lenders to repay all obligations under the Bridge Financing Loans;

·                  Approximately $5.0 million was paid to various parties for fees directly related to various transactions consummated under the Restructuring;

·                  $67.8 million aggregate principal amount of Fixed Rate Notes due 2014 were issued to bondholders in partial exchange for their Floating Rate Notes due 2011; and

·                  54,305,112 shares of newly authorized common stock were issued to various parties.

 

Revolving Credit Facility

 

As of June 30, 2009, and through September 21, 2009, we utilized our Revolving Credit Facility primarily to post letters of credit required to effectively operate within the markets that we serve.  At June 30, 2009, the total availability under the

 

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Revolving Credit Facility was $147.8 million, of which the maximum we could utilize was $115.0 million as a result of amendments to the Revolving Credit Facility during fiscal year 2009.  As of June 30, 2009, $96.3 million of availability was utilized in the form of outstanding letters of credit.  During the fiscal year ended June 30, 2009, we drew $30.0 million of cash advances under the Revolving Credit Facility, all of which was repaid prior to June 30, 2009.  Total interest expense associated with these cash borrowings was less than $0.1 million for the fiscal year ended June 30, 2009.  Other than the Bridge Financing loans described below, there were no cash borrowings outstanding under the Revolving Credit Facility at June 30, 2009 or June 30, 2008.

 

The Revolving Credit Facility was replaced by the Commodity Supply Facility effective September 22, 2009.

 

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 our 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 the 2009 Amendments, we were required to actively seek a liquidity event, which may have included one or more of the following: (1) the repayment in full of all of the obligations under the Revolving Credit Facility and the termination of the revolving commitments thereunder; or (2) an equity contribution to us in an amount no less than $75.0 million, which shall be made on terms and conditions satisfactory to the administrative agent and the majority lenders at their sole discretion (a “Liquidity Event”). Various milestone events and dates were established by the 2009 Amendments and were eventually met by the Company, all leading to development and consummation of the Restructuring on September 22, 2009.

 

Other material impacts of the 2009 Amendments are summarized as follows:

 

·                  The maturity date of the Revolving Credit Facility was extended to September 21, 2009 from December 19, 2008.

·                  The maximum amount that we could borrow under the Revolving Credit Facility was incrementally reduced from $280.0 million at June 30, 2008 to $115.0 million at June 30, 2009 and to $94 million from July 31, 2009 through the termination date.

·                  In November 2008, we were required to obtain $10.4 million of additional debt financing from Denham Commodity Partners Fund LP (“Denham”) and Charter Mx LLC, both significant stockholders of the Company, and four members of our senior management team.

·                  We were required to borrow the $12.0 million available balance under the Denham Credit Facility by November 7, 2008.

·                  The volume of natural gas that could be maintained in inventory was limited to maximum amounts ranging from a maximum of: (a) 4.2 million MMBtus on any date from May 15, 2009 through May 31, 2009; (b) 5.1 million MMBtus on any date during the month of June 2009; (c) 5.6 million MMBtus on any date during the month of July 2009; and 6.1 million MMBtus effective for the period July 31, 2009 through the termination date.

·                  Our marketing expenses were limited to: $0.2 million per week effective May 15, 2009.

·                  We were required to maintain a minimum cash balance with the administrative agent as security for all obligations of the Revolving Credit Facility, which increased from $60.0 million effective May 15, 2009, to $65 million effective May 29, 2009, and to $75.0 million effective June 15, 2009 until termination of the Revolving Credit Facility and cancellation of all letters of credit issued thereunder.

·                  Effective November 17, 2008, the aggregate outstanding principal amount of cash advances under the Revolving Credit Facility was limited to $20.0 million.  Effective March 11, 2009, our ability to obtain cash advances under the Revolving Credit Facility was eliminated.

·                  Effective September 30, 2008, any plan of the Company to acquire customer portfolios or operations of other companies required the explicit approval by lenders holding a majority of the commitments under the Revolving Credit Facility.  Effective May 15, 2009, any acquisitions of customer portfolios or operations of other companies were strictly prohibited.

·                  We were temporarily allowed to exceed the maximum amount that can be borrowed under the Revolving Credit Facility by various amounts that decreased incrementally from $35.0 million effective in November 2008 to $0 effective in March 2009.

·                  From November 1, 2008 through November 17, 2008, we were temporarily allowed to request issuance of letters of credit of up to $25,360,000 without deducting such letters of credit from the available borrowing base.

·                  Amounts and terms of letters of credit that we could request to be issued were progressively limited.

·                  Effective May 15, 2009, the aggregate amount of letters of credit that could be issued with an expiration date beyond October 31, 2009 was limited to $40.0 million.

 

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·                  The margins added to base rate loans, various letter of credit fees and other facility fees were increased.

·                  Financial covenants related to consolidated tangible net worth, consolidated working capital, interest coverage and allowed negative consolidated earnings were each amended.

·                  We were required to have at least $10.0 million in available borrowing base on and after April 30, 2009.

·                  We were required to have at least $40.0 million in cash and cash equivalents at all times on and after April 30, 2009, excluding any such cash and cash equivalents acquired from the proceeds of advances under the Revolving Credit Facility.

·                  We paid approximately $8.7 million of amendment fees, legal fees and consulting fees and other costs directly related to various amendments of the Revolving Credit Facility and the Hedge Facility during the fiscal year ended June 30, 2009, which were deferred on the consolidated balance sheet and amortized over the remaining terms of the facilities.  Incremental interest expense associated with amortization of these deferred costs was approximately $7.5 million during fiscal year 2009.

 

On November 17, 2008, Charter Mx LLC, Denham and four members our senior management team agreed to provide Bridge Financing in an aggregate amount of $10.4 million by becoming lenders in a new bridge loan tranche under the Revolving Credit Facility.  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 Jeffrey A. Mayer, Chief Executive Officer; Steven Murray, Chief Operating Officer; Carole R. Artman-Hodge, Executive Vice President; and Chaitu Parikh, Chief Financial Officer.  An upfront fee of 2% of the respective loan amount was paid to each Bridge Financing lender upon closing.

 

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, on September 22, 2009.  During fiscal year 2009, we recorded approximately $2.7 million of interest expense associated with the Bridge Financing loans.

 

The agreement that governed the Revolving Credit Agreement contained customary covenants that restricted certain of our activities including, among others, making capital expenditures, disposal of property and equipment, additional indebtedness, issuance of capital stock and payment of dividends.  We were in compliance with all such covenants as of June 30, 2009, including the milestone events relating to replacement of the Revolving Credit Facility and Hedge Facility.

 

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.  As of June 30, 2009, all of our natural gas hedge positions under the Hedge Facility were with a counterparty that had an investment grade credit rating.

 

The Hedge Facility was replaced by the Commodity Supply Facility effective September 22, 2009.

 

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 and dates associated with a Liquidity Event.

 

The Hedge Facility was secured by a first lien on customer contracts and a second lien on substantially all other assets.  As of June 30, 2008, we were required to post a $25.0 million letter of credit as collateral for any potential negative mark-to-market changes in the value of our forward hedge position.  Effective with a July 2008 amendment to the Master Transaction Agreement, we were required to increase the collateral required to be posted as margin to $35.0 million in the event that the negative mark-to-market value of our forward hedge position exceeds $25.0 million.  We have the flexibility to post either cash collateral or issue a letter of credit as collateral for the Hedge Facility.  As of June 30, 2009, we had increased the letter of credit posted as collateral to $35.0 million because our mark-to-market exposure under the Hedge Facility exceeded $25.0 million.

 

Other material amendments to the Hedge Facility during fiscal year 2009 include:

 

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·                  The maturity date of the Hedge Facility was extended to September 21, 2009 from July 31, 2008.

·                  Effective May 29, 2009, counterparties for any new natural gas transactions required the approval of the hedge provider at its sole discretion.

·                  Effective May 29, 2009, the limitation on the maximum total outstanding hedging positions was reduced from a maximum of 25.0 million MMBtus in the original agreement that governs the Hedge Facility to 12.0 million MMBtus effective May 29, 2009, to 11.0 million MMBtus effective July 31, 2009, and to 10.0 million MMBtus effective August 31, 2009.

 

Floating Rate Notes due 2011

 

On August 4, 2006, we issued $190.0 million aggregate principal amount of Floating Rate Notes due 2011, which mature on August 1, 2011 and bear interest at a rate equal to LIBOR plus 7.5% per annum.  The interest rate on the Floating Rate Notes due 2011 was 9.13% and 10.69% at June 30, 2009 and 2008, respectively.  The weighted-average interest rate was 10.02% and 11.95% for the fiscal years ended June 30, 2009 and 2008, respectively.  We have entered into interest rate swap agreements to hedge the floating rate interest expense on the Floating Rate Notes due 2011.  Refer to “Item 3. Quantitative and Qualitative Disclosures About Market Risk” below for additional information regarding the interest rate swaps.

 

During fiscal year 2008 and 2007, we purchased $12.8 million and $12.0 million, respectively, of aggregate principal amount of Floating Rate Notes due 2011, plus accrued interest, from noteholders for amounts less than face value.  These transactions resulted in gains on early extinguishment of debt of approximately $0.8 and $1.0 million during fiscal years 2008 and 2007, respectively, which were recorded as reductions of interest expense.  We also recorded as additional interest expense of $0.5 million and $0.6 million during fiscal years 2008 and 2007, respectively, representing a pro rata portion of original issue discount and debt issuance costs that were deferred at the issuance date of the Floating Rate Notes due 2011.

 

As of June 30, 2009, we had $165.2 million aggregate principal amount of Floating Rate Notes due 2011 outstanding.  On September 22, 2009, we consummated an exchange offer of $158.8 million aggregate principal amount  of Floating Rate Notes due 2011 for $26.7 million of cash, $67.8 million aggregate principal amount of Fixed Rate Notes due 2014 and approximately 33,940,683 shares of newly authorized Class A Common Stock.  The shares of Class A Common Stock issued to the holders of the Fixed Rate Notes due 2014 represented 62.5% of the aggregate shares of common stock outstanding after consummation of the Restructuring.

 

Holders of $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 on our consolidated balance sheets until their maturity date in August 2011 unless acquired or retired by us at an earlier date.  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.

 

Fixed Rate Notes due 2014

 

Pursuant to the Restructuring consummated on September 22, 2009, the Company 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, to the holders of record of the Fixed Rate Notes due 2014 on the immediately preceding January 15 and July 15.  The Fixed Rate Notes due 2014 will mature on August 1, 2014.  The Fixed Rate Notes due 2014 were issued at a discount, which will be recorded as a reduction from the 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.

 

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 value of the assets securing the Fixed Rate Notes due 2014 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 interest in a cash escrow account maintained as security for future payments to holders of the Fixed Rate Notes due 2014 (the “Notes Escrow Account”) and by a second-priority security interest in substantially all other existing and future assets of the Company.  The Notes Escrow Account was funded with

 

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approximately $9.0 million, which represents the approximate interest payable on the Fixed Rate Notes due 2014 for a twelve-month period.

 

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 as required by the Amended Revolving Credit Agreement, the entire amount of which was still outstanding at June 30, 2009.  The outstanding balance outstanding under the Denham Credit Facility was repaid; including accrued and unpaid interest, and the Denham Credit Facility was terminated on September 22, 2009.

 

Commodity Supply Facility

 

As a result of 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 MXenergy Inc. and MXenergy Electric Inc. and all obligations are guaranteed by Holdings and its other domestic subsidiaries.  Obligations under the Commodity Supply Facility are secured by a first priority lien on substantially all of Holdings’ and its domestic subsidiaries’ existing and future assets, other than an interest reserve account held on behalf of the holders of the Fixed Rate Notes due 2014.   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 at its sole discretion, provided that such 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, payment extension financing and/or storage financing as needed, and associated hedging transactions in order to maintain the Company’s required matched trading book.  In addition, the Commodity Supply Facility will provide 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 the Company’s behalf to satisfy the requirements of regional transmission operators for capacity rights and ancillary services.

 

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.  RBS Sempra would not be obligated to enter into a transaction with any third party unless RBS Sempra is satisfied with such transaction 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, the Company will be charged an adder for such third-party purchases.

 

The Commodity Supply Facility also provides for certain volumetric fees for all natural gas and electricity purchases, as well as minimum purchase requirements for both natural gas and electricity over the initial three-year term and over the optional one-year extension term.

 

Under the hedging terms of the Commodity Supply Facility, the aggregate notional exposure amount of fixed price hedges allowed to be entered into by the Company will be limited to $260.0 million, without adjustment for mark-to-market movements thereafter.  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 volumetric tenor not to exceed 14 months in duration.  With regards to the Company’s fixed price customer mix, the Company may not, during any 12 month period, enter into any new fixed price contracts with respect to the gas business where the residential customer equivalents of such contracts are greater than 75% of all residential customer equivalents of all new contracts entered into during such period and/or maintain a customer portfolio with more than 325,000 residential customer equivalents operating under fixed price contracts.

 

The maximum amount of cash borrowings permitted under the storage and/or payment extension financing provisions of the Commodity Supply Facility will be $45.0 million.  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 the greater of 4% or Libor plus 3%, provided however, that, if on any date of determination, no termination event has occurred with respect to Holdings and its affiliates and the cash held in certain collateral accounts exceeds all outstanding settlement payments under the Commodity Supply Facility, interest will accrue at a reduced rate of 1.0% on that portion of the credit support amount that is in excess of $27.0 million.

 

With regards to the aggregate exposure outstanding under the Commodity Supply Facility, the Company must maintain a ratio of eligible current working capital assets to outstanding supply and financing exposure (excluding any exposure related to hedging activities) greater than 1.25:1.0 during the months of October through March, and greater then 1.4:1.0 during the months of April through September; (the “Collateral Coverage Ratio”).  In addition, the Company must maintain a consolidated tangible net worth, as defined in the agreement that governs the Commodity Supply Facility, of at least $60.0 million.

 

On September 22, 2009, certain of the Company’s natural gas hedging transactions under the Hedge Facility were novated or otherwise transferred to RBS Sempra.  In addition, the Commodity Supply Facility requires the Company to novate or unwind certain existing electricity and interest rate swaps subsequent to closing, with RBS Sempra providing any necessary credit support to liquidate those positions.

 

In connection with the Commodity Supply Facility, RBS Sempra was issued 4,002,290 shares of Holdings’ Class B Common Stock, which was equal to 7.37% of the outstanding common stock as of September 22, 2009.

 

The agreements that govern the Commodity Supply Facility 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 Commodity Supply Facility also contains customary events of default, including:

 

·                  payment defaults;

·                  breaches of representations and warranties;

·                  covenant defaults;

·                  cross defaults to certain other indebtedness 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 New Facilities 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

·                  a change of control.

 

Agency Credit Ratings

 

Our credit ratings as of June 30, 2009 are summarized in the following table.

 

 

 

Standard
& Poor’s

 

Moody’s
Investors
Service

 

 

 

 

 

 

 

Corporate rating

 

CC

 

Caa3

 

Floating Rate Notes due 2011 rating

 

C

 

Ca

 

Ratings outlook

 

Negative

 

Review

 

 

In November 2008, Standard & Poor’s lowered our corporate credit rating to CCC+ from B and our Floating Rate Notes due 2011 rating from CCC+ to CCC-.  Also in November 2008, Moody’s lowered our corporate credit rating to Caa3 from B3 and our Floating Rate Notes due 2011 rating to Ca from Caa1.  These actions were due to the expectation that our liquidity position would deteriorate due to a decline in the available borrowing base under our Revolving Credit Facility.

 

In December 2008, Standard & Poor’s further lowered our corporate rating to CC and our Floating Rate Notes due 2011 rating to C following our announcement of a tender offer to purchase our Floating Rate Notes due 2011.  The tender offer

 

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also prompted a review by Moody’s, which did not result in any changes in our corporate or Floating Rate Notes due 2011 ratings with them.

 

In July 2009, in response to our announcement of a bond exchange tender offer in June 2009, Moody’s lowered the rating on our Floating Rate Notes due 2011 to Caa3 from Ca and our ratings outlook to negative.  In August 2009, also in response to our announcement of a bond exchange tender offer, Standard & Poor’s lowered our corporate rating to SD (selected default) and our Floating Rate Notes due 2011 rating to D (default) and announced that it is withdrawing its rating of us.  In September 2009, Moody’s assigned a probability of default of Ca/LD (limited default) to us and announced that it is withdrawing its ratings of us.

 

Since the agreements that govern the Fixed Rate Notes due 2014, Floating Rate Notes due 2011 and Commodity Supply Facility do not require us to be rated by credit rating agencies, we have terminated our arrangements with Moody’s and Standard & Poor’s effective in August 2009.

 

Summary of Contractual Obligations

 

The following table discloses aggregate information about our contractual obligations and commercial commitments as of June 30, 2009:

 

 

 

Contractual Obligation Amounts Maturing In

 

 

 

Less Than

 

 

 

 

 

 

 

 

 

 

 

1 Year

 

1-3 Years

 

4-5 Years

 

Thereafter

 

Total

 

 

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

Floating Rate Notes due 2011 (1)

 

$

26,700

 

$

6,413

 

$

 

$

 

$

33,113

 

Denham Credit Facility (2)

 

12,000

 

 

 

 

12,000

 

Bridge Financing loans (2)

 

5,400

 

 

 

 

5,400

 

Hedge Facility (3)

 

217

 

 

 

 

217

 

Operating leases (4)

 

760

 

440

 

468

 

844

 

2,512

 

Capacity charge commitments (5)

 

6,547

 

100

 

 

 

6,647

 

Natural gas physical purchase commitments (6)

 

14,838

 

90

 

 

 

14,928

 

Electricity physical purchase commitments (6)

 

10,402

 

4,103

 

 

 

14,505

 

Total

 

$

76,864

 

$

11,146

 

$

468

 

$

844

 

$

89,322

 

 


(1)

$158.8 million aggregate principal amount of Floating Rate Notes due 2011 were exchanged for cash, common stock and the Fixed Rate Notes due 2014 under the Restructuring consummated on September 22, 2009. The cash paid in the exchange is reflected as maturing in less than 1 year. $6.4 million aggregate principal amount of Floating Rate Notes due 2011 not exchanged are reflected as maturing in 1-3 years.

(2)

The Denham Credit Facility was and Bridge Financing loans were repaid and terminated pursuant to the Restructuring consummated on September 22, 2009.

(3)

Includes monthly facility management and other fees.

(4)

Includes amounts anticipated to be paid for leased office space under non-cancelable operating leases, which contain escalation clauses, have terms that expire between July 2009 and October 2017 and are subject to extension at the option of the Company. We take into account all escalation clauses when determining the amount of future minimum lease payments. All future minimum lease payments are recognized on a straight-line basis over the minimum lease term.

(5)

Includes anticipated fees associated with agreements to transport and store natural gas. These agreements are take-or-pay in that we must pay for the capacity committed even if we do not use the capacity.

(6)

Includes both fixed and variable portions of physical forward contracts. The variable portion is indexed as the NYMEX settle price for the corresponding delivery month in which the natural gas is purchased. The estimated contractual obligations are based on the NYMEX forward curve as of June 30, 2009 for all corresponding delivery months.

 

In addition, as of June 30, 2009, we were required to provide collateral in the form of cash or letters of credit related to activity under our Hedge Facility, commodity supplier agreements and various transportation and storage arrangements.  At June 30, 2009, we posted a $35.0 million letter of credit as collateral under our Hedge Facility, $34.3 million of letters of credit as collateral under various supplier agreements and $27.0 million of letters of credit under various transportation and storage agreements.  As of June 30, 2009, all outstanding letters of credit were scheduled to mature during fiscal 2010.

 

Effective September 22, 2009, 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.  The estimated total value of these purchases will depend upon the market price of natural gas at the time of these purchases.  The Company’s 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.  In the event of early termination of the Commodity Supply Facility, the Company will be obligated to pay a volumetric fee for any unused balance of the minimum volume purchase requirement.

 

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Off-Balance Sheet Arrangements

 

We did not have any off-balance sheet arrangements as of June 30, 2009 or 2008.

 

Critical Accounting Policies

 

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

 

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

 

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

 

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

 

Revenue Recognition

 

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

 

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

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

 

Allowance for Doubtful Accounts

 

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

 

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

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

 

We are also subject to credit risk associated with the creditworthiness of LDCs that guarantee customer accounts receivable balances.  Although all of the LDCs that guarantee our customer accounts receivable had investment grade credit ratings as of June 30, 2009, any detrimental change in the creditworthiness of these LDCs could affect their ability to pay us amounts when due, and may result in the need for higher allowances and provisions for doubtful accounts.

 

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In addition, we may bear credit risk related to imbalance settlement receivables from LDCs and ISOs, to the extent that such LDCs and ISOs are unable to collect imbalance settlements payable to them by other retail marketers.   We record an allowance for doubtful accounts during the month that full collection of any such imbalance receivable balance becomes doubtful.  Therefore, the creditworthiness of other retail marketers, which is difficult to predict and monitor, may also impact our allowance and provision for doubtful accounts.

 

Goodwill

 

Goodwill is not amortized, but is reviewed for impairment at least annually or more frequently if events or changes in circumstances indicate that the carrying amount may not be recoverable.  Goodwill is tested for impairment annually at June 30.  We utilize a discounted cash flow methodology for our impairment testing, which gives consideration to significant and long-term changes in industry and economic conditions as primary indicators of potential impairment.

 

Goodwill of $3.8 million on our consolidated balance sheet at June 30, 2009 represents the excess of purchase price over the fair value of identifiable net assets acquired from SESCo in August 2006.   The goodwill related to the SESCo Acquisition was recorded at June 30, 2007, which is the date that the purchase allocation was finalized.  The goodwill has been assigned entirely to the natural gas business segment since the customers acquired in the SESCo Acquisition were primarily natural gas accounts.

 

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

 

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

 

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

·                  expected natural gas gross profit per MMBtu sold;

·                  expense trends;

·                  multiples of past and future earnings; and

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

 

We completed our annual goodwill impairment test as of June 30, 2009, and have concluded that there was no impairment of goodwill as of that date. In addition, we have concluded that, due to the successful consummation of the Restructuring, we are not at-risk for impairment.

 

Customer Acquisition Costs, net

 

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

 

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

 

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

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

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

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

 

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

 

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

 

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

 

As a result of all quarterly reviews conducted for the fiscal year ended June 30, 2009, we have concluded that there was no impairment to the carrying value of customer acquisition costs recorded on our consolidated balance sheets.

 

Income Taxes

 

The calculations of income tax expense and related balance sheet amounts involve a high degree of management judgment regarding estimates of the timing and probability of recognition of revenue and deductions by taxing authorities.  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 using enacted tax rates expected to be in effect for the year in which the temporary differences are expected to reverse.  In management’s opinion, adequate reserves have been recorded for any future taxes that may be owed as a result of examination by any taxing authority.

 

Total current and long-term deferred income tax assets were $24.1 million and $10.5 million at June 30, 2009 and 2008, respectively.  Our policy is to establish a valuation allowance if it is “more likely than not” that the related tax benefits will not be realized.  At June 30, 2009, we determined that it was “more likely than not” that a portion of our deferred tax assets would not be realized.

 

We have deferred tax assets related to unrealized losses from risk management activities.  We anticipate that these deferred tax assets will be realized in future periods when sales of fixed price commodities, to which the unrealized losses from risk management activities relate, occur.  Therefore, we did not establish a valuation allowance for these deferred tax assets.

 

For the remaining deferred tax assets reflected in the table above, we determined based on available evidence, including historical financial results for the last 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 of approximately $22.0 million and $0.7 million related to our U.S. and Canadian operations, respectively, as a reduction of the tax benefit recorded for fiscal year 2009.

 

The valuation allowance related to deferred tax assets is considered to be a critical estimate because, in assessing the likelihood of realization of deferred tax assets, management considers taxable income trends and forecasts.  Actual income taxes expensed and/or paid could vary from estimated amounts due to the impacts of various items, including:

 

·                  changes to tax laws by taxing authorities;

·                  final review of filed tax returns by taxing authorities;

·                  actual financial results for recent fiscal years; and

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

 

Derivatives

 

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

 

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market prices whenever possible.  As of June 30, 2009, less than 2% of the notional values of all derivative financial instruments outstanding were valued using non-quoted prices.

 

If quoted market prices are not available, quotes from third party brokers or internally-developed pricing models that are based on various assumptions and management judgment are used.  Although the total notional value of these instruments is not material at June 30, 2009, the assumptions used for these pricing models are considered to be critical estimates due to the high level of management judgment utilized in their development.

 

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

 

Redeemable Convertible Preferred Stock

 

Prior to the consummation of the Restructuring, we were authorized to issue 5,000,000 shares of Preferred Stock.  On June 30, 2004, we entered into the Preferred Stock Purchase Agreement, pursuant to which we issued 1,451,310 shares of Preferred Stock at a purchase price of $21.36 per share.  In accordance with provisions of the Preferred Stock Purchase Agreement, the Preferred Investors had the right to: (1) receive dividends on their shares; (2) convert their shares to common stock; and (3) elect to require us to redeem the Preferred Stock.  The rights of Preferred Investors to receive dividends and to elect to require redemption of the Preferred Stock were dependent upon the fair value of our common stock during the five-year period ending June 30, 2009.  Under certain circumstances, the appropriate redemption, conversion and dividend amounts were dependent upon the fair value of our common stock.

 

Because our common stock is not publicly traded, we obtain an independent valuation of fair value at June 30 of each fiscal year.  For the three-month periods ended September 30, December 31, and March 31 of each fiscal year, we calculate the fair value our common stock using an internally-developed model that approximates the independent model.  Key estimates and assumptions used in our stock valuation models include: (1) internally-developed earnings forecasts that reflect estimates of revenue and expense growth; and (2) expected stock price volatilities that are estimated based on historical realized volatilities of comparable publicly traded company stock prices.  These are considered to be critical estimates because the assumptions used involve a high degree of subjectivity and are based on historical experience and internal forecasts of future results.  There can be no assurance that actual future earnings or stock volatilities will approximate these estimates.

 

The Preferred Stock was converted to common stock on September 22, 2009 pursuant to the Restructuring.

 

Stock-Based Compensation

 

As of June 30, 2009, we had three stock-based compensation plans in effect, under which warrants and options have been granted to employees, non-employees and directors.  We use the Black-Scholes-Merton option-pricing model for estimating the fair value of awards granted after June 30, 2006.  The Black-Scholes-Merton option-pricing model was developed for use in estimating the fair value of traded options which have no vesting restrictions and are fully transferable.  In addition, option-pricing models require the input of highly subjective assumptions, including expected stock price volatility, expected term of the option award, expected annual forfeiture rate and risk-free interest rate.  These assumptions are primarily based on historical experience that may not necessarily approximate future results.

 

For awards of warrants and options granted prior to July 1, 2006, expense recorded in our statements of operations may fluctuate from reporting period to reporting period based upon the calculated fair value of our common stock.  Because our common stock is not publicly traded, we obtain an independent valuation of fair value at June 30 of each fiscal year.  For the three-month periods ended September 30, December 31, and March 31 of each fiscal year, we calculate the fair value our common stock using an internally-developed model that approximates the independent model.  Key estimates and assumptions used in our stock valuation models include: (1) internally-developed earnings forecasts that reflect estimates of revenue and expense growth; and (2) expected stock price volatilities that are estimated based on historical realized volatilities of comparable publicly traded company stock prices.  These are considered to be critical estimates because there is no guarantee that actual future earnings or stock volatilities will approximate these estimates.

 

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

 

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As of June 30, 2009, we had options and warrants outstanding that were, or may be, exercisable for 1,008,770 shares of common stock.  Pursuant to the Restructuring, we offered a cash settlement to holders of options and warrants to cancel and terminate such options and warrants.  As a result, all outstanding options and warrants were cancelled and terminated.

 

New Accounting Pronouncements

 

Accounting Pronouncements Adopted During the Fiscal Year Ended June 30, 2009

 

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

 

In February 2008, the FASB issued Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS No. 159”), which permits, but does not require, entities to elect fair value measurement for both the initial and subsequent measurements of certain financial assets and liabilities that were not previously measured at fair value, generally on an instrument-by-instrument basis.  Changes in fair value subsequent to initial measurement are to be recognized in earnings during the periods when those changes occur.  SFAS No. 159 also requires additional disclosures to compensate for the lack of comparability that will arise from the election of the fair value option for those financial instruments.  We did not adopt the provisions of SFAS No. 159 for any financial assets or liabilities as of the effective date of July 1, 2008.

 

In September 2008, the FASB ratified the consensus on Emerging Issues Task Force Issue No. 08-5, “Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement” (“EITF No. 08-5”).  EITF No. 08-5 requires that the measurement of liabilities with inseparable, third-party credit enhancements carried or disclosed at fair value on a recurring basis exclude the effect of the credit enhancement.  EITF No. 08-5 also requires debtors to consider their own credit standing, and not that of the third-party guarantor, in measuring the fair value of a liability with a third-party guarantee.  EITF No. 08-5 is effective on a prospective basis for the first reporting period on or after December 15, 2008, with earlier application permitted.  We adopted the provisions of EITF No. 08-5 effective January 1, 2009.  Adoption of EITF No. 08-5 did not have any impact on our financial position or results of operations.

 

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

 

In April 2009, the FASB issued FASB Staff Position No. FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (“FSP No. 157-4”).  FSP No. 157-4 provides additional guidance for estimating fair value in accordance with SFAS No. 157 when the volume and level of activity for the asset or liability have significantly decreased.  It also provides guidance on identifying circumstances that indicate a transaction is not orderly.  FSP No. 157-4 is effective for interim and annual reporting periods ending after June 15, 2009.  We adopted the provisions of FSP No. 157-4 effective for our fiscal quarter ending June 30, 2009.  The adoption of FSP No. 157-4 did not have any impact on our financial condition or results of operations

 

In May 2008, the FASB issued Statement of Financial Accounting Standards No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS No. 162”).  SFAS No. 162 identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements that are presented in conformity with U.S. GAAP.  We adopted the provisions of SFAS No. 162 effective January 1, 2009.  The adoption of SFAS No. 162 did not have any impact on our financial position or results of operations.

 

In May 2009, FASB issued Statement of Financial Accounting Standards No. 165, “Subsequent Events” (“SFAS No. 165”).  SFAS No. 165 establishes principles and requirements for subsequent events, including: (1) the period after the balance sheet date during which management of a reporting entity shall evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; (2) the circumstances under which an entity shall recognize events or

 

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transactions occurring after the balance sheet date in its financial statements; and (3) the disclosures that an entity shall make about events or transactions that occurred after the balance sheet date.  SFAS No. 165 is effective for interim or annual financial periods ending after June 15, 2009.  We adopted the provisions of SFAS No 165 effective with our financial statements prepared for the fiscal year ended June 30, 2009.  The adoption of SFAS No. 165 did not have any impact on our financial position or results of operations.

 

Accounting Pronouncements Not Yet Adopted as of June 30, 2009

 

In March 2008, the FASB issued Statement of Financial Accounting Standards No. 141(R), “Business Combinations” (“SFAS No. 141(R)”).  SFAS No. 141(R) establishes principles and requirements for an acquiring company to recognize and measure in its financial statements the identifiable assets acquired, liabilities assumed, goodwill acquired, any gain from a bargain purchase, and any noncontrolling interest in an acquired company.  In addition, SFAS No. 141(R) provides guidance for disclosures relating to business combinations.  SFAS No. 141(R) applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008.  We intend to adopt the provisions of SFAS No. 141(R) for acquisitions occurring on or after July 1, 2009.  We are currently evaluating the provisions of SFAS No. 141(R) to determine their likely impact on the accounting and reporting for future acquisitions, if any.

 

Also in March 2008, the FASB issued Statement of Financial Accounting Standards No. 160, “Noncontrolling Interests in Consolidated Financial Statements — An Amendment of ARB No. 51” (“SFAS No. 160”).  SFAS No. 160 establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, for changes in a parent’s ownership interest while the parent retains its controlling financial interest in a subsidiary, and for any retained noncontrolling equity investment by a parent when a subsidiary is deconsolidated.  SFAS No. 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008.  We intend to adopt the provisions of SFAS No. 160 for acquisitions occurring on or after July 1, 2009.  We are currently evaluating the provisions of SFAS No. 160 to determine their likely impact on the accounting and reporting for future acquisitions, if any.

 

In April 2009, the FASB issued FASB Staff Position No. FAS 141(R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies” (“FSP No. FAS 141(R)-1”).  FSP No. FAS 141(R)-1 amends and clarifies SFAS No. 141(R) to address application issues relating to accounting and disclosures for assets and liabilities arising from contingencies in a business combination.  FSP No. FAS 141(R)-1 applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008.  We intend to adopt the provisions of FSP No. FAS 141(R)-1 for acquisitions occurring on or after July 1, 2009.  We are currently evaluating the provisions of FSP No. FAS 141(R)-1 for their likely impact on the accounting and reporting for future acquisitions, if any.

 

In April 2009, the FASB issued FASB Staff Position No. FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (“FSP FAS 107-1 and APB 28-1”).  FSP FAS 107-1 and APB 28-1 amends FASB Statement No. 107, “Disclosures about Fair Value of Financial Instruments,” to require disclosures about financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements.  It also amends APB Opinion No. 28, “Interim Financial Reporting,” to require those disclosures in summarized financial information at interim reporting periods.  FSP FAS 107-1 and APB 28-1 is effective for interim reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009.  We intend to adopt the provisions of FSP FAS 107-1 and APB 28-1 effective with our reporting period ending September 30, 2009, which represents the first interim reporting period of our 2010 fiscal year.

 

In June 2009, the FASB issued Statement of Financial Accounting Standards No. 168, “The FASB Accounting Standards CodificationTM and the Hierarchy of Generally Accepted Accounting Principles” (“SFAS No. 168”).  SFAS No. 168 identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles in the United States.  SFAS No 168 replaces SFAS No. 162.   SFAS No. 168 is effective for financial statements issued for interim and annual periods ending after September 15, 2009.  We intend to adopt the provisions of SFAS No. 168 effective July 1, 2009.  The adoption of SFAS No. 168 is not expected to have any impact on our financial position or results of operations.

 

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Risk Management

 

Overview

 

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

 

·                  Timely identification of various risks associated with our business;

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

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

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

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

 

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

 

The Risk Oversight Committee is primarily responsible for oversight of our process for identifying and mitigating market risks associated with acquiring natural gas and electricity commodities for distribution to our customers.

 

Market Risk Management

 

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

 

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

 

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

 

Liquidity Risk Management

 

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

 

·                  Utilize our hedging strategy to reduce the impact of volatile commodity prices — We have a risk management policy that is intended to reduce our financial exposure related to changes in the price of natural gas and electricity.  Under this policy, we hedge all anticipated natural gas and electricity commodity purchases required to meet expected customer demand for all accounts served under fixed price contracts.  Although we engage in hedging activities with various counterparties for electricity, as of June 30, 2009 we utilized the Hedge Facility as our primary natural gas hedge facility.

 

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·      Utilize our credit facilities to provide liquidity for operating requirements As of June 30, 2009, through the Revolving Credit Facility, we had a ready source of liquidity, primarily in the form of letters of credit used for collateral to be placed with hedge counterparties, commodity suppliers and providers of transportation and storage services.  On September 22, 2009, we entered into the Commodity Supply Facility, which we believe is adequate to supplement cash provided by operations for meeting our operational liquidity needs for fiscal year 2010.

 

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

 

·      Maximize cash collections from customers and LDCs – During fiscal year 2009, approximately 45% of our total sales of natural gas and electricity was within markets that guarantee customer accounts receivable.  The LDCs in these markets have credit ratings that are investment grade.  We monitor the payment histories, credit ratings and other financial information for these LDCs in order to identify and address adverse trends, if any.  As of June 30, 2009, we do not maintain an allowance for doubtful accounts against receivables from these LDCs as we do not anticipate any material credit losses related to these receivables.

 

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

 

Operational and Compliance Risk Management

 

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

 

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

 

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

 

·      Regulatory affairs;

·      Marketing and sales;

·      Contract pricing;

·      Natural gas and electricity supply;

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

·      Compliance;

·      Financial and tax reporting;

·      Legal counsel; and

·      Human Resources and payroll.

 

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

 

Fraud Risk

 

We have a formal fraud risk assessment program, which is designed to facilitate:

 

·      Identification of potential fraud risks;

·      Design of internal controls to address and mitigate the fraud risks identified;

·      Periodic reviews of controls for effectiveness; and

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

 

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

 

Information Systems

 

We maintain a number of information systems for capturing customer, accounting, supply forecasting and risk management information.  The majority of our systems are hosted at an offsite data center in Houston, Texas, which maintains 24/7 security and has stand-alone power generation to keep the data center functional in the case of an extended power outage.

 

During fiscal year 2008, in conjunction with our hosting provider, we launched an initiative to modernize our key server infrastructure to increase reliability and to increase redundancy.  During fiscal 2009, we continued to consolidate our multiple existing customer relationship management tools and multiple billing platforms.  As of June 30, 2009, more than 80% of our customers had been consolidated into our primary strategic systems.  We are also continuing to convert our demand forecasting and risk management operations to new or enhanced third party software systems.  We are currently utilizing these systems and will continue to make enhancements during fiscal 2010.

 

We perform daily backup of our key servers and maintain backup tapes for a period of four weeks before they are overwritten.  We also perform a month-end backup of key servers and keep such data for a period of six months to one year. All backup tapes are rotated offsite at a secure storage facility on a weekly basis.  We currently replicate our email and various other production servers to ensure availability of our critical systems.  We are in the process of increasing this functionality to additional servers.

 

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

 

Our corporate website has been custom-developed by an outsourced marketing company and was hosted offsite as of June 30, 2009.  In July 2009, we began hosting our corporate website onsite with a full-time employee of the Company serving as our webmaster.

 

Business Continuity Planning

 

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

 

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

Commodity Price Risk

 

Commodity price risk is the risk of exposure to fluctuations in the price of natural gas and electricity.  Because our contracts require that we deliver full commodity requirements to many of our customers and because our customers’ usage is impacted by factors such as weather, we are exposed to fluctuations in customer load requirements.  We typically purchase commodity equal to expected customer consumption assuming normal weather patterns.  We may purchase additional commodity volumes for the summer in the case of electricity and for the winter in the case of natural gas in order to protect against a potential demand increase in peak seasons.  As a result of the natural swing in customer consumption related 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 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 June 30, 2009, our hedge positions extend through December 2011.

 

We have adopted a risk management policy to measure and limit market risk and credit risk associated with our customer portfolio.  The risk policy requires that we maintain a balanced position at all times and does not permit speculative trading.  None of our employees are compensated on the basis of his or her trading gains.  In marketing 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

 

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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 fiscal year 2009, volatility in natural gas commodity prices resulted in higher 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 fiscal years 2009 and 2008 are summarized in the following table.

 

 

 

Fiscal Year Ended June 30,

 

Potential loss during the period

 

2009

 

2008

 

 

 

(in thousands)

 

Fiscal ended March 31:

 

 

 

 

 

Average

 

$

120

 

$

108

 

Maximum

 

624

 

366

 

Minimum

 

25

 

7

 

 

There have been no material changes in our methodology or policies regarding commodity price risk management during the fiscal year ended June 30, 2009.

 

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 has an investment grade credit rating as of June 30, 2009.  Subsequent to consummation of the Restructuring, 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 fiscal year ended June 30, 2009, approximately 55% of our total sales of natural gas and electricity were within markets where LDCs do not guarantee customer accounts receivable while 45% 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 June 30, 2009, 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.  Based upon our review as of June 30, 2009, and for the fiscal year ended, we believe that the allowance for doubtful accounts is adequate to cover potential credit losses related to customer accounts receivable.

 

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.  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.

 

 

 

Fiscal Year Ended June 30,

 

 

 

2009

 

2008

 

2007

 

 

 

 

 

 

 

 

 

Provision for doubtful accounts as a percentage of sales of natural gas and electricity in non-guaranteed markets

 

2.79

%

1.19

%

0.82

%

 

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During fiscal year 2009, we experienced deterioration of the aging of billed customer accounts receivable within several of our markets, including our largest natural gas market in Georgia and in our Texas electricity market, which resulted in an increase in the provision for doubtful accounts.  We will continue to closely monitor economic conditions and actual collections data within these and other 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 fiscal year ended June 30, 2009.

 

Interest Rate Risk

 

Effective August 4, 2006, we became exposed to fluctuations in interest rates under the Floating Rate Notes due 2011.  As of June 30, 2009, $165.2 million aggregate principal of the Floating Rate Notes due 2011 was outstanding, before original issue discount.  We entered into interest rate swap agreements during fiscal 2007, which are utilized to manage our exposure to interest rate fluctuations on the Floating Rate Notes due 2011.  These agreements effectively convert interest rate exposure from a variable rate to a fixed rate of interest.  As of June 30, 2009, the following interest rate swaps were outstanding.

 

·      A $30.0 million swap that expires on August 2, 2010 and bears interest at 10.33% per annum; and

·      An $80.0 million swap that expires on August 1, 2011 that bears interest at 13.24% per annum.

 

The $30.0 million swap that was due to expire on August 2, 2010 was terminated in September 2009.  A $50.0 million swap expired on August 1, 2008 and was not replaced.

 

All swaps are fixed-for-floating and settle against the six-month LIBOR rate.  None of the interest rate swaps have been designated as a hedge and, accordingly, changes in the market value of the interest rate swaps are charged directly to interest expense.  The additional interest expense associated with changes in the market value of interest rate swaps was $3.7 million, $3.3 million and $0.9 million for the fiscal years ended June 30, 2009, 2008 and 2007, respectively.

 

Our average, high and low month-end balances for the Floating Rate Notes due 2011 during fiscal year 2009, net of the aggregate balance of the interest rate swaps, were approximately $53.5 million, $55.2 million and $35.2 million, respectively.  Based on the average outstanding amount of our variable rate indebtedness under the Floating Rate Notes due 2011 during the fiscal years ended June 30, 2009 and 2008, a one percentage point change in the interest rates, net of the effects of the interest rate swaps, would have impacted our annual interest expense by approximately $0.5 million and $0.4 million, respectively.  Based on the average outstanding amount of variable rate indebtedness expected for the fiscal year ending June 30, 2010, a one percentage point change in the interest rates would impact fiscal 2010 interest expense by approximately $0.6 million.

 

The Commodity Supply Facility requires that the Company novate or unwind the remaining $80.0 million swap subsequent to closing of the Commodity Supply Facility, with RBS Sempra providing any necessary credit support to liquidate that position.

 

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Report of Independent Registered Public Accounting Firm

 

The Board of Directors and Stockholders
MXenergy Holdings Inc.

 

We have audited the accompanying consolidated balance sheets of MXenergy Holdings Inc. as of June 30, 2009 and 2008, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended June 30, 2009. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

 

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

 

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of MXenergy Holdings Inc. at June 30, 2009, and 2008, and the consolidated results of its operations and its cash flows for each of the three years in the period ended June 30, 2009, in conformity with U.S. generally accepted accounting principles.

 

 

Stamford, Connecticut

October 13, 2009

 

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MXENERGY HOLDINGS INC.

Consolidated Balance Sheets

(dollars in thousands)

 

 

 

Balance at June 30,

 

 

 

2009

 

2008

 

 

 

 

 

 

 

Assets

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

 

$

23,266

 

$

71,958

 

Restricted cash

 

75,368

 

587

 

Accounts receivable, net (Note 6)

 

47,598

 

87,673

 

Natural gas inventories (Note 7)

 

29,415

 

65,006

 

Current portion of unrealized gains from risk management activities (Note 13)

 

294

 

35,864

 

Income taxes receivable

 

6,461

 

7,524

 

Deferred income taxes (Note 11)

 

9,020

 

 

Other current assets

 

12,084

 

3,361

 

Total current assets

 

203,506

 

271,973

 

Unrealized gains from risk management activities (Note 13)

 

 

13,221

 

Goodwill (Note 8)

 

3,810

 

3,810

 

Customer acquisition costs, net (Note 9)

 

27,950

 

41,693

 

Fixed assets, net (Note 10)

 

3,728

 

10,525

 

Deferred income taxes (Note 11)

 

15,089

 

10,503

 

Other assets

 

4,988

 

4,027

 

Total assets

 

$

259,071

 

$

355,752

 

 

 

 

 

 

 

Liabilities and stockholders’ equity

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Accounts payable and accrued liabilities (Note 12)

 

$

33,300

 

$

36,602

 

Accrued commodity purchases

 

9,847

 

51,461

 

Current portion of unrealized losses from risk management activities (Note 13)

 

34,224

 

2,978

 

Deferred revenue

 

4,271

 

7,435

 

Bridge Financing loans payable (Note 19)

 

5,400

 

 

Denham Credit Facility (Note 19)

 

12,000

 

 

Deferred income taxes (Note 11)

 

 

9,800

 

Total current liabilities

 

99,042

 

108,276

 

Unrealized losses from risk management activities (Note 13)

 

14,071

 

2,839

 

Long-term debt:

 

 

 

 

 

Floating Rate Notes due 2011 (Note 16)

 

163,476

 

162,648

 

Total long-term debt

 

163,476

 

162,648

 

Total liabilities

 

276,589

 

273,763

 

 

 

 

 

 

 

Redeemable Convertible Preferred Stock (Note 17)

 

54,632

 

48,779

 

 

 

 

 

 

 

Commitments and contingencies (Note 21)

 

 

 

 

 

 

 

 

 

Stockholders’ equity:

 

 

 

 

 

Common stock, par value $0.01, 10,000,000 shares authorized; 4,681,219 and 3,604,788 shares issued and outstanding, respectively

 

47

 

36

 

Additional paid-in capital

 

18,275

 

23,635

 

Unearned stock compensation

 

 

(4

)

Accumulated other comprehensive loss

 

(3

)

(189

)

(Accumulated deficit) retained earnings

 

(90,469

)

9,732

 

Total stockholders’ equity

 

(72,150

)

33,210

 

Total liabilities and stockholders’ equity

 

$

259,071

 

$

355,752

 

 

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

 

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MXENERGY HOLDINGS INC.

Consolidated Statements of Operations

(dollars in thousands)

 

 

 

Fiscal Years Ended June 30,

 

 

 

2009

 

2008

 

2007

 

 

 

 

 

 

 

 

 

Sales of natural gas and electricity

 

$

789,780

 

$

752,283

 

$

703,926

 

Cost of goods sold (excluding depreciation and amortization):

 

 

 

 

 

 

 

Cost of natural gas and electricity sold

 

596,747

 

630,006

 

552,028

 

Realized losses from risk management activities, net

 

72,824

 

6,747

 

33,039

 

Unrealized losses (gains) from risk management activities, net

 

87,575

 

(67,168

)

17,079

 

 

 

757,146

 

569,585

 

602,146

 

Gross profit

 

32,634

 

182,698

 

101,780

 

 

 

 

 

 

 

 

 

Operating expenses:

 

 

 

 

 

 

 

General and administrative expenses

 

59,957

 

62,271

 

54,516

 

Advertising and marketing expenses

 

2,117

 

4,546

 

4,044

 

Reserves and discounts

 

15,130

 

7,130

 

4,725

 

Depreciation and amortization

 

37,575

 

32,698

 

27,730

 

Total operating expenses

 

114,779

 

106,645

 

91,015

 

 

 

 

 

 

 

 

 

Operating (loss) profit

 

(82,145

)

76,053

 

10,765

 

Interest expense (net of interest income of $430, $3,806 and $4,258, respectively)

 

45,305

 

34,105

 

33,058

 

(Loss) income before income tax benefit (expense)

 

(127,450

)

41,948

 

(22,293

)

Income tax benefit (expense)

 

27,249

 

(17,155

)

8,495

 

Net (loss) income

 

$

(100,201

)

$

24,793

 

$

(13,798

)

 

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

 

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MXENERGY HOLDINGS INC.

Consolidated Statements of Stockholders’ Equity

(dollars in thousands)

 

 

 

Common
Stock
(Par Value)

 

Additional
Paid-in
Capital

 

Unearned
Stock
Compensation

 

Accumulated
Other
Comprehensive
Loss

 

(Accumulated
Deficit)
Retained
Earnings

 

Total
Stockholders’
Equity

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance at June 30, 2006

 

$

34

 

$

17,355

 

$

(115

)

$

(40

)

$

18,159

 

$

35,393

 

Issuance of common stock

 

 

22

 

 

 

 

22

 

Unamortized stock compensation

 

 

2,219

 

(2,219

)

 

 

 

Purchase and cancellation of treasury shares

 

 

(654

)

 

 

 

(654

)

Stock compensation expense

 

 

2,227

 

 

 

 

2,227

 

Tax benefit on issuance of common stock from options

 

 

198

 

 

 

 

198

 

Amortization of stock compensation

 

 

 

2,312

 

 

 

2,312

 

Comprehensive income (loss):

 

 

 

 

 

 

 

 

 

 

 

 

 

Net loss

 

 

 

 

 

(13,798

)

(13,798

)

Foreign currency translation

 

 

 

 

(89

)

 

(89

)

Comprehensive loss

 

 

 

 

 

 

 

 

 

 

 

(13,887

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance at June 30, 2007

 

34

 

21,367

 

(22

)

(129

)

4,361

 

25,611

 

Issuance of common stock

 

2

 

1,337

 

 

 

 

1,339

 

Revaluation of Redeemable Convertible Preferred Stock

 

 

 

 

 

(19,422

)

(19,422

)

Unamortized stock compensation

 

 

(558

)

558

 

 

 

 

Purchase and cancellation of treasury shares

 

 

(1,559

)

 

 

 

(1,559

)

Stock compensation expense

 

 

2,244

 

 

 

 

2,244

 

Tax benefit on issuance of common stock from options

 

 

804

 

 

 

 

804

 

Amortization of stock compensation

 

 

 

(540

)

 

 

(540

)

Comprehensive income (loss):

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

 

 

 

 

24,793

 

24,793

 

Foreign currency translation

 

 

 

 

(60

)

 

(60

)

Comprehensive income

 

 

 

 

 

 

 

 

 

 

 

24,733

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance at June 30, 2008

 

36

 

23,635

 

(4

)

(189

)

9,732

 

33,210

 

Issuance of common stock

 

11

 

(11

)

 

 

 

 

Revaluation of Redeemable Convertible Preferred Stock

 

 

(5,853

)

 

 

 

(5,853

)

Unamortized stock compensation

 

 

(584

)

584

 

 

 

 

Purchase and cancellation of treasury shares

 

 

(11

)

 

 

 

(11

)

Stock compensation expense

 

 

1,099

 

 

 

 

1,099

 

Amortization of stock compensation

 

 

 

(580

)

 

 

(580

)

Comprehensive income (loss):

 

 

 

 

 

 

 

 

 

 

 

 

 

Net loss

 

 

 

 

 

(100,201

)

(100,201

)

Foreign currency translation

 

 

 

 

186

 

 

186

 

Comprehensive loss

 

 

 

 

 

 

(100,015

)

Balance at June 30, 2009

 

$

47

 

$

18,275

 

$

 

$

(3

)

$

(90,469

)

$

(72,150

)

 

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

 

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Table of Contents

 

MXENERGY HOLDINGS INC.

Consolidated Statements of Cash Flows

(dollars in thousands)

 

 

 

Fiscal Years Ended June 30,

 

 

 

2009

 

2008

 

2007

 

Operating activities:

 

 

 

 

 

 

 

Net (loss) income

 

$

(100,201

)

$

24,793

 

$

(13,798

)

Adjustments to reconcile net (loss) income to net cash (used in) provided by operating activities:

 

 

 

 

 

 

 

Unrealized losses (gains) from risk management activities

 

87,575

 

(67,168

)

17,079

 

Stock compensation expense

 

519

 

1,704

 

4,539

 

Depreciation and amortization

 

37,575

 

32,698

 

27,730

 

Deferred income tax (benefit) expense

 

(23,406

)

18,187

 

(14,449

)

Non-cash interest expense, primarily unrealized losses on interest rate swaps and amortization of deferred financing fees

 

16,233

 

10,836

 

7,906

 

Amortization of customer contracts acquired

 

(634

)

(762

)

11,891

 

Changes in assets and liabilities, net of effects of acquisitions:

 

 

 

 

 

 

 

Restricted cash

 

(74,781

)

463

 

(623

)

Accounts receivable

 

40,075

 

(30,181

)

3,453

 

Natural gas inventories

 

36,509

 

(7,308

)

(1,712

)

Income taxes receivable

 

1,063

 

(7,173

)

5,184

 

Option premiums

 

1,571

 

1,191

 

1,835

 

Other assets

 

(20,509

)

609

 

(993

)

Accounts payable, accrued commodity purchases and other accrued liabilities

 

(46,553

)

17,882

 

31,555

 

Deferred revenue

 

(3,164

)

(4,352

)

9,384

 

Net cash (used in) provided by operating activities

 

(48,128

)

(8,581

)

88,981

 

 

 

 

 

 

 

 

 

Investing activities:

 

 

 

 

 

 

 

Purchase of Catalyst assets

 

(1,609

)

 

 

Loan to PS Energy Group, Inc. related to purchase of GasKey assets

 

 

(8,983

)

 

Cash received from PS Energy Group, Inc. for repayment of loan.

 

 

8,983

 

 

Purchase of GasKey assets

 

 

(12,427

)

 

Purchase of SESCo assets

 

 

 

(126,044

)

Return of deposit related to purchase of SESCo assets

 

 

 

3,348

 

Purchase of Vantage assets

 

 

 

(732

)

Customer acquisition costs

 

(15,343

)

(19,555

)

(7,610

)

Purchases of fixed assets

 

(1,001

)

(1,959

)

(1,882

)

Net cash used in investing activities

 

(17,953

)

(33,941

)

(132,920

)

 

 

 

 

 

 

 

 

Financing activities:

 

 

 

 

 

 

 

Proceeds from Denham Credit Facility

 

12,000

 

 

23,040

 

Repayments of Denham Credit Facility

 

 

(11,040

)

(12,000

)

Proceeds from cash advanced under the Revolving Credit Facility

 

30,000

 

 

 

Repayment of cash advances under the Revolving Credit Facility

 

(30,000

)

 

 

Proceeds from Bridge Financing under the Revolving Credit Facility

 

10,400

 

 

 

Repayment of Bridge Financing under the Revolving Credit Facility

 

(5,000

)

 

 

Proceeds from other loans

 

 

 

6,000

 

Repayments of other loans

 

 

 

(6,000

)

Debt financing costs

 

 

 

(9,345

)

Proceeds from bridge loan

 

 

 

190,000

 

Repayment of bridge loan

 

 

 

(190,000

)

Proceeds from Floating Rate Notes due 2011

 

 

 

185,250

 

Repurchase of Floating Rate Notes due 2011

 

 

(12,006

)

(11,723

)

Issuance of common stock from exercise of warrants and options

 

 

387

 

22

 

Issuance of common stock from other executive compensation

 

 

952

 

 

Purchase and cancellation of treasury shares, net of tax benefit

 

(11

)

(755

)

(456

)

Net cash provided by (used in) financing activities

 

17,389

 

(22,462

)

174,788

 

Net (decrease) increase in cash

 

(48,692

)

(64,984

)

130,849

 

Cash and cash equivalents at beginning of year

 

71,958

 

136,942

 

6,093

 

Cash and cash equivalents at end of year

 

$

23,266

 

$

71,958

 

$

136,942

 

 

 

 

 

 

 

 

 

Supplemental cash flow information:

 

 

 

 

 

 

 

Income taxes paid

 

$

431

 

$

5,405

 

$

753

 

Interest paid

 

$

31,616

 

$

29,426

 

$

17,345

 

 

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

 

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Table of Contents

 

MXENERGY HOLDINGS INC.

Notes to Consolidated Financial Statements

 

Note 1.  Organization

 

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

 

Note 2.  Significant Accounting Policies

 

Basis of Presentation

 

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

 

Principles of Consolidation

 

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

 

Use of Estimates and Assumptions

 

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

 

Revenue Recognition

 

Sales of Natural Gas and Electricity

 

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

 

Passthrough Revenues

 

Revenues also include certain “passthrough” revenues, which represent transportation charges billed to customers by certain LDCs.  These revenues are offset by corresponding amounts in cost of goods sold for amounts billed to the Company by the LDC.

 

Fees Charged to Customers

 

Various fees charged to customers, such as late payment fees, early contract termination fees, service shut-off fees and fees charged to customers for providing copies of bills, are generally recorded as revenue when collection is deemed to be reasonably assured.  Late payment fees charged in all markets, and various other fees charged in certain markets are recorded as revenue when billed to the customer.  Certain other fees are recorded as revenue when actually collected from the customer.

 

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Deferred Revenue

 

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

 

Sales Incentives

 

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

 

Collections of Sales Tax

 

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

 

Fair Value of Financial Instruments

 

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

 

Short-term Financial Assets and Liabilities

 

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

 

The Company had $22.1 million and $68.5 million invested in money market funds at June 30, 2009 and 2008, respectively.  Each share of the money market funds was valued at $1.00 at June 30, 2009 and 2008.

 

Derivatives

 

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

 

As of June 30, 2009, natural gas derivative instruments are generally with a single counterparty under the Company’s primary hedge facility and the Company uses various counterparties for electricity derivative instruments.  The Company generally enters into master netting agreements with hedge counterparties for settlement of derivative fair value assets and liabilities.  The Company records such fair value assets and liabilities net on the consolidated balance sheets.

 

The recorded fair values of derivative instruments reflect management’s best estimate of market 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.

 

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Long-term Debt

 

At June 30, 2009, long-term debt includes the aggregate outstanding principal amount of Floating Rate Notes due 2011.  The carrying values of long-term debt instruments are not necessarily indicative of fair value due to changing market conditions and terms for similar unsecured instruments.  The Company has elected not to record these financial instruments at fair value at June 30, 2009.

 

Foreign Currency Translation

 

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

 

Cash and Cash Equivalents

 

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

 

Restricted Cash

 

Restricted cash consists of: (1) cash and money market funds required as security for letters of credit issued under the Company’s Revolving Credit Facility; (2) cash and money market funds required as security for surety bonds required by LDCs, utility commissions and pipeline tariffs and regulations; (3) money market funds held in escrow as contingent consideration related to acquisitions; and (4) cash deposits received from customers.

 

Accounts Receivable and Allowance for Doubtful Accounts

 

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

 

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

 

Accounts receivable also includes cash imbalance settlements that represent the value of excess natural gas delivered to LDCs for consumption by our customers and actual customer usage.   Such imbalances are expected to be settled in cash in accordance with contractual payment arrangements.  The Company bears credit risk related to imbalance settlement receivables to the extent that such LDCs are unable to collect imbalance settlements payable to them by other retail marketers.  The Company records an allowance for doubtful accounts during the month that full collection of any such imbalance receivable balance becomes doubtful, with a corresponding charge to reserves and discounts.

 

Natural Gas Inventories

 

Natural gas inventories include natural gas held in storage by third parties on the Company’s behalf, which are valued at the lower of cost or market value on a weighted-average cost basis.  The weighted-average cost of inventory includes related transportation and storage costs.

 

Natural gas inventories also include estimated commodity delivery/usage imbalance settlement amounts that represent natural gas to be transferred to the Company from various third parties within the upcoming twelve-month period.

 

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Adjustments to the value of natural gas inventories on the consolidated balance sheets result in corresponding adjustments to cost of goods sold on the consolidated statements of operations.  Such adjustments result from changes in inventory storage levels as natural gas is delivered to customers as well as changes in the weighted average cost of natural gas in storage.

 

Other Current Assets

 

Other current assets primarily include: (1) security deposits placed with commodity and other suppliers as collateral for future purchases in lieu of letters of credit or other credit enhancements; and (2) prepaid expenses and deferred charges, which include costs incurred that pertain to future benefit periods not exceeding twelve months.  These costs are amortized to appropriate expense lines on the consolidated statement of operations over their estimated benefit period.

 

Business Combinations and Goodwill

 

Since its organization in 1999, the Company has acquired natural gas and electricity operations of numerous energy companies, each of which was recorded as a purchase business combination.  For all purchase business combinations recorded through June 30, 2009, the purchase price was allocated to the net assets acquired based on their estimated fair values at the acquisition date.  Costs incurred to effect the purchase business combination transaction (e.g., legal, accounting, valuation and other professional or consulting fees) were added to the costs of the acquisition and allocated accordingly to the net assets acquired.  Certain intangible assets, such as customer acquisition costs and goodwill, were recorded as a result of purchase business combinations to the extent that the purchase price exceeded the values assigned to identifiable net assets.  The initial purchase price allocation was reviewed and adjusted for a period of twelve months subsequent to the acquisition date as new or revised information became available.

 

Effective July 1, 2009, the Company adopted the provisions of Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards No. 141(R), “Business Combinations” (“SFAS No. 141(R)”), which establishes principles and requirements for an acquiring company to recognize and measure in its financial statements the identifiable assets acquired, liabilities assumed, goodwill acquired, any gain from a bargain purchase, and any noncontrolling interest in an acquired company.  Under SFAS No. 141(R), assets acquired and liabilities assumed for purchase business combinations after June 30, 2009, if any, will to be recorded at their estimated fair values, regardless of their cost.  Additionally, costs incurred to effect such transactions will be recognized separately from the acquisition transaction and generally be expensed during the periods in which the costs are incurred and the services are received.  Finally, restructuring costs that the Company was not obligated to incur will also be recognized separately from the purchase business combination transaction.

 

The Company has determined that its natural gas and electricity reporting units correspond with its business segments for management and financial reporting purposes.

 

As of June 30, 2009, goodwill of $3.8 million represents the excess of purchase price over the fair value of identifiable natural gas net assets acquired from Shell Energy Services Company L.L.C. (“SESCo”) in August 2006.   The Company has assigned this goodwill to its natural gas business segment.  Goodwill is not amortized, but rather is reviewed for impairment at least annually or more frequently if events or changes in circumstances indicate that the carrying amount may not be recoverable.  Goodwill is tested for impairment annually at June 30.  The Company utilizes a discounted cash flow methodology for its impairment testing, which gives consideration to significant and long-term changes in industry and economic conditions as primary indicators of potential impairment.

 

Customer Acquisition Costs, Net

 

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

 

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

 

Direct-response telemarketing costs are capitalized to the extent that: (1) their purpose was to elicit sales to customers; (2) customers have responded specifically to the advertising; and (3) probable future economic benefit results from the activity.  Such costs are amortized over the period during which the future economic benefits are expected to be realized.

 

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The Company currently estimates a three-year benefit period for these assets.  Periodic amortization expense is calculated on a cost-pool-by-cost-pool basis, and is based on the current revenues generated for a cost-pool in relation to the total current and future estimated revenues for that cost-pool.

 

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

 

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

 

Fixed Assets, Net

 

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

 

Capitalized Software Costs

 

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

 

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

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

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

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

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

 

The following software-related costs are generally expensed as incurred and recorded in general and administrative expenses on the consolidated statements of operations:

 

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

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

·      costs of selecting a vendor for acquired software;

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

·      internal or external training costs related to software;

·      internal or external maintenance costs related to software;

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

·      updates and minor modifications; and

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

 

The costs of computer software obtained or developed for internal use is amortized on a straight-line basis over the estimated useful life of the software.  Amortization begins when the software and all related software modules on which it is functionally dependant are ready for their intended use.  Amortization expense is recorded in depreciation and amortization in

 

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the consolidated statements of operations.  The Company’s amortization period does not exceed five years for any capitalized software project.

 

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

 

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

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

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

 

Income Taxes

 

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

 

Deferred 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 using enacted tax rates expected to be in effect for the year in which the temporary differences are expected to reverse.  The Company records a valuation allowance if it is “more likely than not” that the related tax benefits will not be realized.

 

Derivatives and Hedging Activities

 

Commodity Derivatives

 

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

 

The recorded fair values of derivative instruments reflect management’s best estimate of market 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.

 

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

 

Interest Rate Swaps

 

The Company utilizes interest rate swaps to reduce its exposure to interest rate fluctuations related to its Floating Rate Notes due 2011.  The swaps are fixed-for-floating and settle against the six month LIBOR rate.  None of the interest rate swaps has been designated as a hedge, and accordingly, these instruments are carried at fair value on the consolidated balance sheets with changes in fair value recorded as adjustments to interest expense.

 

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Debt

 

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

 

Debt Issue Discounts and Debt Issue Costs

 

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

 

Early Extinguishment of Debt

 

During the period from August 2006 through June 30, 2009, the Company purchased approximately $24.8 million in aggregate principal amount of Floating Rate Notes due 2011 from the holders of the notes.  These transactions were recorded as early extinguishments of debt.  Gains from these transactions, which result from the discounts paid by the Company for outstanding Floating Rate Notes due 2011, are recorded as adjustments to interest expense.

 

Interest Expense

 

Interest expense includes interest accrued for various debt instruments, certain fees paid for issuance of letters of credit and other transactions related to the Company’s credit agreements, amortization of debt issue discount and amortization of deferred debt issue costs.   Interest expense on the consolidated statements of operations is presented net of interest income earned from cash and cash equivalents and restricted investments.

 

Redeemable Convertible Preferred Stock

 

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

 

The agreement that governs the Preferred Stock contains various provisions for redemption of the Preferred Stock, for conversion of the Preferred Stock to common stock and for preferences of the holders of the Preferred Stock should the Company be liquidated.  Should any of these events occur, the holders of the Preferred Stock are guaranteed a minimum return of 12% per annum, compounded annually, from the June 30, 2004 issue date through the date of the redemption, conversion or liquidation event.  Adjustments to the carrying value of the Preferred Stock as a result of any of these events are recorded as a charge against retained earnings or, in the absence of retained earnings, by charges against additional paid-in capital.  On September 22, 2009, the Preferred Stock was converted into the newly authorized Class C Common Stock.  As of September 22, 2009, no Preferred Stock is outstanding.

 

Stock Based Compensation

 

As of June 30, 2009, the Company had three stock-based compensation plans in effect, under which stock options to acquire the Company’s common stock have been granted to employees, directors and other non-employees of the Company.  In addition, the Company has issued warrants to purchase its common stock to certain employees and non-employees that were not issued under any of its three approved stock-based compensation plans.  Refer to Note 18 for additional information regarding the Company’s stock based compensation plans and its grants of options and warrants.

 

Compensation expense related to all awards of options and warrants is recorded in general and administrative expenses in the consolidated statements of operations.

 

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

 

For stock option awards granted after June 30, 2006, the Company recognizes compensation expense prospectively over the vesting period.  Compensation expense for option awards subject to graded vesting is recognized based on the accelerated attribution method as specified under U.S. GAAP guidelines.  The fair value of each option award granted subsequent to

 

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June 30, 2006 is estimated on the grant date using a Black-Scholes-Merton option valuation model.  Certain key assumptions used in the model included share price volatility, expected term, risk-free interest rate and expected forfeiture rate.  Total compensation expense to be recognized over the vesting period is based on: (1) the fair value of the Company’s common stock at the quarterly reporting date (e.g., September 30, December 31, March 31 and June 30) immediately prior to the grant date, as determined by an independent valuation of the Company’s common stock or internally developed valuation models; and (2) the total number of options expected to be exercised, net of expected forfeitures.  The cumulative effect on current and prior periods of a change in the number of options expected to be exercised, net of forfeitures, is recognized in compensation expense in the period of the change.

 

The Company has elected to follow APB No. 25, and related interpretations, in accounting for stock option awards granted to employees prior to June 30, 2006, rather than the alternative fair value method allowed under SFAS No. 123.  APB No. 25 provides that compensation expense relative to the Company’s employee stock and stock option grants be measured based on the intrinsic value of the stock or stock option at the grant date.  Pursuant to APB No. 25, for options granted to employees prior to June 30, 2006, the Company was not required to recognize compensation expense during the fiscal years ended June 30, 2009, 2008 or 2007 because the exercise price for all such awards equaled or exceeded the estimated fair value of the Company’s common stock at the grant date.

 

Awards of Warrants to Acquire the Company’s Common Stock

 

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

 

Certain warrants issued by the Company prior to June 30, 2006 are not subject to variable plan accounting because there is no requirement to provide any future service to the Company in order to exercise the warrants.  Therefore, the Company does not record any compensation expense related to these warrants.

 

Transactions with Related Parties

 

In the normal course of business, the Company enters into transactions with various non-employee related parties for financing arrangements, legal services, financial advisory services and management services.  The Company utilizes accounting practices for these transactions that are consistent with similar transactions with unrelated third parties.  Refer to Note 19 of the consolidated financial statements for a summary of the Company’s related party transactions.

 

Note 3.  New Accounting Pronouncements

 

Accounting Pronouncements Adopted During the Fiscal Year Ended June 30, 2009

 

In September 2006, the Financial Accounting Standard Board (“FASB”) issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (“SFAS No. 157”).  SFAS No. 157 defines fair value, establishes a framework for measuring fair value, and requires additional disclosures regarding fair value measurements.  In addition, SFAS No. 157 requires that entities consider their own credit risk when measuring the fair value of liabilities including, but not limited to, liabilities related to derivative contracts.  The Company adopted the provisions of SFAS No. 157, effective July 1, 2008.  The adoption of SFAS No. 157 did not have a material impact on the Company’s financial position or results of operations.  Refer to Note 14 for fair value disclosures required under SFAS No. 157.

 

In February 2008, the FASB issued Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS No. 159”), which permits, but does not require, entities to elect fair value measurement for both the initial and subsequent measurements of certain financial assets and liabilities that were not previously measured at fair value, generally on an instrument-by-instrument basis.  Changes in fair value subsequent to initial

 

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measurement are to be recognized in earnings during the periods when those changes occur.  SFAS No. 159 also requires additional disclosures to compensate for the lack of comparability that will arise from the election of the fair value option for those financial instruments.  The Company did not adopt the provisions of SFAS No. 159 for any financial assets or liabilities as of the effective date of July 1, 2008.

 

In September 2008, the FASB ratified the consensus on Emerging Issues Task Force Issue No. 08-5, “Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement” (“EITF No. 08-5”).  EITF No. 08-5 requires that the measurement of liabilities with inseparable, third-party credit enhancements carried or disclosed at fair value on a recurring basis exclude the effect of the credit enhancement.  EITF No. 08-5 also requires debtors to consider their own credit standing, and not that of the third-party guarantor, in measuring the fair value of a liability with a third-party guarantee.  EITF No. 08-5 is effective on a prospective basis for the first reporting period on or after December 15, 2008, with earlier application permitted.  The Company adopted the provisions of EITF No. 08-5 effective January 1, 2009.  Adoption of EITF No. 08-5 did not have any impact on the Company’s financial position or results of operations.

 

In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161, “Disclosures about Derivative Instruments and Hedging Activities” (“SFAS No. 161”).  SFAS No. 161 requires companies with derivative instruments to disclose information that would enable readers of financial statements to understand: (1) how and why a company uses derivative instruments; (2) how derivative instruments and related hedged items are accounted for under U.S. GAAP; and (3) how derivative instruments and related hedged items affect a company’s financial position, financial performance and cash flows.  SFAS No. 161 must be applied prospectively for fiscal years and interim periods beginning after November 15, 2008.  The Company adopted the provisions of SFAS No. 161 effective January 1, 2009.  Refer to Note 13 for disclosures required under SFAS No. 161.

 

In April 2009, the FASB issued FASB Staff Position No. FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (“FSP No. 157-4”).  FSP No. 157-4 provides additional guidance for estimating fair value in accordance with SFAS No. 157 when the volume and level of activity for the asset or liability have significantly decreased.  It also provides guidance on identifying circumstances that indicate a transaction is not orderly.  FSP No. 157-4 is effective for interim and annual reporting periods ending after June 15, 2009.  The Company adopted the provisions of FSP No. 157-4 effective for its fiscal quarter ending June 30, 2009.  The adoption of FSP No. 157-4 did not have any impact on the Company’s financial position or results of operations.

 

In May 2008, the FASB issued Statement of Financial Accounting Standards No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS No. 162”).  SFAS No. 162 identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements that are presented in conformity with U.S. GAAP.  SFAS No. 162 was adopted by the Company effective January 1, 2009.  The adoption of SFAS No. 162 did not have any impact on the Company’s financial position or results of operations.

 

In May 2009, FASB issued Statement of Financial Accounting Standards No. 165, “Subsequent Events” (“SFAS No. 165”).  SFAS No. 165 establishes principles and requirements for subsequent events, including: (1) the period after the balance sheet date during which management of a reporting entity shall evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; (2) the circumstances under which an entity shall recognize events or transactions occurring after the balance sheet date in its financial statements; and (3) the disclosures that an entity shall make about events or transactions that occurred after the balance sheet date.  SFAS No. 165 is effective for interim or annual financial periods ending after June 15, 2009.  The Company adopted the provisions of SFAS No 165 effective with its financial statements prepared for the fiscal year ended June 30, 2009.  The adoption of SFAS No. 165 did not have any impact on the Company’s financial position or results of operations.  Refer to Note 4 for disclosures related to subsequent events.

 

Accounting Pronouncements Not Yet Adopted as of June 30, 2009

 

In March 2008, the FASB issued Statement of Financial Accounting Standards No. 141(R), “Business Combinations” (“SFAS No. 141(R)”).  SFAS No. 141(R) establishes principles and requirements for an acquiring company to recognize and measure in its financial statements the identifiable assets acquired, liabilities assumed, goodwill acquired, any gain from a bargain purchase, and any noncontrolling interest in an acquired company.  In addition, SFAS No. 141(R) provides guidance for disclosures relating to business combinations.  SFAS No. 141(R) applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008.  The Company intends to adopt the provisions of SFAS No. 141(R) for acquisitions occurring on or after July 1, 2009.  The Company is currently evaluating the provisions of SFAS No. 141(R) to determine their likely impact on the accounting and reporting for future acquisitions, if any.

 

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Also in March 2008, the FASB issued Statement of Financial Accounting Standards No. 160, “Noncontrolling Interests in Consolidated Financial Statements — An Amendment of ARB No. 51” (“SFAS No. 160”).  SFAS No. 160 establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, for changes in a parent’s ownership interest while the parent retains its controlling financial interest in a subsidiary, and for any retained noncontrolling equity investment by a parent when a subsidiary is deconsolidated.  SFAS No. 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008.  The Company intends to adopt the provisions of SFAS No. 160 for acquisitions occurring on or after July 1, 2009.  The Company is currently evaluating the provisions of SFAS No. 160 to determine their likely impact on the accounting and reporting for future acquisitions, if any.

 

In April 2009, the FASB issued FASB Staff Position No. FAS 141(R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies” (“FSP No. FAS 141(R)-1”).  FSP No. FAS 141(R)-1 amends and clarifies SFAS No. 141(R) to address application issues relating to accounting and disclosures for assets and liabilities arising from contingencies in a business combination.  FSP No. FAS 141(R)-1 applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008.  The Company intends to adopt the provisions of FSP No. FAS 141(R)-1 for acquisitions occurring on or after July 1, 2009.  The Company is currently evaluating the provisions of FSP No. FAS 141(R)-1 for their likely impact on the accounting and reporting for future acquisitions, if any.

 

In April 2009, the FASB issued FASB Staff Position No. FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (“FSP FAS 107-1 and APB 28-1”).  FSP FAS 107-1 and APB 28-1 amends FASB Statement No. 107, “Disclosures about Fair Value of Financial Instruments,” to require disclosures about financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements.  It also amends APB Opinion No. 28, “Interim Financial Reporting,” to require those disclosures in summarized financial information at interim reporting periods.  FSP FAS 107-1 and APB 28-1 is effective for interim reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009.  The Company intends to adopt the provisions of FSP FAS 107-1 and APB 28-1 effective with its reporting period ending September 30, 2009, which represents the first interim reporting period of its 2010 fiscal year.

 

In June 2009, the FASB issued Statement of Financial Accounting Standards No. 168, “The FASB Accounting Standards CodificationTM and the Hierarchy of Generally Accepted Accounting Principles” (“SFAS No. 168”).  SFAS No. 168 identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles in the United States.  SFAS No 168 replaces SFAS No. 162.   SFAS No. 168 is effective for financial statements issued for interim and annual periods ending after September 15, 2009.  The Company intends to adopt the provisions of SFAS No. 168 effective July 1, 2009.  The adoption of SFAS No. 168 is not expected to have any impact on the Company’s financial position or results of operations.

 

Note 4.  Subsequent Events

 

The Company has evaluated subsequent events through October 13, 2009, which is the date that these consolidated financial statements were issued.  Other than the consummation of the Restructuring described below, there were no material events or transactions during the period July 1, 2009 through October 13, 2009 that required recognition or disclosure in these consolidated financial statements.

 

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 natural gas inventory component of the available borrowing base under the Company’s revolving credit facility with a syndicate of banks (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 governs the Revolving Credit Facility, prompted downgrades in the Company’s credit ratings from Standard & Poor’s and Moody’s and ultimately resulted in the Company seeking and obtaining material waivers of debt covenants and defaults and amendments to the agreement that governs the Revolving Credit Facility and the Company’s principal commodity hedge facility (the “Hedge Facility”). Such amendments had the following material direct impacts on the Company’s liquidity position:

 

·      The maturity dates of the Revolving Credit Facility and Hedge Facility were extended to September 2009.

·      The maximum amount that could be borrowed under the Revolving Credit Facility was reduced from $280.0 million at June 30, 2008 to $115.0 million at June 30, 2009, and $94.0 million effective July 31, 2009.

 

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·      The Company was required to actively seek a new facility to replace the Revolving Credit Facility and Hedge Facility.

·      Through June 30, 2009 the Company paid approximately $8.7 million of fees related to all amendments and extensions, which were deferred on the consolidated balance sheet and are being amortized as an increase to interest expense over the remaining terms of the Revolving Credit Facility and Hedge Facility.  During fiscal year 2009, the Company recorded approximately $7.5 million of incremental interest expense resulting from amortization of these deferred costs.

 

The Company explored a number of potential liquidity events, including the potential sale of its business.  Given the currently negative conditions in the economy generally and the credit markets in particular, there was substantial uncertainty that the Company would be able to effect a refinancing of the Revolving Credit Facility without a material restructuring of its debt and equity position.

 

On September 22, 2009, the Company consummated an equity and debt restructuring (the “Restructuring”), which was intended to reduce its debt exposure and interest expense, improve its liquidity and improve its financial and operational flexibility in order to allow it to compete more effectively.  The Restructuring included, among other things, the transactions described below.

 

Amendment and Restatement of Corporate Documents

 

On the consummation date of the of the Restructuring, the Company’s Certificate of Incorporation and Bylaws were amended and restated, and the Company entered into new stockholder agreements with holders of various classes of newly authorized common stock.  These documents contain customary provisions, including provisions relating to certain approval rights, preemptive rights, share transfer restrictions, rights of first refusal, tag-along rights and drag-along rights.

 

Additionally, the amended and restated Certificate of Incorporation authorized issuance of 200,000,000 shares of Common Stock, consisting of 50,000,000 shares of Class A Common Stock, 10,000,000 shares of Class B Common Stock, 40,000,000 shares of Class C Common Stock and 100,000,000 shares of Class D Common Stock.  Prior to the consummation of the Restructuring, the Company had 4,681,219 shares of common stock issued and outstanding.  Those shares of common stock were exchanged for 4,499,588 shares of newly authorized Class C Common Stock, which represented 8.29% of the aggregate shares of common stock outstanding as of the consummation date of the Restructuring.  Additional shares of Class A Common Stock, Class B Common Stock and Class C Common Stock were issued to various parties as a result of the Restructuring, as described below.

 

As a result of amendments and restatements to the Company’s corporate documents, effective September 22, 2009, the Company’s authorized board of directors increased to nine members from eight members prior to the consummation of Restructuring.  The initial composition of the new board of directors (the “Board of Directors”) is described below

 

·      Holders of the Class A Common Stock are entitled to nominate and elect five directors (the “Class A Directors”), at least two of whom shall be independent and qualify as a “financial expert”.

·      The holders of Class B Common Stock is entitled to nominate and elect one director (the “Class B Director”).

·      Holders of Class C Common Stock are entitled to nominate and elect two directors (the “Class C Directors”).

·      The ninth Director is Holdings’ president and chief executive officer.

 

Exchange of Floating Rate Notes due 2011 for Cash, Fixed Rate Notes due 2014 and Class A Common Stock

 

As of June 30, 2009, the Company had $165.2 million aggregate principal amount of Floating Rate Notes due 2011 outstanding (the “Floating Rate Notes due 2011”).  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.  The shares of Class A Common Stock issued to the holders of the Fixed Rate Notes due 2014 represented 62.5% of the aggregate shares of common stock outstanding as of the consummation date.  The Fixed Rate Notes due 2014 were issued at a discount, which will be recorded as a reduction from the Fixed Rate Notes due 2014 on the Company’s consolidated balance sheets during the first quarter of fiscal year 2009, and which will be amortized as an increase to interest expense over the remaining life of the Fixed Rate Notes due 2014.

 

Refer to Note 16 for additional information regarding the Floating Rate Notes due 2011 and Fixed Rate Notes due 2014.

 

New Master Credit, Hedge and Supply Agreement

 

As of June 30, 2009, the Company relied on the following credit, commodity hedging and commodity supply arrangements

 

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for operation of its 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 the Company serves;

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

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

·      Arrangements with numerous commodity suppliers to supply natural gas and electricity necessary for customer consumption in the markets that the Company serves.

 

Effective September 22, 2009 the Revolving Credit Facility and Hedge Facility were replaced by a new exclusive credit, supply and commodity hedging agreement (the “Commodity Supply Facility”) with Sempra Energy Trading LLC (“RBS Sempra”), which effectively replaced the separate credit, hedging and supply arrangements outlined above.  As a condition for entry into the agreements governing the Commodity Supply Facility, the Company also issued 4,002,290 shares of newly authorized Class B Common Stock to RBS Sempra, which represented 7.37% of the Company’s aggregate shares of common stock outstanding on the consummation date of the Restructuring.  The aggregate fair value of the common stock issued to RBS Sempra was recorded as deferred financing costs in other assets on the consolidated balance sheets and will be amortized over the remaining term of the Commodity Supply Facility.

 

Refer to Note 15 for additional information regarding the Commodity Supply Facility.

 

Conversion of Redeemable Convertible Preferred Stock to Class C Common Stock

 

As of June 30, 2009, the Company had 1,451,310 shares of Preferred Stock outstanding, which was recorded at its estimated redemption value of $54.6 million on the consolidated balance sheets.  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 shares of the Company’s common stock outstanding after consummation of the Restructuring.  The excess of the redemption value over the aggregate fair value of common stock issued to the holders of Preferred Stock was reclassified to stockholders’ equity on the consolidated balance sheets during the first quarter of fiscal year 2010.

 

Refer to Note 17 for additional information regarding the Company’s redeemable convertible preferred stock.

 

Termination of the Credit Agreement with Denham Commodity Partners LP (“Denham”)

 

As of June 30, 2009, the Company had a $12.0 million outstanding balance under a credit agreement with Denham Commodity Partners LP (the “Denham Credit Facility”).  On September 22, 2009, all amounts previously borrowed were repaid and the Denham Credit Facility was terminated.

 

Refer to Note 19 for additional information regarding the Denham Credit Facility.

 

New Management Incentive Plan and Bonuses

 

In connection with the Restructuring, it is anticipated that the Company’s board of directors will authorize the creation of a new management incentive plan (the “Management Incentive Plan”), pursuant to which they may issue Class C Common Stock not to exceed 10% of the Company’s aggregate outstanding common stock (on a fully diluted basis) after giving effect to the Restructuring.  The Company expects that the Management Incentive Plan will provide the board of directors the flexibility to make awards to employees, officers, directors, consultants and advisors and will permit, among other things, the grant of options to purchase shares of common stock that are intended to qualify as incentive stock options under Section 422 of the Internal Revenue Code, grants of options to purchase shares of common stock that will not so qualify, grants of stock appreciation rights, and grants of common stock at incentive prices or for free.

 

In addition, the compensation committee of the board of directors approved a total bonus pool equal to $750,000, which was paid to 19 of the Company’s executive officers and employees, including the Company’s chief executive officer and chief financial officer, upon the consummation of the Restructuring.

 

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Settlement and Cancellation of Existing Options and Warrants

 

As of June 30, 2008, the Company had options and warrants outstanding which were, or may be, 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 (e.g., 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).  Pursuant to the Restructuring, the Company terminated its existing share-based compensation plans and offered a cash settlement to holders of options and warrants to cancel and terminate such options and warrants.  As a result, all outstanding options and warrants were cancelled and terminated.  The total amount required for such cash settlement payments was approximately $0.2 million, which was recorded as general and administrative expense during the first quarter of fiscal year 2010.

 

Note 5  Seasonality of Operations

 

For the fiscal year ended June 30, 2009, natural gas and electricity sales accounted for approximately 85% and 15%, respectively, of the Company’s total sales.  Weather conditions have a significant impact on customer demand for natural gas and electricity consumption.  In addition, weather can have an impact on the price of natural gas and electricity.  Customer demand exposes the Company to a high degree of seasonality in sales, cost of sales, billing and collection of customer accounts receivable, inventory requirements and cash flows.  In addition, budget billing programs and LDC payment terms can cause timing differences between the billing and collection of accounts receivable and the recording of revenues.

 

The Company utilizes a considerable amount of cash from operations to meet working capital requirements during the months of November through April of each fiscal year.  In addition, the Company utilizes cash to purchase natural gas inventories during the months of April through October.  The majority of natural gas customer consumption and gross profit occurs during the months of November through March with collections on accounts receivable peaking in the spring.  By contrast, electricity customer consumption and gross profit peaks during the summer months of June through September with collections on accounts receivable peaking in late summer and early fall.

 

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, operating results for a full fiscal year may not be materially impacted by such trends due to the Company’s economic hedging and contract pricing strategies,.  Therefore, the short-term impacts of changing commodity prices should be considered in the context of the Company’s entire annual operating cycle.

 

Note 6.  Accounts Receivable, Net

 

Accounts receivable, net is summarized in the following table.

 

 

 

Balances at June 30,

 

 

 

2009

 

2008

 

 

 

(in thousands)

 

Billed customer accounts receivable:

 

 

 

 

 

Guaranteed by LDCs

 

$

7,768

 

$

17,085

 

Non-guaranteed by LDCs

 

26,679

 

32,966

 

 

 

34,447

 

50,051

 

Unbilled customer accounts receivable (1):

 

 

 

 

 

Guaranteed by LDCs

 

5,737

 

9,803

 

Non-guaranteed by LDCs

 

10,547

 

19,905

 

 

 

16,284

 

29,708

 

Total customer accounts receivable

 

50,731

 

79,759

 

Less: Allowance for doubtful accounts

 

(7,344

)

(5,154

)

Customer accounts receivable, net

 

43,387

 

74,605

 

Cash imbalance settlements and other receivables, net(2)

 

4,211

 

13,068

 

Accounts receivable, net

 

$

47,598

 

$

87,673

 

 


(1)

 

Unbilled customer accounts receivable represents estimated revenues associated with natural gas and electricity consumed by customers but not yet billed under the LDC’s monthly cycle billing method.

 

 

 

(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 39 market 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

 

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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 each of the fiscal years ended June 30, 2009, 2008 and 2007.

 

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 June 30, 2009, and for the fiscal year then ended, 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.

 

 

 

Fiscal Year Ended June 30,

 

 

 

2009

 

2008

 

2007

 

 

 

(in thousands)

 

 

 

 

 

 

 

 

 

Balance at beginning of period

 

$

5,154

 

$

5,259

 

$

3,285

 

Add: Provision for doubtful accounts

 

12,009

 

5,050

 

3,018

 

Less: Net charge offs of customer accounts receivable

 

(9,819

)

(5,155

)

(1,044

)

Balance at end of period

 

$

7,344

 

$

5,154

 

$

5,259

 

 

 

 

 

 

 

 

 

Provision for doubtful accounts as a percentage of sales of natural gas and electricity in non-guaranteed markets

 

2.79

%

1.19

%

0.82

%

 

Reserves and discounts in the consolidated statements of operations includes 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.  For the fiscal year ended June 30, 2009, approximately 55% of the Company’s total sales of natural gas and electricity were within markets where LDCs do not guarantee customer accounts receivable while 45% 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 cases where customer accounts receivable are guaranteed by the LDC, the Company is exposed to the credit risk of the LDC, rather than 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 June 30, 2009, all of the Company’s customer accounts receivable in LDC-guaranteed markets were with LDCs with investment grade credit ratings.

 

The higher provision for doubtful accounts for fiscal year 2009, as compared with the prior fiscal year, primarily relates to the Company’s largest non-guaranteed natural gas market in Georgia and its non-guaranteed electricity market in Texas.  Total sales of natural gas and electricity for these markets increased a combined 7% during the fiscal year 2009.  In addition, the Company experienced deterioration of the aging of billed customer accounts receivable within these and other markets during fiscal year 2009.  As expected, charge offs of customer accounts receivable related to the customer accounts acquired in the Company’s acquisition of Catalyst Natural Gas, LLC were also experienced during the final six months of fiscal year 2009.  The Company will continue to closely monitor economic conditions and actual collections data within these and other markets for signs of any negative long-term trends which could result in higher allowance requirements.

 

Note 7.  Natural Gas Inventories

 

Natural gas inventories are summarized in the following table.

 

 

 

Balances at June 30,

 

 

 

2009

 

2008

 

 

 

(in thousands)

 

 

 

 

 

Storage inventory for delivery to customers

 

$

24,457

 

$

52,807

 

Imbalance settlements in-kind (1)

 

4,958

 

12,195

 

Other

 

 

4

 

Total

 

$

29,415

 

$

65,006

 

 


(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.

 

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After reaching record highs during the three months ended June 30, 2008, natural gas market prices dropped sharply during fiscal year 2009, which resulted in a 60% decrease in the Company’s weighted-average average cost per MMBtu of natural gas included in natural gas storage inventory from June 30, 2008 to June 30, 2009.  The resulting decrease in natural gas inventories was partially offset by a 14% increase in MMBtus held in storage over the same period.

 

Adjustments to the value of natural gas inventories on the consolidated balance sheets result in corresponding adjustments to cost of goods sold on the consolidated statements of operations.  Such adjustments result from changes in inventory storage levels as natural gas is delivered to customers as well as changes in the weighted average cost of natural gas in storage.

 

Note 8.  Goodwill

 

All of the Company’s goodwill, which resulted from its acquisition of Shell Energy Services Company L.L.C. (“SESCo”) in August 2006, is assigned to the natural gas business segment.  The Company completed its annual impairment test of goodwill as of June 30, 2009.  At the testing date, the Company determined that the fair value of the natural gas reporting unit exceeded its carrying value.  As a result, no impairment loss was required to be recognized.  Since the testing date, there were no material events, transactions or changes in circumstances which warranted consideration for their impact on the recorded carrying value assigned to goodwill.

 

Note 9.  Customer Acquisition Costs, Net

 

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

 

 

 

Balance at June 30, 2009

 

 

 

Gross
Book Value

 

Accumulated
Amortization

 

Net Book Value

 

 

 

(in thousands)

 

 

 

 

 

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

 

 

 

 

Balance at June 30, 2008

 

 

 

Gross
Book Value

 

Accumulated
Amortization

 

Net Book Value

 

 

 

(in thousands)

 

 

 

 

 

Customer contracts acquired

 

$

47,515

 

$

26,395

 

$

21,120

 

Direct sales and advertising costs

 

32,287

 

11,714

 

20,573

 

Total customer acquisition costs

 

$

79,802

 

$

38,109

 

$

41,693

 

 

Amortization expense relating to capitalized customer acquisition costs was approximately $29.8 million, $23.4 million and $19.5 million for the fiscal years ended June 30, 2009, 2008 and 2007, respectively.  Amortization expense associated with customer acquisition costs capitalized as of June 30, 2009 is expected to approximate $16.7 million, $9.3 million and $1.9 million for the fiscal years ending June 30, 2010, 2011 and 2012, respectively.

 

The value and recoverability of customer acquisition costs are evaluated quarterly by comparing their carrying value to their projected future cash flows on an undiscounted basis.  During the fiscal year ended June 30, 2009, no impairment was indicated as a result of these comparisons, and there were no material events or transactions which warranted consideration for their impact on the recorded book value assigned to customer acquisition costs.

 

As of June 30, 2009, the weighted-average remaining amortization period for customer acquisition costs is approximately 1.47 years.

 

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Note 10.  Fixed Assets, Net

 

Fixed assets, net are summarized in the following table.

 

 

 

 

 

 

 

Estimated

 

 

 

Balance at June 30,

 

Useful

 

Fixed Asset Category

 

2009

 

2008

 

Lives

 

 

 

(in thousands)

 

 

 

 

 

 

 

Computer equipment

 

$

6,080

 

$

5,126

 

3 years

 

Computer software and development

 

25,607

 

25,583

 

3-5 years

 

Office furniture and equipment

 

1,502

 

1,479

 

3-5 years

 

 

 

33,189

 

32,188

 

 

 

Less: accumulated depreciation and amortization

 

(29,461

)

(21,663

)

 

 

Net

 

$

3,728

 

$

10,525

 

 

 

 

During each of the fiscal years ended June 30, 2009 and 2008, the Company capitalized approximately $1.0 million of software development costs related to a project designed to reduce the number of software systems utilized to service customer accounts and to enhance the overall capabilities of existing software.  Amortization expense relating to capitalized computer software costs was approximately $6.4 million, $7.7 million and $6.4 million for the fiscal years ended June 30, 2009, 2008 and 2007, respectively.

 

Depreciation expense relating to computer equipment, office furniture and other equipment was approximately $1.4 million, $1.6 million and $1.7 million for the fiscal years ended June 30, 2009, 2008 and 2007, respectively.

 

Note 11.  Income Taxes

 

Income tax benefit (expense) is summarized in the following table:

 

 

 

Fiscal Years ended June 30

 

 

 

2009

 

2008

 

2007

 

 

 

(in thousands)

 

Current:

 

 

 

 

 

 

 

Federal

 

$

4,666

 

$

599

 

$

(4,750

)

State

 

(823

)

434

 

(1,204

)

 

 

3,843

 

1,033

 

(5,954

)

Deferred:

 

 

 

 

 

 

 

Federal

 

18,892

 

(15,000

)

13,249

 

State

 

4,514

 

(3,188

)

1,200

 

 

 

23,406

 

(18,188

)

14,449

 

Total income tax benefit (expense)

 

$

27,249

 

$

(17,155

)

$

8,495

 

 

As of June 30, 2009, the Company has net operating loss carryforwards of approximately $2.0 million and $0.7 million related to its U.S. and Canadian operations, respectively.  The net operating loss carryforwards related to U.S. operations will expire in fiscal year 2029.  The net operating loss carryforwards related to Canadian operations will expire during fiscal years 2014 through 2029.

 

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

 

 

 

2009

 

2008

 

2007

 

 

 

 

 

 

 

 

 

Federal statutory rate

 

35.0

%

35.0

%

35.0

%

State statutory rate, net of federal benefit

 

3.9

 

4.5

 

5.4

 

Total statutory rate

 

38.9

 

39.5

 

40.4

 

Impact of prior year adjustments on current and deferred income taxes

 

 

(0.6

)

 

Impact of changing tax rates on prior year deferred balances

 

 

1.0

 

(0.1

)

Impact of permanent differences

 

(0.2

)

1.0

 

(2.2

)

Impact of recording valuation allowance

 

(17.3

)

 

 

Effective tax rate

 

21.4

%

40.9

%

38.1

%

 

The effective tax rate applied to income tax benefits for fiscal years 2009 and 2007 and income tax expense for fiscal year 2008.  The lower effective tax rate for fiscal year 2009 was primarily due to recognition of a valuation allowance for deferred income tax assets at June 30, 2009.  The state statutory tax rate decreased to 3.9% for the fiscal year ended June 30, 2009 as a result of income apportionment for the states in which the Company does business.

 

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

 

Taxing Jurisdiction

 

Open Years

 

 

 

 

 

U.S. Federal

 

2005 and later

 

U.S. states and cities

 

2005 and later

 

Canada

 

2005 and later

 

 

The significant components of the Company’s deferred tax assets and liabilities are summarized in the following table.

 

 

 

Balance at June 30,

 

 

 

2009

 

2008

 

 

 

(in thousands)

 

Deferred tax assets:

 

 

 

 

 

Depreciation and amortization

 

$

18,982

 

$

12,877

 

Net unrealized losses from risk management activities

 

18,693

 

 

Allowance for doubtful accounts

 

2,860

 

2,035

 

Tax loss carryforwards

 

2,724

 

 

Accrued bonuses

 

1,707

 

1,090

 

Stock compensation expense

 

1,642

 

1,664

 

Other reserves

 

165

 

122

 

Valuation allowance

 

(22,664

)

 

Total deferred tax assets

 

24,109

 

17,788

 

Deferred tax liabilities:

 

 

 

 

 

Net unrealized gains from risk management activities

 

 

(17,085

)

Total deferred tax liabilities

 

 

(17,085

)

Net deferred tax asset

 

$

24,109

 

$

703

 

 

 

 

 

 

 

Balance sheet classification:

 

 

 

 

 

Current deferred tax asset

 

$

9,020

 

$

 

Long-term deferred tax asset

 

15,089

 

10,503

 

Current deferred tax liability

 

 

(9,800

)

Net deferred tax asset

 

$

24,109

 

$

703

 

 

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.  At June 30, 2009, the Company determined that it was “more likely than not” that a portion of its deferred tax assets would not be realized.

 

The Company has deferred tax assets related to unrealized losses from risk management activities.  The Company anticipates that these deferred tax assets will be realized in future periods when sales of fixed price commodities, to which the unrealized losses from risk management activities relate, occur.  Therefore, the Company did not establish a valuation allowance for these deferred tax assets.

 

For the remaining deferred tax assets reflected in the table above, the Company determined based on available evidence, including historical financial results for the last 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 of approximately $22.0 million and $0.7 million related to its U.S. and Canadian operations, respectively, as a reduction of tax benefit recorded for fiscal year 2009.

 

Activity related to uncertain tax positions for the fiscal year ended June 30, 2009 is summarized in the following table.

 

 

 

Amount

 

 

 

(in millions)

 

 

 

 

 

Unrecognized tax benefit at July 1, 2008

 

$

0.9

 

Decreases from payments during the fiscal year

 

 

Unrecognized tax benefit at June 30, 2009

 

$

0.9

 

 

At June 30, 2009, the Company had an uncertain tax position of $0.9 million for a timing issue related to compensation expense.  There was no change to this amount during the fiscal year ended June 30, 2009, and the Company does not expect this item to be settled within the next twelve months.  There is no change in the effective tax rate as a result of this item.

 

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The Company recognizes accrued interest and penalties related to income tax liabilities in accrued liabilities in the consolidated balance sheet and interest expense in the consolidated statement of operations.  As of June 30, 2009, the Company had accrued approximately $0.2 million for potential interest and penalties for the compensation-related timing issue described above.  There was no material change in this amount during the fiscal year ended June 30, 2009.

 

Note 12.  Accounts Payable and Accrued Liabilities

 

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

 

 

 

Balance at June 30,

 

 

 

2009

 

2008

 

 

 

(in thousands)

 

 

 

 

 

Interest payable (1)

 

$

8,946

 

$

11,662

 

Trade accounts payable and accrued liabilities (2)

 

13,952

 

14,427

 

Accrued payroll and related liabilities

 

4,761

 

3,824

 

Sales and other taxes

 

2,193

 

1,291

 

Customer contracts acquired in business combinations

 

47

 

699

 

Other

 

3,401

 

4,699

 

Total accounts payable and accrued liabilities

 

$

33,300

 

$

36,602

 

 


(1)

 

Includes $1.0 million of accrued interest at June 30, 2009 related to bridge loans from Charter Mx LLC, Denham and certain members of the Company’s senior management team. Refer to Note 19 for additional information regarding related party transactions.

(2)

 

Includes $1.9 million and $0.3 million due to related parties at June 30, 2009 and 2008, respectively, for legal services, financial advisory services and management fees. Refer to Note 19 for additional information regarding related party transactions.

 

Interest payable relates primarily to accrued interest on the Floating Rate Notes due 2011.  Trade accounts payable and accrued expenses relate primarily to transportation and distribution charges, imbalances and other utility-related expenses.

 

Note 13.  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 rate associated with its Floating Rate Notes due 2011.  The Company’s risk management policy defines various risk management controls and limits designed to monitor the Company’s 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 has elected not to designate any of the derivative instruments as accounting hedges under U.S. GAAP.  Accordingly, all changes in the fair value of outstanding commodity derivative contracts are adjusted directly through unrealized gains or losses from risk management activities, net on the consolidated statements of operations, while changes in the fair value of outstanding interest rate derivative contracts are adjusted directly through interest expense, net.  Unrealized gains and losses on the consolidated balance sheets reflect the current market values for all of the Company’s derivative instruments.

 

Outstanding derivative instruments, which extend through December 2011, are summarized in the following table.

 

 

 

Open Contracts
As of
June 30, 2009

 

Natural gas (primarily under the Hedge Facility):

 

 

 

NYMEX referenced over the counter swaps (MMBtus(1))

 

10,158,000

 

Basis swaps (MMBtus)

 

11,712,000

 

Options (MMBtus)

 

1,015,000

 

 

 

 

 

Electricity:

 

 

 

Swaps and fixed price contracts (MWhrs) (2)

 

168,000

 

 


(1)  Million British thermal units

(2)  Million watt hours

 

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The fair values of derivative instruments recorded on the Company’s consolidated balance sheets are summarized in the following table.

 

 

 

 

 

Fair Value as of June 30, 2009

 

Type of Derivative

 

Location on the Consolidated Balance Sheet

 

Prior to
Netting

 

Impact of
Master
Netting
Agreements

 

After Netting

 

 

 

 

 

(in thousands)

 

 

 

 

 

 

 

Asset derivatives:

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

Unrealized gains from risk management activities

 

$

24,649

 

(24,355

)

294

 

Interest rate derivatives

 

Unrealized gains from risk management activities

 

 

 

 

Total

 

 

 

$

24,649

 

$

(24,355

)

$

294

 

 

 

 

 

 

 

 

 

 

 

Liability Derivatives:

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

Unrealized gains from risk management activities

 

$

64,347

 

(24,355

)

$

39,992

 

Interest rate derivatives

 

Unrealized gains from risk management activities

 

8,303

 

 

8,303

 

Total

 

 

 

$

72,650

 

$

(24,355

)

$

48,295

 

 

The effect of derivative instruments on the Company’s consolidated statements of operations for the fiscal year ended June 30, 2009 is summarized in the following table.

 

 

 

Location of (Gains) Losses Recognized on the
Consolidated Statement of Operations

 

Amount of
(Gains)
Losses
Recognized

 

 

 

 

 

(in thousands)

 

Fiscal year ended June 30, 2009:

 

 

 

 

 

Commodity derivatives

 

Cost of goods sold – realized losses (gains) from risk management activities, net

 

$

72,824

 

Commodity derivatives

 

Cost of goods sold – unrealized losses (gains) from risk management activities, net

 

87,575

 

Interest rate derivatives

 

Interest expense, net of interest income

 

3,693

 

Total

 

 

 

$

164,092

 

 

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).

 

Natural Gas Hedging Activities

 

Although the Company engages in economic hedging activities with various counterparties for electricity, it utilizes one particular hedge facility to economically hedge the variability in the cost of natural gas.  The Hedge Facility, which was governed by a master transaction agreement (the “Master Transaction Agreement”), had an initial term of two years with subsequent one-year renewal terms.

 

The Hedge Facility was replaced by the Commodity Supply Facility effective September 22, 2009 (refer to Note 15).

 

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

 

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 and dates associated with a Liquidity Event.

 

Other material amendments to the Hedge Facility during fiscal year 2009 included:

 

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·      The maturity date of the Hedge Facility was extended to September 21, 2009 from December 19, 2008.

·      Effective May 29, 2009, counterparties for any new natural gas transactions required the approval of the hedge provider at its sole discretion.

·      Effective May 29, 2009, the limitation on the maximum total outstanding hedging positions was reduced from a maximum of 25.0 million MMBtus in the original agreement that governs the Hedge Facility to 12.0 million MMBtus effective May 29, 2009, to 11.0 million MMBtus effective July 31, 2009, and to 10.0 million MMBtus effective August 31, 2009.

 

The Hedge Facility was secured by a first lien on customer contracts and a second lien on substantially all other assets of the Company, primarily unrestricted cash, customer accounts receivable and natural gas inventory.  Collateral available to satisfy the second lien represents the sum of: (1) the excess of calculated net asset values over calculated availability under the Revolving Credit Facility; plus (2) the carrying value of customer acquisition costs.   At June 30, 2009, total collateral available to satisfy natural gas derivative liabilities was approximately $43.7 million, which exceeded such liabilities by approximately $7.8 million.

 

As of June 30, 2008, the Company was required to post a $25.0 million letter of credit as collateral for any potential negative mark-to-market changes in the value of its forward hedge position.  As a result of the amendment to the Master Transaction Agreement that was finalized in July 2008, the Company was required to increase the collateral required to be posted as margin to $35.0 million in the event that the negative mark-to-market value of its forward hedge position exceeds $25.0 million.  The Company has the flexibility to post either cash collateral or issue a letter of credit as margin for the Hedge Facility.  As of June 30, 2009, the Company had increased the letter of credit posted as collateral to $35.0 million because its mark-to-market exposure under the Hedge Facility exceeded $25.0 million.

 

As of June 30, 2009, all of the Company’s natural gas economic hedge positions were with a counterparty that has an investment grade credit rating.

 

Electricity Hedging Activities

 

The Company utilizes swaps and fixed price contracts with various counterparties to economically hedge the variability in the cost of electricity.  As of June 30, 2009, the Company did not have an exclusive agreement with any single hedge provider for electricity.  The Company manages its exposure to risk associated with any single electricity hedge provider through a formal credit risk management process and through daily review of exposures from open positions.  As of June 30, 2009, all of the Company’s electricity hedge positions were with counterparties with investment grade credit ratings.

 

The Company is generally required to post letters of credit to cover its liability positions with various counterparties in accordance with electricity hedging agreements.  Such counterparties periodically review their exposure with us and adjust the required amounts of letters of credit as necessary.

 

The Commodity Supply Facility requires the Company to novate or unwind certain electricity swaps subsequent to closing of the Commodity Supply Facility, with RBS Sempra providing any necessary credit support to liquidate those positions.

 

Interest Rate Risk Management Activities

 

Effective August 4, 2006, the Company became exposed to fluctuations in interest rates under the Floating Rate Notes due 2011.  As of June 30, 2009, $165.2 million aggregate principal of the Floating Rate Notes due 2011 was outstanding, before original issue discount.  We entered into interest rate swap agreements during fiscal 2007, which are utilized to manage our exposure to interest rate fluctuations on the Floating Rate Notes due 2011.  These agreements effectively convert interest rate exposure from a variable rate to a fixed rate of interest.  As of June 30, 2009, the following interest rate swaps were outstanding:

 

·      A $30.0 million swap that expires on August 2, 2010 and bears interest at 10.33% per annum; and

·      An $80.0 million swap that expires on August 1, 2011 that bears interest at 13.24% per annum.

 

The $30.0 million swap that was due to expire on August 2, 2010 was terminated in September 2009.  A $50.0 million swap expired on August 1, 2008 and was not replaced.

 

All swaps are fixed-for-floating and settle against the six-month LIBOR rate.  None of the interest rate swaps have been designated as a hedge and, accordingly, changes in the market value of the interest rate swaps are charged directly to interest expense.  The additional interest expense associated with changes in the market value of interest rate swaps was $3.7 million, $3.3 million and $0.9 million for the fiscal years ended June 30, 2009, 2008 and 2007, respectively.

 

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As of June 30, 2009, the Company was not specifically required to provide any collateral or letters of credit in support of its interest rate derivative liabilities.  However, coverage for interest rate derivative liabilities is included in the calculation of borrowing availability under the Revolving Credit Facility.

 

The Commodity Supply Facility requires the Company to novate or unwind the remaining $80.0 million swap subsequent to closing of the Commodity Supply Facility, with RBS Sempra providing any necessary credit support to liquidate that position.

 

Credit Risk Associated with Derivative Financial Instruments

 

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

 

Note 14.  Fair Value of Financial Instruments

 

As described in Note 3 of these consolidated financial statements, in September 2006, the FASB issued SFAS No. 157, which defines fair value for financial assets and liabilities, establishes a framework for measuring fair value, and requires additional disclosures regarding fair value measurements.  SFAS No. 157 established a fair value hierarchy that prioritizes the assumptions, or “inputs,” used in applying valuation techniques.  The three levels of inputs within fair value hierarchy include:

 

·      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.   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, as defined in SFAS No. 157, 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 fair value of the Company’s financial assets and liabilities that are measured at fair value, by level within the fair value hierarchy, is summarized in the following table.

 

 

 

Balance at June 30, 2009

 

 

 

Level 1

 

Level 2

 

Level 3

 

Total

 

 

 

(in thousands)

 

Assets:

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

$

 

$

294

 

$

 

$

294

 

Interest rate derivatives

 

 

 

 

 

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 Floating Rate Notes due 2011 at fair value.  Utilizing observable market data, the fair market value of the Floating Rate Notes due 2011 was approximately $65.0 million as of June 30, 2009.

 

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Note 15.  Revolving Credit Facility and Commodity Supply Facility

 

As of June 30, 2009, and through September 21, 2009, MXenergy Inc. and MXenergy Electric Inc. were borrowers under a revolving credit facility with a syndicate of banks (the “Revolving Credit Facility”).  The maximum amount that could be borrowed under the Revolving Credit Facility was the lesser of: (1) total bank commitments under the Revolving Credit Facility; and (2) the amount of the applicable borrowing base, which represents the aggregate of specific advance rates against cash, customer accounts receivable, natural gas inventory and imbalance receivables. As of June 30, 2008, prior to the fiscal year 2009 amendments described below to the agreement that governs the Revolving Credit Facility, the expiration date of the Revolving Credit Facility was December 19, 2008, at which time any outstanding principal amounts would have become due.  Borrowings under the Revolving Credit Facility bore interest at a fluctuating rate based upon a base rate or a Eurodollar rate plus an applicable margin.  As of June 30, 2008, the applicable margin for base rate loans was 1.00% per annum and the applicable margin for Eurodollar loans was 2.00% per annum.  As of June 30, 2008, the fees associated with issuing letters of credit under the Revolving Credit Facility were 1.75% per annum.  At June 30, 2008, the total availability under the Revolving Credit Facility was $193.9 million, of which $147.9 million was utilized in the form of outstanding letters of credit.  There were no cash borrowings under the Revolving Credit Facility during the fiscal year ended June 30, 2008.

 

At June 30, 2009, the total availability under the Revolving Credit Facility was $147.8 million, of which of which the maximum the Company could utilize was $115.0 million as a result of amendments to the Revolving Credit Facility during fiscal year 2009.  As of June 30, 2009, $96.3 million of availability was utilized in the form of outstanding letters of credit.  There were no cash borrowings outstanding under the Revolving Credit Facility at June 30, 2009 other than the $5.4 million of Bridge Financing loans (as defined below).  During the fiscal year ended June 30, 2009, the Company borrowed $30.0 million of cash advances under the Revolving Credit Facility, all of which was repaid prior to June 30, 2009.  Total interest expense associated with these cash borrowings was less than $0.1 million for the fiscal year ended June 30, 2009.

 

The agreement that governed the Revolving Credit Facility, as revised for the amendments described below, contained customary covenants that restrict certain of the Company’s activities including, among others, limitation on capital expenditures, disposal of property and equipment, additional indebtedness, issuance of capital stock and dividend payments.  The agreement that governed the Revolving Credit Facility, as amended, also contained customary events of default.  The Company was in compliance with the covenants under the Amended Revolving Credit Agreement as of June 30, 2009, including the milestone events relating to a Liquidity Event.

 

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 the Company’s 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 the 2009 Amendments, the Company was required to actively seek a new facility to replace the Revolving Credit Facility and Hedge Facility.  Various milestone events and dates were established by the 2009 Amendments and were eventually met by the Company, all leading to development and consummation of the Restructuring on September 22, 2009.

 

Other material impacts of the 2009 Amendments are summarized as follows:

 

·      The maturity date of the Revolving Credit Facility was extended to September 21, 2009 from December 19, 2008.

·      The maximum amount that the Company could borrow under the Revolving Credit Facility was incrementally reduced from $280.0 million at June 30, 2008 to $115.0 million at June 30, 2009 and to $94 million from July 31, 2009 through the termination date.

·      In November 2008, the Company was required to obtain $10.4 million of additional debt financing from Denham Commodity Partners Fund LP (“Denham”) and Charter Mx LLC, both significant stockholders of the Company, and four members of the Company’s senior management team (the “Bridge Financing”; refer to Note 19).

·      The Company was required to borrow the $12.0 million available balance under the Denham Credit Facility by November 7, 2008.

·      The volume of natural gas that could be maintained in inventory was limited to maximum amounts ranging from a maximum of: (a) 4.2 million MMBtus on any date from May 15, 2009 through May 31, 2009; (b) 5.1 million MMBtus on any date during the month of June 2009; (c) 5.6 million MMBtus on any date during the month of July 2009; and 6.1 million MMBtus effective for the period July 31, 2009 through the termination date.

·      The Company’s marketing expenses were limited to $0.2 million per week effective May 15, 2009.

·      The Company was required to maintain a minimum balance of cash with the administrative agent as security for all obligations of the Revolving Credit Facility, which increased from $60.0 million effective May 15, 2009, to $65

 

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million effective May 29, 2009, and to $75.0 million effective June 15, 2009 until termination of the Revolving Credit Facility and cancellation of all letters of credit issued thereunder.

·      Effective November 17, 2008, the aggregate outstanding principal amount of cash advances under the Revolving Credit Facility was limited to $20.0 million.  Effective March 11, 2009, the Company’s ability to make cash advances under the Revolving Credit Facility was eliminated.

·      Effective September 30, 2008, any plan of the Company to acquire customer portfolios or operations of other companies required the explicit approval by lenders holding a majority of the commitments under the Revolving Credit Facility.  Effective May 15, 2009, any acquisition of customer portfolios or operations of other companies were strictly prohibited.

·      The Company was temporarily allowed to exceed the maximum amount that can be borrowed under the Revolving Credit Facility by various amounts that decreased incrementally from $35.0 million effective in November 2008 to $0 effective in March 2009.

·      From November 1, 2008 through November 17, 2008, the Company was temporarily allowed to request issuance of letters of credit of up to $25,360,000 without deducting such letters of credit from the available borrowing base.

·      Effective May 15, 2009, the aggregate amount of letters of credit that may be issued with an expiration date beyond October 31, 2009 was limited to $40.0 million.

·      The margin added to base rate loans and various letter of credit and other facility fees were increased.

·      Financial covenants related to consolidated tangible net worth, consolidated working capital, interest coverage and negative allowed consolidated earnings were each amended.

·      The Company was required to have at least $10.0 million in available borrowing base on and after April 30, 2009.

·      The Company was required to have at least $40.0 million in cash and cash equivalents at all times on and after April 30, 2009, excluding any such cash and cash equivalents acquired from the proceeds of advances under the Revolving Credit Facility.

·      The Company paid approximately $8.7 million of amendment fees, legal fees and consulting fees and other costs directly related to various amendments of the Revolving Credit Facility and the Hedge Facility during the fiscal year ended June 30, 2009, which were deferred on the consolidated balance sheet and amortized over the remaining terms of the facilities.  Incremental amortization expense associated with these deferred costs was approximately $7.5 million during fiscal year 2009.

 

As a result of 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 MXenergy Inc., MXenergy Electric Inc. and all obligations are guaranteed by Holdings and its other domestic subsidiaries.  Obligations under the Commodity Supply Facility are secured by a first priority lien on substantially all of the Holdings’ and its domestic subsidiaries’ existing and future assets 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, payment extension financing and/or storage financing as needed, and associated hedging transactions in order to maintain the Company’s required matched trading book.  In addition, the Commodity Supply Facility will provide 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 Commodity Supply Facility also will provide for RBS Sempra to act on the Company’s behalf to satisfy the requirements of regional transmission operators for capacity rights and ancillary services.

 

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.  RBS Sempra would not be obligated to enter into a transaction with any third party unless RBS Sempra is satisfied with such transaction 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, the Company will be charged an adder for such purchases.

 

The Commodity Supply Facility also provides for certain volumetric adder fees for all natural gas and electricity purchases, as well as minimum purchase requirements for both natural gas and electricity over the initial three-year term and over the optional one-year extension term.

 

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Under the hedging terms of the Commodity Supply Facility, the aggregate notional exposure amount of fixed price hedges allowed to be entered into by the Company will be limited to $260.0 million, without adjustment for mark-to-market movements thereafter.  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 volumetric tenor not to exceed 14 months in duration.  With regards to the Company’s fixed price customer mix, the Company may not, during any 12 month period, enter into any new fixed price contracts with respect to the gas business where the residential customer equivalents of such contracts are greater than 75% of all residential customer equivalents of all new contracts entered into during such period and/or maintain a customer portfolio with more than 325,000 residential customer equivalents operating under fixed price contracts.

 

The maximum amount of cash borrowings permitted under the storage and/or payment extension financing provisions of the Commodity Supply Facility will be $45.0 million.  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%, but not less than 4%; provided, however, that, if on any date of determination, no termination event has occurred with respect to Holdings and its affiliates and the cash held in certain collateral accounts exceeds all outstanding settlement payments under the Commodity Supply Facility, interest will accrue at a reduced rate of 1.0% on that portion of the credit support amount that is in excess of $27.0 million.

 

With regards to the aggregate exposure outstanding under the Commodity Supply Facility, the Company must maintain a ratio of eligible current working capital assets to outstanding supply and financing exposure (excluding any exposure related to hedging activities) greater than 1.25:1.0 during the months of October through March, and greater then 1.4:1.0 during the months of April through September; (the “Collateral Coverage Ratio”).  In addition, the Company must maintain a consolidated tangible net worth, as defined in the agreement that governs the Commodity Supply Facility of at least $60.0 million.

 

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

 

In connection with consummation of the Commodity Supply Facility, RBS Sempra was issued a number of shares of Holdings’ Class B Common Stock equal to 7.37% of the outstanding common stock on Restructuring consummation date.

 

The agreements that govern the Commodity Supply Facility 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 Commodity Supply Facility also contains 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;

 

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·      failure of any guaranty or security document supporting the New Facilities 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

·      a change of control.

 

Note 16.  Long-Term Debt

 

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 1 and August 1 of each year.

 

The interest rate on the Floating Rate Notes due 2011 was 9.13% and 10.69% at June 30, 2009 and 2008, respectively.  The weighted-average interest rate was 10.02%, 11.95% and 12.97% for the fiscal years ended June 30, 2009, 2008 and 2007, respectively.  Total interest expense associated with the Floating Rate Notes due 2011, excluding the impact of mark-to-market adjustments related to interest rate swaps, was $16.8 million, $21.0 million and $21.2 million for the fiscal years ended June 30, 2009, 2008 and 2007, 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 13 for additional information regarding the Company’s use of interest rate swaps.

 

The original issue discount of approximately $4.8 million is being amortized to interest expense ratably over the term of the Floating Rate Notes due 2011.  Amortization of original issue discount to interest expense for the fiscal years ended June 30, 2009, 2008 and 2007 was approximately $0.8 million, $1.1 million and $1.0 million, respectively.  These amounts include the impact of the early extinguishment of Floating Rate Notes due 2011 discussed in the following paragraphs.

 

On December 13, 2006, the Company purchased $12.0 million aggregate principal amount of Floating Rate Notes due 2011 outstanding, plus accrued interest, from a noteholder for an amount less than face value.  The Company utilized the Denham Credit Facility (refer to Note 19) to acquire such Floating Rate Notes due 2011.  This transaction resulted in a gain on early extinguishment of debt of approximately $1.0 million, which was recorded as a reduction of interest expense for the fiscal year ended June 30, 2007.  The Company also recorded as additional interest expense $0.6 million of original issue discount and debt issuance costs for the fiscal year ended June 30, 2007, which represents a pro rata portion of such costs that were deferred at the issuance date of the Floating Rate Notes due 2011.

 

During the fiscal year ended June 30, 2008, the Company utilized cash and cash equivalents to acquire $12.8 million aggregate principal amount of outstanding Floating Rate Notes due 2011 from noteholders, in each case, for an amount less than face value.  These transactions resulted in $0.8 million of aggregate gains on the early extinguishment of debt that was recorded as a reduction of interest expense for the fiscal year ended June 30, 2008.  The Company also recorded as additional interest expense $0.5 million of original issue discount and debt issuance costs for the fiscal year ended June 30, 2008, which represents a pro rata portion of such costs that were deferred at the issuance date of the Floating Rate Notes due 2011.

 

As of June 30, 2009, the Company had $165.2 million aggregate principal amount of Floating Rate Notes due 2011 outstanding.  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.  The shares of Class A Common Stock issued to the holders of the Fixed Rate Notes due 2014 represented 62.5% of the total aggregate shares of common stock outstanding after consummation of the Restructuring.

 

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 on the consolidated balance sheets until their maturity date in August 2011 unless acquired 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.

 

Fixed Rate Notes due 2014

 

Pursuant to the Restructuring consummated on September 22, 2009, the Company issued $67.8 million aggregate principal amount 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, to the holders of record of the Fixed Rate Notes due 2014 on the immediately preceding January 15 and July 15.  The Fixed Rate Notes due

 

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2014 will mature on August 1, 2014.  The Fixed Rate Notes due 2014 were issued at a discount, which will be 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 will be amortized as an increase to interest expense over the remaining life 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 the Company’s unsecured senior obligations, including the Floating Rate Notes due 2011, to the extent of the value of the assets securing the Fixed Rate Notes due 2014 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 a cash escrow account maintained as security for future payments to holders of the Fixed Rate Notes due 2014 (the “Notes Escrow Account”) and by a second-priority security interest in substantially all other existing and future assets of the Company.  The Notes Escrow Account was funded with approximately $9.0 million, which represents approximate interest payable by the Company 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, the Company may, at its option, use the net cash proceeds of equity offerings, if any, to redeem either: (1) 100% of the principal amount of the Fixed Rate Notes due 2014 issued; or (2)  up to 35% of the principal amount of the Fixed Rate Notes due 2014 issued 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 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 11, 2011, the Company may redeem the Fixed Rate Notes due 2014 at its option, in whole or in part, upon not less than 30 nor more than 60 days’ notice, at the redemption prices specified in the agreement that governs the Fixed Rate Notes due 2014.

 

Upon a change of control of the Company, the Company will 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.

 

Holdings has no significant independent operations.  Each of Holdings’ domestic U.S. subsidiaries jointly and severally, fully and unconditionally guarantees the Floating Rate Notes due 2011 and the Fixed Rate Notes due 2014.  Refer to Note 23 for consolidating financial statements of Holdings and its guarantor and non-guarantor subsidiaries.

 

The indenture governing the Fixed Rate Notes due 2014 contains restrictions on Holdings and its domestic subsidiaries with regard to declaring or paying any dividend or distribution on Holdings capital stock.  As of June 30, 2009, the Company was in compliance with all provisions of the indenture governing the Floating Rate Notes due 2011.

 

Note 17.  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.  During the fiscal year ended June 30, 2005, as part of a corporate reorganization, MXenergy Inc. merged with a subsidiary of Holdings to become a wholly owned subsidiary of Holdings and stockholders of MXenergy Inc. became stockholders of Holdings.  Total related offering expenses of approximately $1.6 million were deducted from the carrying value of the Preferred Stock, which resulted in a net carrying value of approximately $29.4 million at June 30, 2007.

 

The Company has determined that the Preferred Stock 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 is recorded outside of stockholders’ equity on the consolidated balance sheets.  As of June 30, 2008, the Company determined that it was probable that the Preferred Stock would become redeemable at June 30, 2009, which is the earliest possible date that the Preferred Investors could have caused the Company to make the redemption election described under the redemption

 

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provisions of the Preferred Stock Purchase Agreement.  As of June 30, 2009, the Company determined that the Preferred Stock became redeemable as of that date. Therefore, as of June 30, 2009 and 2008, the carrying value of the Preferred Stock was adjusted to reflect the estimated redemption value, which represents the amount that provides the Preferred Investors with a minimum annual rate of return of 12%, compounded annually through June 30, 2009, as guaranteed to the Preferred Investors under the dividend provisions of the Preferred Stock Purchase Agreement with corresponding charges of $5.9 million and $19.4 million recorded to retained earnings or additional paid in capital during the fiscal years ended June 30, 2009 and 2008, respectively.

 

The Preferred Investors had the right at any time to convert their shares of Preferred Stock into shares of Holdings’ common stock.  Upon conversion, the number of shares of common stock to be issued shall be the number of shares of Preferred Stock outstanding; adjusted in accordance with conversion provisions in the Preferred Stock Purchase Agreement that guarantee the Preferred Investors a minimum annual rate of return equal to 12% per annum, compounded annually.  The conversion price was subject to certain anti-dilution provisions included in the Preferred Stock Purchase Agreement.  As of June 30, 2009, 1,451,310 shares of Holdings’ common stock were reserved for issuance upon conversion of the Preferred Stock.

 

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 any Preferred Stock.

 

Note 18.  Common Stock

 

Amendment and Restatement of Corporate Documents

 

On the consummation date of the of the Restructuring, the Company’s Certificate of Incorporation and Bylaws were amended and restated, and certain holders of common stock entered into a Stockholders Agreement.  These documents contain customary provisions, including provisions relating to certain approval rights, preemptive rights, share transfer restrictions, rights of first refusal, tag-along rights and drag-along rights.

 

Additionally, the amended and restated Certificate of Incorporation authorized 200,000,000 shares of Common Stock, consisting of 50,000,000 shares of Class A Common Stock, 10,000,000 shares of Class B Common Stock, 40,000,000 shares of Class C Common Stock and 100,000,000 shares of Class D Common Stock.  Prior to the consummation of the Restructuring, the Company had 4,681,219 shares of common stock issued and outstanding.  Those shares of common stock were exchanged for 4,499,588 shares of newly authorized Class C Common Stock, which represented 8.29% of the aggregate total shares of common stock outstanding after the consummation of the Restructuring.  Additional shares of Class A Common Stock, Class B Common Stock and Class C Common Stock were issued to various parties as a result of the Restructuring.

 

Stock-Based Compensation Plans

 

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

 

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:

 

·      2001 Incentive Stock Option Plan (the “2001 ISO Plan”)  The 2001 ISO Plan allows for awards of stock or stock options not to exceed the 366,500 shares of Holdings’ common stock reserved as a pool for distribution to employees and non-employees.  As of June 30, 2009, there were no shares available under the 2001 ISO Plan for future award.

 

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·      2003 Incentive Stock Option Plan (the “2003 ISO Plan”) – The 2003 ISO Plan allows for awards of stock or stock options not to exceed the 400,000 shares of Holdings’ common stock reserved as a pool for distribution to employees and non-employees.  As of June 30, 2009, there were 68,396 shares available under the 2003 ISO Plan for future award.

 

·      2006 Equity Incentive Compensation Plan (the “2006 EIC Plan”) – The 2006 EIC Plan allows for awards of options, restricted stock, phantom shares, dividend equivalent rights performance awards or stock appreciation rights, to employees, members of the Board of Directors, officers, consultants and other service providers.  Up to 750,000 shares of Holdings’ common stock have been authorized to be issued for awards under the 2006 EIC Plan.  As of June 30, 2009, 328,066 shares were available under the 2006 EIC Plan for future award.  The adoption of the 2006 EIC Plan had no impact on the 2001 ISO Plan or the 2003 ISO Plan.

 

The Company did not grant any other awards of options under any of its stock-based compensation plans during the fiscal year ended June 30, 2009.

 

As of June 30, 2009, 981,270 options to purchase common stock were outstanding under the Company’s three approved stock-based compensation plans.  The Company recorded approximately $1.1 million, $2.2 million and $2.2 million of compensation expense in general and administrative expenses during the fiscal years ended June 30, 2009, 2008 and 2007, respectively, related to these outstanding awards.  Since all outstanding options and warrants have been cancelled pursuant to the Restructuring, the Company does not expect to record any expense related to options and warrants during fiscal year 2010.

 

As of June 30, 2009, 34,600 options to purchase common stock have been issued to two non-employee directors of the Company.  These options have a weighted average exercise price of $12.75 per share and are fully-vested as of June 30, 2009.

 

As of June 30, 2009, the Company had options and warrants outstanding which were, or may be, 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 (e.g., 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) .  Pursuant to the Restructuring, the Company announced its intention to terminate the 2001 ISO Plan, the 2003 ISO Plan and the 2006 EIC Plan and offered a cash settlement to holders of options and warrants in exchange for their agreement to cancel and terminate such options and warrants.  The total amount required for such cash settlement payments was approximately $0.2 million, which was recorded as general and administrative expense during the first quarter of fiscal year 2010.

 

Warrants Issued to Employees and Related Parties

 

The Company has issued warrants to purchase common stock to certain employees and related parties that were not issued under any of the Company’s three approved stock-based compensation plans.  As of June 30, 2009, the Company had 27,500 warrants to purchase common stock outstanding that were granted to employees prior to June 30, 2006 and are accounted for using variable plan accounting.  For these warrants, changes in the estimated fair value of the Company’s common stock between the grant date and the exercise date result in corresponding adjustments to compensation expense during the period in which the change in the estimated fair value of common stock occurs.  Total compensation expense (reduction of compensation expense) related to these warrants was ($0.6) million (($0.4) million net of tax), ($0.5) million (($0.3) million net of tax) and $2.3 million ($1.4 million net of tax) during the fiscal years ended June 30, 2009, 2008 and 2007, respectively.

 

As of June 30, 2008, Denham held 1,544,736 fully-vested warrants to purchase common stock outstanding, with a weighted average exercise price of $9.79 per share.  In September 2008, Denham exercised these warrants in a cashless transaction, resulting in the issuance of 1,054,982 shares of Holdings’ common stock.  Denham forfeited the right to acquire 489,754 shares of Holdings’ common stock under the warrants as consideration for the cashless exercise.  These warrants were not subject to variable plan accounting because there was no future requirement to provide any services to the Company in order for Denham to exercise the warrants.  Therefore, the Company did not record any expense related to these warrants during the fiscal years ended June 30, 2009, 2008 or 2007.

 

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

 

 

 

Awards Outstanding at June 30,

 

 

 

2009

 

2008

 

2007

 

 

 

Number of
Awards

 

Weighted-
Average
Exercise
Price

 

Number of
Awards

 

Weighted-
Average
Exercise
Price

 

Number of
Awards

 

Weighted-
Average
Exercise
Price

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Outstanding at beginning of year

 

2,666,056

 

$

17.16

 

2,931,406

 

$

16.35

 

2,538,106

 

$

10.87

 

Granted

 

 

 

7,500

 

50.10

 

508,000

 

42.90

 

Exercised

 

(1,591,436

)

9.78

 

(224,417

)

4.18

 

(29,000

)

3.08

 

Forfeited

 

(49,300

)

11.09

 

(48,433

)

33.57

 

(40,700

)

28.73

 

Expired

 

(16,550

)

8.80

 

 

 

(45,000

)

4.40

 

Outstanding at end of year

 

1,008,770

 

29.24

 

2,666,056

 

17.16

 

2,931,406

 

16.35

 

Weighted average fair value of grants during the year

 

 

 

$

 

 

 

$

13.70

 

 

 

$

12.31

 

Total intrinsic value of awards exercised during fiscal year 2009 (in millions)

 

$

33.0

 

 

 

 

 

 

 

 

 

 

 

Total intrinsic value of awards outstanding at June 30, 2009 (in millions)

 

$

0.1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Awards Outstanding at June 30,

 

 

 

2009

 

2008

 

2007

 

Exercise
Price

 

Number of
Awards
Outstanding

 

Number of
Awards
Exercisable

 

Weighted-
Average
Contractual
Life
Remaining

 

Number of
Awards
Outstanding

 

Number of
Awards
Exercisable

 

Number of
Awards
Outstanding

 

Number of
Awards
Exercisable

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$1.00

 

72,500

 

72,500

 

2.7 Years

 

100,000

 

100,000

 

110,000

 

110,000

 

$2.16

 

 

 

 

 

 

132,450

 

132,450

 

$3.72 – $5.35

 

10,000

 

10,000

 

2.7 Years

 

10,000

 

10,000

 

47,500

 

47,500

 

$6.99 – $9.12

 

115,350

 

115,350

 

4.1 Years

 

1,163,263

 

1,163,263

 

1,215,863

 

1,215,863

 

$11.64 – $15.00

 

 

 

 

562,573

 

562,573

 

562,573

 

562,573

 

$21.50 – $25.00

 

220,920

 

220,920

 

3.7 Years

 

233,820

 

233,820

 

234,420

 

162,947

 

$27.50 – $33.67

 

124,000

 

124,000

 

5.1 Years

 

128,500

 

128,500

 

136,300

 

91,200

 

$42.57 – $50.10

 

466,000

 

309,833

 

7.0 Years

 

467,900

 

157,067

 

492,300

 

5,000

 

 

 

1,008,770

 

852,603

 

 

 

2,666,056

 

2,355,223

 

2,931,406

 

2,327,533

 

 

The weighted-average remaining term for all outstanding awards as of June 30, 2009 was approximately 5.3 years.  The weighted-average remaining term for all exercisable awards as of June 30, 2009 was approximately 5.0 years.  The weighted average exercise price of awards exercisable as of June 30, 2009 was $26.69 per share.

 

The aggregate proceeds from exercises of options and warrants were $15.6 million, $0.4 million, and less than $0.1 million for the fiscal years ended June 30, 2009, 2008 and 2007, respectively.   The tax benefit for the Company from the exercise of options and warrants was less than $0.1 million, $0.8 million and $0.2 million for the fiscal years ended June 30, 2009, 2008 and 2007, respectively, which was recorded as a reduction of current tax liability and an increase to additional paid-in capital.

 

Common Stock Issued to Senior Executives

 

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

 

New Management Incentive Plan

 

In connection with the Restructuring, it is anticipated that the Company’s board of directors will authorize the creation of a new management incentive plan (the “Management Incentive Plan”) to issue Class C Common Stock not to exceed 10% of the Company’s outstanding common stock (on a fully diluted basis) after giving effect to the Restructuring.  The Company expects that the Management Incentive Plan will provide the board of directors the flexibility to make awards to employees, officers, directors, consultants and advisors and will permit, among other things, the grant of options to purchase shares of common stock that are intended to qualify as incentive stock options under Section 422 of the Internal Revenue Code, grants

 

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of options to purchase shares of common stock that will not so qualify, grants of stock appreciation rights, and grants of common stock at incentive prices or for free.

 

Note 19.  Related Party Transactions

 

Credit Agreement with Denham Commodity Partners Fund LP

 

Denham Commodity Partners Fund LP is a significant stockholder of the Company.  Denham has extended a $12.0 million line of credit to the Company, which bears interest at 9% per annum.  The termination date for the Denham Credit Facility is May 19, 2010, at which time any outstanding principal balance becomes due.  In accordance with the September 30, 2008 amendment and restatement of the agreement that governs the Revolving Credit Facility (refer to Note 15), the Company was required to borrow any available balance under the Denham Credit Facility prior to November 7, 2008, and to maintain such balance outstanding until the Revolving Credit Facility expires.  In September 2008, the Company borrowed the entire $12.0 million available line under the Denham Credit Facility.  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 related to the Denham Credit Facility was approximately $0.8 million, $0.5 million and $0.5 million for the fiscal years ended June 30, 2009, 2008 and 2007, respectively.

 

Legal Services

 

A former director and significant 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.  During the fiscal years ended June 30, 2009, 2008 and 2007, Paul Hastings provided the Company with legal services totaling $1.9 million, $0.6 million and $1.2 million, respectively, of which $1.2 million, $0.6 million and $0.8 million, respectively, were for general legal services recorded as general and administrative expenses.  The remaining $0.7 million and $0.4 million of fees for the fiscal years ended June 30, 2009 and 2007, respectively, primarily related to issuance of debt and acquisitions and were deferred on the consolidated balance sheets, to be amortized over the estimated useful lives associated with the related transactions.  The Company expects that Paul Hastings will continue to provide legal services to the Company in future periods.

 

Financial Advisory Services

 

The Company has 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”).  In April 2008, the Company entered into an engagement letter with Greenhill that amends the Greenhill Agreement by: (1) expanding the definition of the potential transaction specified in the Greenhill Agreement; and (2) outlining fees associated with the occurrence of such a transaction.  In November 2008, the April 2008 engagement letter was amended to: (1) extend the engagement; (2) further expand the definition of the potential transaction; and (3) revise the potential fees associated with such a transaction.  Greenhill provided services to the Company totaling approximately $0.3 million related to the Restructuring, which were recorded as general and administrative expenses during the first quarter of fiscal year 2010.

 

Management Fees

 

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

 

In accordance with the terms of the Revolving Credit Agreement, payments to the shareholders for these management fees were deferred until consummation of the Restructuring on September 22, 2009.

 

Warrants Exercised by Denham

 

As of June 30, 2008, Denham held 1,544,736 fully-vested warrants to purchase an equivalent number of shares of Holdings’ common stock with a weighted average exercise price of $9.79 per share.  These warrants were issued in connection with various previous debt financings and accordingly, were not subject to variable plan accounting.  Therefore, the Company did not record any expense related to these warrants during fiscal years 2009 or 2008.  In September 2008, Denham exercised these warrants in a cashless transaction, resulting in the issuance of 1,054,982 shares of Holdings’ common stock.  Denham forfeited the right to acquire 489,754 shares of Holdings’ common stock under the warrants as consideration for the cashless exercise.

 

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Bridge Financing Related to the Revolving Credit Agreement

 

Pursuant to the Amended Revolving Credit Agreement, on November 17, 2008, Charter Mx LLC, Denham and four members of the Company’s senior management team agreed to provide Bridge Financing in an aggregate amount of $10.4 million by becoming lenders in a new bridge loan tranche under the Amended Revolving Credit Agreement.  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 Jeffrey A. Mayer, Chief Executive Officer; Steven Murray, Chief Operating Officer; Carole R. Artman-Hodge, Executive Vice President; and Chaitu Parikh, Chief Financial Officer.  An upfront fee of 2% of the respective loan amount was paid to each Bridge Financing lender upon closing.

 

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, on the expiration date of the Revolving Credit Facility in September 2009.

 

Interest accrued to each Bridge Financing lender 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 is repaid.  Charter Mx LLC was guaranteed a minimum of $1.25 million of interest over the life of its loan.  The remaining lenders are guaranteed an aggregate minimum of $1.62 million of interest, shared ratably in proportion to their outstanding loan balances over the lives of their outstanding loans.  During the fiscal year ended June 30, 2009, the Company recorded approximately $2.7 million of interest expense associated with the Bridge Financing.

 

Note 20.  Employee Benefits

 

The Company sponsors an employee savings plan under Section 401(k) of the Internal Revenue Code for all full-time employees and part-time employees (who work at least 1,000 hours annually) with at least three months of continuous service.  Eligible employees may make pre-tax contributions up to 20% of their annual compensation, not to exceed the annual limitation set forth in Section 402 (g) for any plan year.  The Company makes a matching contribution of up to 10% of each participating employee’s compensation up to the maximum allowable under the plan.  Employees whose employment date is prior to July 1, 2007, are immediately 100% vested in all contributions.  Employer contributions for employees whose employment date is on or after July 1, 2007 vest in increments of 25% per year.  The Company made contributions of $1.4 million, $1.3 million and $1.0 million for the fiscal years ended June 30, 2009, 2008 and 2007, respectively.

 

Note 21.  Commitments and Contingencies

 

Operating Leases

 

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

 

Fiscal year

 

Amount

 

 

 

(in thousands)

 

 

 

 

 

2010

 

$

760

 

2011

 

232

 

2012

 

208

 

2013

 

234

 

2014

 

234

 

Thereafter

 

844

 

Total

 

$

2,512

 

 

Capacity Charge Commitments

 

The Company enters into agreements to transport and store natural gas.  Since the demand for natural gas in the winter is high, the Company agrees to pay for certain capacity for the transportation systems utilized for up to a twelve-month period.  These agreements are take-or-pay in that the Company must pay for the capacity committed even if it does not use the

 

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capacity.  For contracts outstanding, as of June 30, 2009, the total committed capacity charges were approximately $6.6 million.  These agreements generally will expire during various months during the fiscal year ending June 30, 2010, and will be replaced with new contracts as necessary.

 

Physical Commodity Purchase Commitments

 

The Company has forward physical contracts to acquire natural gas and electricity in specified future periods.   The contracts to acquire natural gas generally have a fixed basis component and a variable component determined based on market prices at purchase date.  Contracts to acquire electricity generally are on a fixed basis.  All such contracts are considered to be “normal purchases” under U.S. GAAP, and therefore are not reported on the consolidated balance sheets.

 

As of June 30, 2009, the Company had forward physical contracts to purchase a total of 3,603,000 MMBtus of natural gas beginning in July 2009 and ending in November 2010.  The amount of the fixed basis and variable components of these contracts were $0.2 million and $14.7 million, respectively, at June 30, 2009.

 

As of June 30, 2009, the Company had forward physical contracts to purchase a total of 228,000 MWhrs of electricity beginning in July 2009 and ending in September 2011.  These contracts, which are all on a fixed basis, amounted to $14.5 million at June 30, 2008.

 

As of June 30, 2009, total forward commitments to purchase natural gas and electricity were $25.2 million for fiscal year 2010, $3.9 million for fiscal year 2011 and $0.3 million for fiscal year 2012.

 

Litigation

 

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

 

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

 

Note 22.  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 segments, natural gas and electricity are sold at fixed and variable contracted prices based on the demand or usage of customers.

 

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

 

Fiscal year ended June 30,

 

Natural Gas

 

Electricity

 

Total

 

 

 

(in thousands)

 

2009:

 

 

 

 

 

 

 

Sales

 

$

670,584

 

$

119,196

 

$

789,780

 

Cost of goods sold (excluding unrealized gains (losses) from risk management activities, net) (1)

 

(572,616

)

(96,955

)

(669, 571

)

Gross profit (excluding unrealized gains (losses) from risk management activities, net) (1)

 

$

97,968

 

$

22,241

 

120,209

 

 

 

 

 

 

 

 

 

Items to reconcile total segment gross profit to income before income tax expense:

 

 

 

 

 

 

 

Unrealized gains (losses) from risk management activities, net

 

 

 

 

 

(87,575

)

Operating expenses

 

 

 

 

 

(114,779

)

Interest expense, net of interest income

 

 

 

 

 

(45,305

)

 

 

 

 

 

 

 

 

Loss before income tax benefit

 

 

 

 

 

$

(127,450

)

 

 

 

 

 

 

 

 

Assets and liabilities allocated to business segments at period end:

 

 

 

 

 

 

 

Accounts receivable, net

 

$

36,006

 

$

11,592

 

$

47,598

 

Natural gas inventories

 

29,415

 

 

29,415

 

Goodwill

 

3,810

 

 

3,810

 

Customer acquisition costs, net

 

20,882

 

7,068

 

27,950

 

Total assets allocated to business segments

 

$

90,113

 

$

18,660

 

$

108,773

 

 

 

 

 

 

 

 

 

2008:

 

 

 

 

 

 

 

Sales

 

$

669,522

 

$

82,761

 

$

752,283

 

Cost of goods sold (excluding unrealized gains (losses) from risk management activities, net) (1)

 

(564,219

)

(72,534

)

(636,753

)

Gross profit (excluding unrealized gains (losses) from risk management activities, net) (1)

 

$

105,303

 

$

10,227

 

115,530

 

 

 

 

 

 

 

 

 

Items to reconcile total segment gross profit to income before income tax expense:

 

 

 

 

 

 

 

Unrealized gains (losses) from risk management activities, net

 

 

 

 

 

67,168

 

Operating expenses

 

 

 

 

 

(106,645

)

Interest expense, net of interest income

 

 

 

 

 

(34,105

)

 

 

 

 

 

 

 

 

Income before income tax expense

 

 

 

 

 

$

41,948

 

 

 

 

 

 

 

 

 

Assets and liabilities allocated to business segments at period end:

 

 

 

 

 

 

 

Accounts receivable

 

$

65,897

 

$

21,776

 

$

87,673

 

Natural gas inventories

 

65,006

 

 

65,006

 

Goodwill

 

3,810

 

 

3,810

 

Customer acquisition costs, net

 

34,439

 

7,254

 

41,693

 

Total assets allocated to business segments

 

$

169,152

 

$

29,030

 

$

198,182

 

 

 

 

 

 

 

 

 

2007:

 

 

 

 

 

 

 

Sales

 

$

680,811

 

$

23,115

 

$

703,926

 

Cost of goods sold (excluding unrealized gains (losses) from risk management activities, net) (1)

 

(565,531

)

(19,536

)

(585,067

)

Gross profit (excluding unrealized gains (losses) from risk management activities, net) (1)

 

$

115,280

 

$

3,579

 

118,859

 

 

 

 

 

 

 

 

 

Items to reconcile total segment gross profit to loss before income tax benefit:

 

 

 

 

 

 

 

Unrealized gains (losses) from risk management activities, net

 

 

 

 

 

(17,079

)

Operating expenses

 

 

 

 

 

(91,015

)

Interest expense, net of interest income

 

 

 

 

 

(33,058

)

 

 

 

 

 

 

 

 

Loss before income tax benefit

 

 

 

 

 

$

(22,293

)

 


(1)

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

 

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Note 23.  Condensed Consolidating Financial Information

 

The Floating Rate Notes due 2011 were issued by Holdings in August 2006.  Each of the following wholly owned domestic subsidiaries of Holdings (the “Guarantor Subsidiaries”) jointly, severally and unconditionally guarantees the 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.

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

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

·                  MXenergy Services Inc.

·                  Infometer.com Inc.

 

The only wholly owned subsidiary that is not a guarantor for the 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

June 30, 2009

(in thousands)

 

 

 

 

 

Non-

 

 

 

 

 

 

 

 

 

MXenergy

 

Guarantor

 

Guarantor

 

 

 

 

 

 

 

Holdings Inc.

 

Subsidiary

 

Subsidiaries

 

Eliminations

 

Consolidated

 

 

 

 

 

 

 

 

 

 

 

 

 

Assets

 

 

 

 

 

 

 

 

 

 

 

Current assets:

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

 

$

262

 

$

23,004

 

$

 

$

23,266

 

Restricted cash

 

 

 

75,368

 

 

75,368

 

Intercompany receivable

 

191,399

 

 

 

(191,399

)

 

Accounts receivable, net

 

 

56

 

47,542

 

 

47,598

 

Natural gas inventories

 

 

 

29,415

 

 

29,415

 

Current portion of unrealized gains from risk management activities

 

 

 

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

 

197,860

 

405

 

196,640

 

(191,399

)

203,506

 

Unrealized gains from risk management activities

 

 

 

 

 

 

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

 

Long-term investments

 

(40,169

)

 

 

40,169

 

 

Other assets

 

4,412

 

 

576

 

 

4,988

 

Total assets

 

$

162,103

 

$

434

 

$

247,764

 

$

(151,230

)

$

259,071

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities and stockholders’ equity

 

 

 

 

 

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

 

 

 

 

 

Accounts payable and accrued liabilities

 

$

7,842

 

$

120

 

$

25,338

 

$

 

$

33,300

 

Accrued commodity purchases

 

 

40

 

9,807

 

 

9,847

 

Intercompany payable

 

 

1,845

 

189,554

 

(191,399

)

 

Current portion of unrealized losses from risk management activities

 

4,176

 

 

30,048

 

 

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

 

12,018

 

2,005

 

276,418

 

(191,399

)

99,042

 

Unrealized losses from risk management activities

 

4,127

 

 

9,944

 

 

14,071

 

Long-term debt:

 

 

 

 

 

 

 

 

 

 

 

Floating Rate Notes due 2011

 

163,476

 

 

 

 

163,476

 

Total long-term debt

 

163,476

 

 

 

 

163,476

 

Total liabilities

 

179,621

 

2,005

 

286,362

 

(191,399

)

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

)

 

Unearned stock compensation

 

 

 

 

 

 

Accumulated other comprehensive loss

 

(3

)

(3

)

 

3

 

(3

)

(Accumulated deficit) retained earnings

 

(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

 

$

162,103

 

$

434

 

$

247,764

 

$

(151,230

)

$

259,071

 

 

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MXENERGY HOLDINGS INC.

Consolidating Balance Sheet

June 30, 2008

(dollars in thousands)

 

 

 

MXenergy
Holdings Inc.

 

Non-
Guarantor
Subsidiary

 

Guarantor
Subsidiaries

 

Eliminations

 

Consolidated

 

Assets

 

 

 

 

 

 

 

 

 

 

 

Current assets:

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

 

$

970

 

$

70,988

 

$

 

$

71,958

 

Restricted cash

 

 

 

587

 

 

587

 

Intercompany receivable

 

172,455

 

 

 

(172,455

)

 

Accounts receivable, net

 

 

28

 

87,645

 

 

87,673

 

Natural gas inventories

 

 

 

65,006

 

 

65,006

 

Current portion of unrealized gains from risk management activities

 

183

 

 

35,681

 

 

35,864

 

Income taxes receivable

 

7,524

 

 

 

 

7,524

 

Other current assets

 

 

302

 

3,059

 

 

3,361

 

Total current assets

 

180,162

 

1,300

 

262,966

 

(172,455

)

271,973

 

Unrealized gains from risk management activities

 

234

 

 

12,987

 

 

13,221

 

Goodwill

 

 

 

3,810

 

 

3,810

 

Customer acquisition costs, net

 

 

68

 

41,625

 

 

41,693

 

Fixed assets, net

 

 

 

10,525

 

 

10,525

 

Deferred income taxes

 

 

 

10,503

 

 

10,503

 

Long-term investments

 

74,949

 

 

 

(74,949

)

 

Other assets

 

3,134

 

 

893

 

 

4,027

 

Total assets

 

$

258,479

 

$

1,368

 

$

343,309

 

$

(247,404

)

$

355,752

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities and stockholders’ equity

 

 

 

 

 

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

 

 

 

 

 

Accounts payable and accrued liabilities

 

$

8,816

 

$

305

 

$

27,481

 

$

 

$

36,602

 

Accrued commodity purchases

 

 

612

 

50,849

 

 

51,461

 

Intercompany payable

 

 

1,912

 

170,543

 

(172,455

)

 

Current portion of unrealized losses from risk management activities

 

2,187

 

 

791

 

 

2,978

 

Deferred revenue

 

 

 

7,435

 

 

7,435

 

Deferred income taxes

 

 

 

9,800

 

 

9,800

 

Total current liabilities

 

11,003

 

2,829

 

266,899

 

(172,455

)

108,276

 

Unrealized losses from risk management activities

 

2,839

 

 

 

 

2,839

 

Long-term debt:

 

 

 

 

 

 

 

 

 

 

 

Floating Rate Notes Due 2011

 

162,648

 

 

 

 

162,648

 

Total long-term debt

 

162,648

 

 

 

 

162,648

 

Total liabilities

 

176,490

 

2,829

 

266,899

 

(172,455

)

273,763

 

 

 

 

 

 

 

 

 

 

 

 

 

Redeemable convertible preferred stock

 

48,779

 

 

 

 

48,779

 

 

 

 

 

 

 

 

 

 

 

 

 

Commitments and contingencies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Stockholders’ equity:

 

 

 

 

 

 

 

 

 

 

 

Common stock

 

36

 

1

 

 

(1

)

36

 

Additional paid-in-capital

 

23,635

 

 

 

 

23,635

 

Contributed capital

 

 

 

42,401

 

(42,401

)

 

Unearned stock compensation

 

(4

)

 

 

 

(4

)

Accumulated other comprehensive loss

 

(189

)

(189

)

 

189

 

(189

)

(Accumulated deficit) retained earnings

 

9,732

 

(1,273

)

34,009

 

(32,736

)

9,732

 

Total stockholders’ equity

 

33,210

 

(1,461

)

76,410

 

(74,949

)

33,210

 

Total liabilities and stockholders’ equity

 

$

258,479

 

$

1,368

 

$

343,309

 

$

(247,404

)

$

355,752

 

 

106



Table of Contents

 

MXENERGY HOLDINGS INC.

Consolidating Statement of Operations

Year Ended June 30, 2009

(in thousands)

 

 

 

 

 

Non-

 

 

 

 

 

 

 

 

 

MXenergy

 

Guarantor

 

Guarantor

 

 

 

 

 

 

 

Holdings Inc.

 

Subsidiary

 

Subsidiaries

 

Eliminations

 

Consolidated

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales of natural gas and electricity

 

$

 

$

358

 

$

789,422

 

$

 

$

789,780

 

Cost of goods sold (excluding depreciation and amortization):

 

 

 

 

 

 

 

 

 

 

 

Cost of natural gas and electricity sold

 

 

348

 

596,399

 

 

596,747

 

Realized losses from risk management activities

 

 

 

72,824

 

 

72,824

 

Unrealized losses from risk management activities

 

 

 

87,575

 

 

 

87,575

 

 

 

 

348

 

756,798

 

 

757,146

 

Gross profit

 

 

10

 

32,624

 

 

32,634

 

Operating expenses:

 

 

 

 

 

 

 

 

 

 

 

General and administrative expenses

 

93

 

733

 

59,131

 

 

59,957

 

Advertising and marketing expenses

 

 

(454

)

2,571

 

 

2,117

 

Reserves and discounts

 

 

 

15,130

 

 

15,130

 

Depreciation and amortization

 

 

31

 

37,544

 

 

37,575

 

Equity in operations of consolidated subsidiaries

 

97,288

 

 

 

(97,288

)

 

Total operating expenses

 

97,381

 

310

 

114,376

 

(97,288

)

114,779

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating (loss) profit

 

(97,381

)

(300

)

(81,752

)

97,288

 

(82,145

)

Interest expense, net

 

3,693

 

(5

)

41,617

 

 

45,305

 

(Loss) income before income tax benefit (expense)

 

(101,074

)

(295

)

(123,369

)

97,288

 

(127,450

)

Income tax benefit (expense)

 

873

 

 

26,376

 

 

27,249

 

Net (loss) income

 

$

(100,201

)

$

(295

)

$

(96,993

)

$

97,288

 

$

(100,201

)

 

107



Table of Contents

 

MXENERGY HOLDINGS INC.

Consolidating Statement of Operations

Year Ended June 30, 2008

(dollars in thousands)

 

 

 

MXenergy
 Holdings Inc.

 

Non-
Guarantor
Subsidiary

 

Guarantor
Subsidiaries

 

Eliminations

 

Consolidated

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales of natural gas and electricity

 

$

 

$

1,481

 

$

750,802

 

$

 

$

752,283

 

Cost of goods sold (excluding depreciation and amortization):

 

 

 

 

 

 

 

 

 

 

 

Cost of natural gas and electricity sold

 

 

1,402

 

628,604

 

 

630,006

 

Realized losses from risk management activities

 

 

 

6,747

 

 

6,747

 

Unrealized losses from risk management activities

 

 

 

(67,168

)

 

(67,168

)

 

 

 

1,402

 

568,183

 

 

569,585

 

Gross profit

 

 

79

 

182,619

 

 

182,698

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating expenses:

 

 

 

 

 

 

 

 

 

 

 

General and administrative expenses

 

117

 

505

 

61,649

 

 

62,271

 

Advertising and marketing expenses

 

 

(426

)

4,972

 

 

4,546

 

Reserves and discounts

 

 

 

7,130

 

 

7,130

 

Depreciation and amortization

 

 

36

 

32,662

 

 

32,698

 

Equity in operations of consolidated subsidiaries

 

(27,584

)

 

 

27,584

 

 

Total operating expenses

 

(27,467

)

115

 

106,413

 

27,584

 

106,645

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating profit (loss)

 

27,467

 

(36

)

76,206

 

(27,584

)

76,053

 

Interest expense, net

 

3,290

 

 

30,815

 

 

34,105

 

Income (loss) before income tax (expense) benefit

 

24,177

 

(36

)

45,391

 

(27,584

)

41,948

 

Income tax benefit (expense)

 

616

 

 

(17,771

)

 

(17,155

)

Net income (loss)

 

$

24,793

 

$

(36

)

$

27,620

 

$

(27,584

)

$

24,793

 

 

108



Table of Contents

 

MXENERGY HOLDINGS INC.

Consolidating Statement of Operations

Year Ended June 30, 2007

(dollars in thousands)

 

 

 

MXenergy
Holdings Inc.

 

Non-
Guarantor
Subsidiary

 

Guarantor
Subsidiaries

 

Eliminations

 

Consolidated

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales of natural gas and electricity

 

$

 

$

1,292

 

$

702,634

 

$

 

$

703,926

 

Cost of goods sold (excluding depreciation and amortization):

 

 

 

 

 

 

 

 

 

 

 

Cost of natural gas and electricity sold

 

 

1,267

 

550,761

 

 

552,028

 

Realized losses from risk management activities

 

 

 

33,039

 

 

33,039

 

Unrealized losses from risk management activities

 

 

 

17,079

 

 

17,079

 

 

 

 

1,267

 

600,879

 

 

602,146

 

Gross profit

 

 

25

 

101,755

 

 

101,780

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating expenses:

 

 

 

 

 

 

 

 

 

 

 

General and administrative expenses

 

 

339

 

54,177

 

 

54,516

 

Advertising and marketing expenses

 

 

4

 

4,040

 

 

4,044

 

Reserves and discounts

 

 

 

4,725

 

 

4,725

 

Depreciation and amortization

 

 

91

 

27,639

 

 

27,730

 

Equity in operations of consolidated subsidiaries

 

15,326

 

 

 

(15,326

)

 

Total operating expenses

 

15,326

 

434

 

90,581

 

(15,326

)

91,015

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating (loss) profit

 

(15,326

)

(409

)

11,174

 

15,326

 

10,765

 

Interest expense, net

 

(3,144

)

 

36,202

 

 

33,058

 

(Loss) income before income tax benefit (expense)

 

(12,182

)

(409

)

(25,028

)

15,326

 

(22,293

)

Income tax (expense) benefit

 

(1,616

)

 

10,111

 

 

8,495

 

Net (loss) income

 

$

(13,798

)

$

(409

)

$

(14,917

)

$

15,326

 

$

(13,798

)

 

109



Table of Contents

 

MXENERGY HOLDINGS INC.

Consolidating Statement of Cash Flows

Year Ended June 30, 2009

(in thousands)

 

 

 

MXenergy

 

Non-
Guarantor

 

Guarantor

 

 

 

 

 

 

 

Holdings Inc.

 

Subsidiary

 

Subsidiaries

 

Eliminations

 

Consolidated

 

Operating activities:

 

 

 

 

 

 

 

 

 

 

 

Net income (loss)

 

$

(100,201

)

$

(295

)

$

(96,993

)

$

97,288

 

$

(100,201

)

Adjustments to reconcile net (loss) income to net cash provided by (used in) operating activities:

 

 

 

 

 

 

 

 

 

 

 

Unrealized losses from risk management activities

 

 

 

87,575

 

 

87,575

 

Stock compensation expense

 

 

 

519

 

 

519

 

Depreciation and amortization

 

 

31

 

37,544

 

 

37,575

 

Deferred tax benefit

 

 

 

(23,406

)

 

(23,406

)

Non-cash interest expense, primarily unrealized losses on interest rate swaps and amortization of deferred financing fees

 

3,694

 

 

12,539

 

 

16,233

 

Amortization of customer contracts acquired

 

 

 

(634

)

 

(634

)

Equity in operations of consolidated subsidiaries

 

97,288

 

 

 

(97,288

)

 

Changes in assets and liabilities, net of effects of acquisitions

 

 

 

 

 

 

 

 

 

 

 

Restricted cash

 

 

 

(74,781

)

 

(74,781

)

Accounts receivable

 

(18,944

)

(28

)

40,103

 

18,944

 

40,075

 

Natural gas inventories

 

 

 

36,509

 

 

36,509

 

Income taxes receivable

 

1,063

 

 

1,063

 

(1,063

)

1,063

 

Option Premiums

 

 

 

1,571

 

 

1,571

 

Other assets

 

(1,278

)

350

 

(19,581

)

 

(20,509

)

Accounts payable, accrued commodity purchases and accrued liabilities

 

(974

)

(825

)

(46,236

)

1,482

 

(46,553

)

Deferred revenue

 

 

 

(3,164

)

 

(3,164

)

Net cash (used in) provided by operating activities

 

(19,352

)

(767

)

(47,372

)

19,363

 

(48,128

)

 

 

 

 

 

 

 

 

 

 

 

 

Investing activities:

 

 

 

 

 

 

 

 

 

 

 

Long-term investments

 

19,363

 

 

 

(19,363

)

 

Purchase of Catalyst assets

 

 

 

(1,609

)

 

(1,609

)

Customer acquisition costs

 

 

59

 

(15,402

)

 

(15,343

)

Purchases of fixed assets

 

 

 

(1,001

)

 

(1,001

)

Net cash provided by (used in) investing activities

 

19,363

 

59

 

(18,012

)

(19,363

)

(17,953

)

 

 

 

 

 

 

 

 

 

 

 

 

Financing activities:

 

 

 

 

 

 

 

 

 

 

 

Proceeds from Denham Credit Facility

 

 

 

12,000

 

 

12,000

 

Proceeds from cash advances under Revolving Credit Facility

 

 

 

30,000

 

 

30,000

 

Repayment of cash advances under Revolving Credit Facility

 

 

 

(30,000

)

 

(30,000

)

Proceeds from Revolving Credit Facility Bridge Financing)

 

 

 

10,400

 

 

10,400

 

Repurchase of Revolving Credit Facility Bridge Financing

 

 

 

(5,000

)

 

(5,000

)

Purchase and cancellation of treasury shares, net of tax benefit

 

(11

)

 

 

 

(11

)

Net cash provided by financing activities

 

(11

)

 

17,400

 

 

17,389

 

 

 

 

 

 

 

 

 

 

 

 

 

Net decrease in cash and cash equivalents

 

 

(708

)

(47,984

)

 

(48,692

)

Cash and cash equivalents at beginning of period

 

 

970

 

70,988

 

 

71,958

 

Cash and cash equivalents at end of period

 

$

 

$

262

 

$

23,004

 

$

 

$

23,266

 

 

110



Table of Contents

 

MXENERGY HOLDINGS INC.

Consolidating Statement of Cash Flows

Year Ended June 30, 2008

(dollars in thousands)

 

 

 

MXenergy

 

Non-
Guarantor

 

Guarantor

 

 

 

 

 

 

 

Holdings Inc.

 

Subsidiary

 

Subsidiaries

 

Eliminations

 

Consolidated

 

Operating activities:

 

 

 

 

 

 

 

 

 

 

 

Net income (loss)

 

$

24,793

 

$

(36

)

$

27,620

 

$

(27,584

)

$

24,793

 

Adjustments to reconcile net income (loss) to net cash (used in) provided by operating activities:

 

 

 

 

 

 

 

 

 

 

 

Unrealized losses (gains) from risk management activities

 

 

 

(67,168

)

 

(67,168

)

Stock compensation expense

 

 

 

1,704

 

 

1,704

 

Depreciation and amortization

 

 

36

 

32,662

 

 

32,698

 

Deferred income tax expense (benefit)

 

 

 

18,187

 

 

18,187

 

Non-cash interest expense, primarily unrealized losses on interest rate swaps and amortization of deferred financing fees

 

3,290

 

 

7,546

 

 

10,836

 

Amortization of customer contracts acquired

 

 

 

(762

)

 

(762

)

Equity in operations of consolidated subsidiaries

 

(27,584

)

 

 

27,584

 

 

Changes in assets and liabilities, net of effects of acquisition:

 

 

 

 

 

 

 

 

 

 

 

Restricted cash

 

 

 

463

 

 

463

 

Accounts receivable

 

(98,687

)

93

 

(30,274

)

98,687

 

(30,181

)

Natural gas inventories

 

 

 

(7,308

)

 

(7,308

)

Income taxes receivable

 

(7,173

)

 

(7,173

)

7,173

 

(7,173

)

Option premiums

 

 

 

1,191

 

 

1,191

 

Other assets

 

1,343

 

(194

)

(540

)

 

609

 

Accounts payable, accrued commodity purchases and accrued liabilities

 

20,330

 

981

 

(3,429

)

 

17,882

 

Deferred revenue

 

 

 

(4,352

)

 

(4,352

)

Net cash (used in) provided by operating activities

 

(83,688

)

880

 

(31,633

)

105,860

 

(8,581

)

 

 

 

 

 

 

 

 

 

 

 

 

Investing activities:

 

 

 

 

 

 

 

 

 

 

 

Long-term investments

 

105,860

 

 

 

(105,860

)

 

Loan to PS Energy Group Inc. related to purchase of GasKey

 

 

 

(8,983

)

 

(8,983

)

Cash received from PS Energy Group, Inc. for repayment of loan

 

 

 

8,983

 

 

8,983

 

Purchase of GasKey assets

 

 

 

(12,427

)

 

(12,427

)

Customer acquisition costs

 

 

(47

)

(19,508

)

 

(19,555

)

Purchases of fixed assets

 

 

 

(1,959

)

 

(1,959

)

Net cash provided by (used in) investing activities

 

105,860

 

(47

)

(33,894

)

(105,860

)

(33,941

)

 

 

 

 

 

 

 

 

 

 

 

 

Financing activities:

 

 

 

 

 

 

 

 

 

 

 

Repayment of Denham Credit Facility

 

(11,040

)

 

 

 

(11,040

)

Repurchase of senior notes

 

(11,716

)

 

(290

)

 

(12,006

)

Issuance of common stock and exercise of warrants and options

 

387

 

 

 

 

387

 

Issuance of common stock from other executive compensation

 

952

 

 

 

 

952

 

Purchase and cancellation of treasury shares, net of tax benefit

 

(755

)

 

 

 

(755

)

Net cash used in financing activities

 

(22,172

)

 

(290

)

 

(22,462

)

Net increase (decrease) in cash

 

 

833

 

(65,817

)

 

(64,984

)

Cash and cash equivalents at beginning of year

 

 

137

 

136,805

 

 

136,942

 

Cash and cash equivalents at end of year

 

$

 

$

970

 

$

70,988

 

$

 

$

71,958

 

 

111



Table of Contents

 

MXENERGY HOLDINGS INC.

Consolidating Statement of Cash Flows

Year Ended June 30, 2007

(dollars in thousands)

 

 

 

MXenergy

 

Non-
Guarantor

 

Guarantor

 

 

 

 

 

 

 

Holdings Inc.

 

Subsidiary

 

Subsidiaries

 

Eliminations

 

Consolidated

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating activities:

 

 

 

 

 

 

 

 

 

 

 

Net (loss) income

 

$

(13,798

)

$

(409

)

$

(14,917

)

$

15,326

 

$

(13,798

)

Adjustments to reconcile net loss to net cash (used in) provided by operating activities:

 

 

 

 

 

 

 

 

 

 

 

Unrealized losses from risk management activities

 

 

 

17,079

 

 

17,079

 

Stock compensation expense

 

 

 

4,539

 

 

4,539

 

Depreciation and amortization

 

 

91

 

27,639

 

 

27,730

 

Deferred income tax benefit

 

 

 

(14,449

)

 

(14,449

)

Non-cash interest expense, primarily unrealized losses on interest rate swaps and amortization of deferred financing fees

 

(3,144

)

 

11,050

 

 

7,906

 

Amortization of customer contracts acquired

 

 

 

11,891

 

 

11,891

 

Equity in operations of consolidated subsidiaries

 

15,326

 

 

 

(15,326

)

 

Changes in assets and liabilities, net of effects of acquisition:

 

 

 

 

 

 

 

 

 

 

 

Restricted cash

 

 

 

(623

)

 

(623

)

Accounts receivable, net

 

(208,155

)

(147

)

177,964

 

33,791

 

3,453

 

Natural gas inventories

 

 

 

(1,712

)

 

(1,712

)

Income taxes receivable

 

5,184

 

 

5,184

 

(5184

)

5,184

 

Option premiums

 

 

 

1,835

 

 

1,835

 

Other assets

 

(1,627

)

(69

)

703

 

 

(993

)

Accounts payable, accrued commodity purchases and accrued liabilities

 

14,177

 

620

 

41,646

 

(24,888

)

31,555

 

Deferred revenue

 

 

 

9,384

 

 

9,384

 

Net cash (used in) provided by operating activities

 

(192,037

)

86

 

277,213

 

3,719

 

88,981

 

 

 

 

 

 

 

 

 

 

 

 

 

Investing activities:

 

 

 

 

 

 

 

 

 

 

 

Long-term investments

 

3,719

 

 

 

(3,719

)

 

Purchase of SESCo assets

 

 

 

(126,044

)

 

(126,044

)

Deposit and capitalized costs related to purchase of SESCo assets

 

3,348

 

 

 

 

3,348

 

Purchase of Vantage assets

 

 

 

(732

)

 

(732

)

Customer acquisition costs

 

 

(95

)

(7,515

)

 

(7,610

)

Purchases of fixed assets

 

 

 

(1,882

)

 

(1,882

)

Net cash used in investing activities

 

7,067

 

(95

)

(136,173

)

(3,719

)

(132,920

)

 

 

 

 

 

 

 

 

 

 

 

 

Financing activities:

 

 

 

 

 

 

 

 

 

 

 

Proceeds from Denham Credit Facility

 

11,040

 

 

12,000

 

 

23,040

 

Repayment of Denham Credit Facility

 

 

 

(12,000

)

 

(12,000

)

Proceeds from loans

 

 

 

6,000

 

 

6,000

 

Repayments of loans

 

 

 

(6,000

)

 

(6,000

)

Debt financing costs

 

 

 

(9,345

)

 

(9,345

)

Proceeds from bridge loan

 

 

 

190,000

 

 

190,000

 

Repayment of bridge loan

 

 

 

(190,000

)

 

(190,000

)

Proceeds from Senior Notes

 

174,364

 

 

10,886

 

 

185,250

 

Repurchase of Senior Notes

 

 

 

(11,723

)

 

(11,723

)

Issuance of common stock and exercise of warrants and options

 

22

 

 

 

 

22

 

Purchase and cancellation of treasury shares, net of tax benefit

 

(456

)

 

 

 

(456

)

Net cash provided by financing activities

 

184,970

 

 

(10,182

)

 

174,788

 

Net (decrease) increase in cash and cash equivalents

 

 

(9

)

130,858

 

 

130,849

 

Cash and cash equivalents at beginning of year

 

 

146

 

5,947

 

 

6,093

 

Cash and cash equivalents at end of year

 

$

 

$

137

 

$

136,805

 

$

 

$

136,942

 

 

112



Table of Contents

 

ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

 

None.

 

ITEM 9A(T).  CONTROLS AND PROCEDURES

 

Disclosure Controls

 

We maintain a system of internal control over financial reporting 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 this Annual Report.  Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures were not effective, as of the end of the period covered by this 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 control 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 this 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 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:

 

·      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 a few 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.  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 have 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 have been, or will be, put into place with the intent to mitigate the risk of potential future misstatements from the identified significant deficiencies.

 

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Other than the remediation steps described above, there have been no changes in our system of internal control over financial reporting during the year ended June 30, 2009, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

Section 404 of the Sarbanes-Oxley Act of 2002 requires management to report on, and external auditors to attest to, the effectiveness of our internal control structure and procedures for financial reporting.  Management’s report on internal control over financial reporting is included on the following page of this Annual Report.

 

This Annual Report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting.  Management’s report was not subject to attestation by our registered public accounting firm pursuant to temporary rules of the SEC that permit us to provide only management’s report in this Annual Report.

 

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Report of Management on Internal Control over Financial Reporting

 

October 13, 2009

 

Management is responsible for establishing and maintaining an adequate internal control structure and procedures over financial reporting as defined in Rule 13a-15f of the Securities and Exchange Act of 1934, as amended, and has completed an assessment of the effectiveness of MXenergy Holdings Inc.’s (the “Company’s”) internal control over financial reporting as of June 30, 2009.  In making this assessment, management used the criteria related to internal control over financial reporting described in “Internal Control — Integrated Framework” established by the Committee of Sponsoring Organizations of the Treadway Commission.

 

In connection with the audit of our financial statements for the fiscal year ended June 30, 2009, we reported to the Audit Committee of our Board of Directors that certain significant deficiencies in internal controls over financial reporting existed at June 30, 2009 that, when evaluated in the aggregate, we concluded to be a material weakness in the design and operation of internal control over financial reporting at June 30, 2009.  Therefore, we have concluded that, as of June 30, 2009, the Company’s internal control over financial reporting was not effective.

 

/s/ JEFFREY A. MAYER

 

Jeffrey A. Mayer

 

President and Chief Executive Officer

 

(Principal executive officer)

 

 

 

 

 

/s/ CHAITU PARIKH

 

Chaitu Parikh

 

Chief Financial Officer

 

(Principal financial officer and principal accounting officer)

 

 

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ITEM 9B. OTHER INFORMATION

 

None

 

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PART III.

 

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

 

Executive Officers and Directors

 

On June 30, 2009 and prior to the consummation of the Restructuring, our Board of Directors consisted of eight members.  As of September 29, 2009, our Board of Directors consists of nine members.  All of our executive officers serve at the discretion of our Board of Directors, subject to their employment agreements described under “Item 11. Executive Compensation.”

 

The names and positions of our executive officers as of June 30, 2009 and following the consummation of the Restructuring, and the directors prior to the consummation of the Restructuring are presented in the following table.  Descriptions of the business experience of our executive officers and directors follow the table.

 

Name

 

Age

 

Position

 

 

 

 

 

Jeffrey A. Mayer

 

57

 

President, Chief Executive Officer and Director

Steven Murray

 

49

 

Chief Operating Officer and Director

Carole R. (“Robi”) Artman-Hodge

 

58

 

Executive Vice President and Director

Chaitu Parikh

 

40

 

Vice President and Chief Financial Officer

Robert Blake

 

53

 

Vice President, Electricity Operations & Regulatory Affairs

Gina Goldberg

 

51

 

Vice President, Marketing

Robert Werner

 

53

 

Vice President, Supply

Daniel Bergstein

 

66

 

Director

Michael J. Hamilton

 

62

 

Director

William Landuyt

 

53

 

Director

Stuart Porter

 

43

 

Director

John Stewart

 

67

 

Director

 

Jeffrey A. Mayer is a co-founder of the Company and has been President and Chief Executive Officer since 1999.  He has served as a director of Holdings since 2005. From 1992 to 1999, Mr. Mayer worked for Sempra Trading Corporation, a subsidiary of Sempra Energy (prior to 1997, known as AIG Trading Corporation, a subsidiary of AIG), and served as its Managing Director in charge of natural gas derivatives marketing.  While at Sempra, he worked on the launch of a retail energy marketing joint venture.  Prior to joining AIG, Mr. Mayer worked at Goldman, Sachs & Co. where he managed the Energy Futures Department from 1989 to 1992, worked in the Futures Services Department from 1987 to 1989 and served as Chief Counsel of its J. Aron Commodities Division from 1984 to 1987.  Mr. Mayer developed the Energy Traders Institute, a seminar on risk management sponsored by Infocast and heard by dozens of utilities and energy producers in North America.  Mr. Mayer has provided consulting services to Northeast Utilities and the Chicago Board of Trade Clearing Corporation.  Mr. Mayer serves as Chairman of the Board of Finance of Westport, CT, an elected office in which he serves as chairman of the town’s municipal pension plans, reviews budgets and votes on the tax rate.  Mr. Mayer served as Chairman of AIG Clearing Corporation, the futures clearing arm of AIG Trading, and Chairman of AIG Securities Corporation, the securities affiliate of AIG Trading.

 

Steven Murray has been Chief Operating Officer of the Company since August 2006 and has served as a director of Holdings from 2006 until September 2009.  Previously, Mr. Murray had a 25-year career with the Royal Dutch Shell group of companies, where he most recently served as Chief Executive Officer of SESCo from 2001 to August 2006 and as First President and Chief Executive Officer of Shell Trading US Co. from 1998 to 2001.  He served as General Manager of Higher Olefins and Derivatives Businesses of Shell Chemical LP since December 2005, where he oversaw marketing activity in over 50 countries, operations for plants located in the United States, the United Kingdom, New Zealand and South Africa, as well as research and development activities in North America and The Netherlands.  Mr. Murray has previously served as Vice Chairman of the National Energy Marketers Association as well as a member of the board of the Soapers and Detergents Association.

 

Carole R. (“Robi”) Artman-Hodge is a co-founder of the Company, has been Executive Vice President of the Company since 1999, and served as Chief Operating Officer from 1999 to August 2006.  She served as a director of Holdings from 2005 until September 2009. Prior to co-founding the Company, Ms. Artman-

 

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Hodge worked as senior managing director of the Project Finance unit of Bank of Ireland from 1997 to 1998, senior managing director of Risk Management and Origination for the Natural Resources unit of ING from 1989 to 1996, senior managing director of the Commodity Finance and Treasury Marketing unit of Banque Paribas from 1981 to 1989 and Assistant Treasurer of the international banking unit of Harris Bank from 1977 to 1981.

 

Chaitu Parikh has been Chief Financial Officer and Vice President of Finance of the Company since July 2004 and serves as its Principal Accounting Officer and Assistant Treasurer.  Mr. Parikh served as Vice President of Finance of the Company from December 2002 to July 2004.  Prior to joining the Company, Mr. Parikh served as Vice President and Controller of The New Power Company from October 2001 to December 2002 and as the Chief Financial Officer of Alliance Energy Services from December 1996 to July 2001.  Previously, Mr. Parikh served in public accounting with KPMG from 1991 to 1996.  Mr. Parikh holds a CA designation from the Canadian Institute of Chartered Accountants.

 

Robert Blake has been Vice President of Electricity Operations & Regulatory Affairs of the Company since June 2004.  Mr. Blake served as Vice President of Customer Operations for the Company from April 2001 to May 2004.  Prior to joining the Company, Mr. Blake served as Manager of United Energy from January 2000 to March 2001, and served as Regional Sales Director for Conectiv Energy from April 1998 to January 2000.  From 1980 to March 1998, Mr. Blake worked for United Illuminating, an electric utility in Connecticut, where he served as Director of Commercial & Industrial Energy Services.  He has been involved with numerous national and regional electricity and energy committees and has held leadership positions with several regional energy groups, including chairing a NEPOOL task force.

 

Gina Goldberg has served as Vice President of Sales and Marketing of the Company since February 2004.  Prior to joining the Company as a consultant in November 2003, Ms. Goldberg held various marketing positions at Showtime Networks Inc. from 1984 to 2003, including the position of Senior Vice President of Marketing from 1998 to 2003.  Ms. Goldberg also served as a member of the Viacom Inc. Marketing Board Council from 1998 to 2003.  Previously, Ms. Goldberg worked in the Marketing Department of The Dallas Morning News from 1981 to 1984.

 

Robert Werner has been Vice President of Supply of the Company since August 2006.  Prior to joining the Company, Mr. Werner had a 28-year career with Royal Dutch Shell in energy trading, supply chain management, and pipeline engineering and operations.  From 2002 to 2006, Mr. Werner served as Vice President of Supply for SESCo, responsible for natural gas supply, commodity price exposure management and pricing.  Prior to completing a two-year assignment in trading process and systems redesign in 2002, Mr. Werner spent 14 years in a variety of roles trading crude oil in the United States, Africa, Europe and South America.  Mr. Werner has an M.B.A. from the University of Houston and a B.S. in Mechanical and Aerospace Engineering from Princeton University.  Mr. Werner is a retired professional engineer in the State of California.

 

Daniel Bergstein served as a director of Holdings and the Company from 2000 until September 2009.  Since 1988, Mr. Bergstein has been an attorney in the New York office of the international law firm Paul, Hastings, Janofsky & Walker LLP, where he is the Chairman of the firm’s global Telecommunications and Media practice.  Mr. Bergstein is also a co-founder of Cequel III LLC and a director of Cequel Communications, LLC, the 8th largest cable company in the United States.  He is also an advisory board member of Catalyst Investors I and II, L.P., two private equity investment funds specializing in telecom and media investments, a board member of SR. Teleperformance, S.A., a Paris stock exchange listed company, and a trustee and board member of The Foundation Fighting Blindness.

 

Michael J. Hamilton was elected as a director of Holdings on March 27, 2008, and currently serves as the Chairman of the Audit Committee.  Mr. Hamilton currently served as Chairman and Chief Executive Officer of MMC Energy, Inc., a publicly traded merchant electricity generator that owns several generating units in California, until September 2009.  Previously, Mr. Hamilton was the partner in charge of utility audit and tax at PricewaterhouseCoopers until he retired in 2003.  He served as a senior managing director at FTI Consulting where he specialized in bankruptcy and restructuring work,

 

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primarily in the merchant power industry.  Mr. Hamilton is a certified public accountant with an additional certification in business valuation and is a certified turnaround professional.

 

William Landuyt currently serves as a director of Holdings and has served as a director of the Company since 2004.  Mr. Landuyt currently serves as a member of the Audit Committee.  Mr. Landuyt is a senior partner at Charterhouse Group, Inc., a position he has held since December 2003.  From October 1996 to July 2003, Mr. Landuyt served as the Chief Executive Officer and Chairman of the Board of Millennium Chemicals, Inc.  Mr. Landuyt was previously employed by Hanson Industries where he served as President and Chief Executive Officer from June 1995 to October 1996.  Mr. Landuyt held the positions of Finance Director of Hanson Plc from 1992 to May 1995 and Director of Hanson Plc from 1992 to October 1996.  Mr. Landuyt served as Vice President and Chief Financial Officer of Hanson Industries from 1988 to 1992.

 

Stuart Porter currently serves as a director of Holdings and has served as a director of the Company since 2000.   Mr. Porter currently serves as a member of the Compensation Committee.  Since June 2007, Mr. Porter has been a principal of Denham Capital Management LP, and serves as Chief Investment Officer for the Denham Commodity Partners Funds.  From 2004 to 2007, Mr. Porter was a managing director at Sowood Capital Management LP and, during that period, managed the Sowood Commodity Partners Funds.  From 1996 to July 2004, Mr. Porter was employed as a Vice President and Portfolio Manager at Harvard Management Company, Inc. where he focused on relative value transactions in commodities and structured private transactions in the commodity sector.

 

John Stewart served as a director of Holdings and the Company from 2000 until September 2009.  Mr. Stewart has been an attorney in private practice since 1981.  Mr. Stewart serves on the board of directors of P&B Woodworking and the Amity Art Foundation.  In addition, Mr. Stewart serves as the chairman of the Library Commission of Woodbridge, Connecticut.

 

In connection with the Restructuring, the Company’s Board of Directors was re-organized.  The names of the Company’s current directors are presented in the following table.  Descriptions of the business experience of all new directors follow the table.

 

Name

 

Age

 

Position

 

 

 

 

 

Mark Bernstein

 

39

 

Director

James Chapman

 

47

 

Director

Michael Goldstein

 

50

 

Director

Michael J. Hamilton

 

62

 

Director

William Landuyt

 

53

 

Director

Randal T. Maffett

 

49

 

Director

Jeffrey A. Mayer

 

57

 

President, Chief Executive Officer and Director

Jonathan Moore

 

49

 

Director

Stuart Porter

 

43

 

Director

 

Mark Bernstein is Chief Investment Officer of Private Investment X, LLC, a Houston based private equity firm he founded in 2009 to acquire upstream assets in the oil and gas industry.  From 2006 until 2008, Mr. Bernstein served as Vice President of Constellation Energy Group, Inc., where he focused on upstream principal investments. In 2005, Mr. Bernstein consulted for Davis Petroleum Corp. regarding the establishment of the company’s risk management operations and recapitalization efforts.  From 2002 until 2004, Mr. Bernstein was a founding principal of National Bank of Canada’s global risk management group in Houston.  From 1996 until 2001, Mr. Bernstein was a Director at Enron Corp., working in the wholesale power division until 2001 when his focus changed to Enron Energy Services, a retail electricity provider.  In 1995, Mr. Bernstein worked for Banc One Corp.

 

James Chapman is non-executive Vice Chairman of SkyWorks Leasing, LLC, an aircraft management services company based in Greenwich, Connecticut, which he joined in December 2004.  From 2003 until 2004, Mr. Chapman was associated with Regiment Capital Advisors, LP, an investment advisor based in Boston specializing in high yield investments.  From 2001 until 2003, Mr. Chapman acted as a capital markets and strategic planning consultant with private and public companies, as well as investment advisers and hedge funds, across a range of industries.  From 1996 to 2001, Mr. Chapman worked for The Renco

 

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Group, Inc., a multi-billion dollar private corporation located in New York City.  From 1990 to 1996, Mr. Chapman was a founding principal of Fieldstone Private Capital Group, where he headed the Corporate Finance and High Yield Finance Groups.  From 1985 to 1990, Mr. Chapman worked for Bankers Trust Company, most recently in their BT Securities capital markets area.  Mr. Chapman currently serves as chair of the Company’s Compensation Committee.

 

Mr. Chapman presently serves as a member of the Board of Directors of AerCap Holdings NV, Scottish Re Group Limited, Tembec Inc., American Media, Inc., Chrysler LLC and LNR Property Corporation.  Mr. Chapman is also a Board member of several private companies, and serves on the Finance Committee of The Whitby School in Greenwich.

 

Michael Goldstein has been Senior Managing Director & General Counsel of RBS Sempra Commodities since 1997, where, as chief legal counsel, he regularly advises on energy and metals commodities and derivatives transactions, product development and marketing, trade contract negotiations, regulatory and compliance issues, litigation and commercial disputes and day-to-day operations (trading, credit and back office issues).  Mr. Goldstein is also a member of the firm’s Executive Committee.  Prior to his position at RBS Sempra Commodities, Mr. Goldstein was the Deputy General Counsel for AIG Trading Group and before that, an Associate with the law firms of Paul, Weiss, Rifkind, Wharton & Garrison and Milbank, Tweed, Hadley and McCloy, both located in New York City.  Mr. Goldstein is a member of the New York Bar and is an Authorized House Counsel in Connecticut.  Mr. Goldstein currently serves on the Company’s Compensation Committee.

 

Randal T. Maffett founded Sendero Capital Partners, Inc. (“Sendero”) in 2004 and is currently serving as its President and CEO.  Sendero is a private equity firm focused on investments, acquisitions and operations in the upstream and midstream sectors of the oil and gas industry.  From 2002 until 2004, Mr. Maffett head of the newly formed North American business development group of RWE AG.  When RWE AG decided to exit the North American energy market in 2003, Mr. Maffett was retained to liquidate the company’s U.S. assets.  From 1993 until 2002, Mr. Maffett was responsible for multiple business units, including Enron North America, Enron International, Enron Strategic Ventures and Enron Global Markets, as well as for Enron’s corporate restructuring group where he focused on restructuring under-performing assets and companies, both public and private.  During his years at Enron, Mr. Maffett represented Enron’s interests on numerous domestic and international boards.  From 1989 until 1993, Mr. Maffett managed fuel requirements, long-term supply contract negotiation and power marketing for Altresco Financial, Inc., a company involved power cogeneration.  From 1987 until 1989, Mr. Maffett built and managed the deregulated gas marketing and trading business of Ladd Petroleum.  Mr. Maffett currently serves on the Company’s Audit and Compensation Committees.

 

Jonathan Moore has served as Executive Vice President at Beowulf Energy since 2008.  Beowulf Energy is a leading strategic investor in the power industry.   In 2006, Mr. Moore founded Juice Energy, Inc., a green-focused energy retailer, where he served as CEO from 2006 until 2008.  From 2002 until 2006, Mr. Moore was COO of Constellation NewEnergy (“Constellation”).  Under Mr. Moore’s leadership, NewEnergy grew into the nation’s largest competitive supplier of electricity.  From 1994 until 2002, Mr. Moore worked for The AES Corporation (“AES”), where he was part of the senior management team that led AES’s acquisition of NewEnergy Ventures, which was one of the first companies to offer electricity to commercial and industrial customers in deregulated markets.   In 2002, Mr. Moore was part of the team that negotiated the sale of AES’s retail electricity business to Constellation Energy Group.  Mr. Moore worked as a transactional attorney with O’Melveny & Myers in Washington, D.C. from 1988 to 1994.

 

Committees of the Board of Directors

 

Prior to October 2009, our Board of Directors had appointed four committees to help carry out its duties: the Audit Committee, the Compensation Committee, the Risk Oversight Committee and the Nominating and Governance Committee.

 

The Audit Committee makes recommendations to the Board of Directors regarding the selection of independent auditors, reviews the results and scope of audit and other services provided by our independent auditors and reviews and evaluates our internal audit and control functions.  Prior to the consummation of the Restructuring, the Audit Committee consisted of Messrs. Hamilton (Chair), Bergstein and Landuyt.  The Board of Directors had determined that Messrs. Hamilton and Landuyt qualified as Audit Committee financial experts within the meaning of the SEC rules.

 

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As of September 29, 2009 the Audit Committee consists of Messrs. Hamilton (Chair), Landuyt and Maffett.  The Board of Directors has determined that Messrs. Hamilton and Landuyt qualify as financial experts within the meaning of the SEC rules.

 

The Compensation Committee administers our employee stock and other benefit plans and makes decisions concerning salaries and incentive compensation for our employees.  Prior to the consummation of the Restructuring, the Compensation Committee consisted of Messrs. Bergstein (Chair), Landuyt and Porter.  As of October 12, 2009 the replacement Compensation Committee consists of Messrs Chapman (Chair), Goldstein, Hamilton, Maffett and Porter.

 

The Nominating and Governance Committee identifies and recommends qualified individuals to serve as board and committee members, monitors the effectiveness of the Board of Directors and its committees and establishes the corporate governance guidelines for the Company.  Prior to the consummation of the Restructuring, the Nominating and Governance Committee consisted of Messrs. Porter (Chair), Bergstein and Landuyt.  As of October 12, 2009 the replacement members of the Nominating and Governance Committee have not been appointed by the Board of Directors.

 

The Risk Oversight Committee establishes and provides oversight of the Company’s risk management policies.  Prior to consummation of the Restructuring, the Risk Oversight Committee consisted of Messrs. Porter (Chair), Hamilton, Mayer, Murray and Parikh and Ms. Artman-Hodge.  As of October 12, 2009, the replacement members of the Risk Oversight Committee have not been appointed by the Board of Directors.

 

Code of Ethics

 

We have adopted a Code of Business Conduct and Ethics (the “Code of Ethics”), which applies to our directors, officers and employees that meets the definition of a code of ethics required by Item 406 of Regulation S-K promulgated under the Exchange Act.  The purpose of the Code of Ethics is to promote a culture of honesty, integrity and respect for the law and the people who work at and with the Company.  A copy of the Code of Ethics is available on our website at www.mxholdings.com under the Corporate Governance link.  We intend to timely disclose any amendments to or waivers of certain provisions of the Code of Ethics applicable to our directors, executive officers, including our principal executive officer, principal financial officer and principal accounting officer on our website.

 

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ITEM 11. EXECUTIVE COMPENSATION

 

Compensation Committee Report

 

Only one member (Mr. Stuart Porter) of the Compensation Committee that administered our employee stock and other benefit plans and made decisions concerning salaries and incentive compensation for our employees during fiscal year 2009 transitioned to the new Compensation Committee appointed by the Board of Directors after the consummation of the Restructuring.  The new Compensation Committee has reviewed and discussed with management the following “Compensation Discussion and Analysis,” (“CD&A”) section required by Item 402(b) of Regulation S-K promulgated under the Exchange Act.  Based on such review and discussion with management, Mr. Porter recommended to the Board of Directors that the CD&A be included in the Company’s Annual Report.  The remaining members of the current Compensation Committee have elected to abstain from making such recommendation because they were not members of the Compensation Committee during fiscal year 2009.

 

The information contained in the Compensation Committee Report shall not be deemed to be “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filings under the Securities Act or the Exchange Act, except to the extent that we specifically incorporate it by reference in such filing.

 

Compensation Discussion and Analysis for Named Executive Officers

 

As used herein, “named executive officers” refers to our principal executive officer (the “CEO”), our chief financial officer and principal financial officer (the “CFO”) and the three executive officers, other than the CEO and CFO, who were our most highly compensated executive officers for the fiscal year ended June 30, 2009.

 

Overview of Our Compensation Philosophy and Objectives

 

The compensation of our named executive officers is based in part on the terms of our employment agreements with them and in part on our “pay-for-performance” philosophy on both an individual and corporate level.  We have adopted an approach to compensation that includes a mix of short-term and long-term components that are designed to provide proper incentives and to reward our senior management team for individual and corporate performance.

 

Our intent regarding the compensation of our executive officers is to provide salary and incentives that:

 

·               attract and retain talented and experienced executives;

·               motivate our executives to manage our business to meet our short-term and long-term business objectives;

·               motivate the executives to increase shareholder value; and

·               associate compensation with the achievement of certain short-term and long-term individual and corporate objectives.

 

Role of Our Compensation Committee

 

Our Compensation Committee is responsible for administering our compensation practices. Our Compensation Committee consists of five directors who are “outside directors” for purposes of Section 162(m) of the Internal Revenue Code, as amended (the “Code”).

 

The Compensation Committee has been charged by the Board of Directors with the following overall responsibilities.

 

·                  Approval and evaluation of executive officer compensation policies, plans, and programs;

·                  Approval, oversight and evaluation of equity-based compensation plans, including without limitation, stock-based compensation plans, in which officers or employees may participate;

 

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·                  Arrangements with executive officers relating to their employment relationships with the Company, including, without limitation, employment agreements and restrictive covenants;

·                  Review and approval of ERISA and other significant employee benefit plans.

 

The Compensation Committee considers compensation recommendations from our CEO in determining executive compensation for all of the named executive officers, except in the case of the CEO.  The Compensation Committee, at its sole discretion, may accept or deny, in whole or in part, the recommendations of the CEO.  The activities of the Compensation Committee are formally reported to the Board of Directors, and board members are encouraged to ask questions and review specific details regarding the decisions of the Compensation Committee.  The Board of Directors is not required to approve the decisions of the Compensation Committee.

 

Elements of Executive Compensation

 

The compensation of our named executive officers consists primarily of the following components.

 

Annual base salary;

Participation in incentive-based compensation plans;

Participation in equity-based compensation plans;

Awards of any special or supplemental benefits; and

Awards of severance and other termination benefits.

 

We use a mix of short-term compensation (annual base salaries and incentive-based compensation) and long-term compensation (equity-based compensation) to provide a total compensation structure that is designed to achieve our pay-for-performance philosophy and other compensation objectives.  Although the Compensation Committee has not adopted any formal guidelines for allocating total compensation between short-term and long-term portions, we believe it is important for our executive officers to have some actual or potential equity ownership to provide them with long-term incentives to improve corporate performance.

 

Our Compensation Committee members are involved with a portfolio of companies of various sizes from which they can assess the appropriateness of executive compensation levels.  In addition, they are provided with performance data on named executives and the company’s performance both of which enable thorough decision-making.

 

Annual Cash Compensation

 

Annual Base Salary

 

We believe that a competitive base salary is a necessary element of any compensation program designed to attract and retain talented and experienced executives, and to motivate and reward executives for their overall performance.  In general, the base salaries of our named executive officers reflect:

 

·                  the initial base salaries that we negotiated with each of them at the time of their initial employment or promotion;

·                  consideration of  individual performance and increased experience;

·                  any changes in their appointed roles and responsibilities;

·                  consideration of the individuals contribution toward overall business performance;

·                  annual cost of living adjustment factors;

·                  results of any benchmarking initiatives to compare executive salaries to peer group companies;

·                  experience of the members of the Compensation Committee with executive salaries at other companies; and

·                  recommendations of the CEO, except in the case of the CEO.

 

The base salaries of our executive officers are reviewed and evaluated for possible adjustment annually after their performance evaluations are completed.

 

Base salaries for our named executive officers are summarized in the following table:

 

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Name

 

Fiscal Year
2009

 

Fiscal Year
2008

 

 

 

 

 

 

 

Jeffrey Mayer

 

$

594,825

 

$

566,500

 

Chaitu Parikh

 

421,785

 

401,700

 

Steven Murray

 

486,675

 

463,500

 

Carole R. Artman-Hodge

 

390,000

 

390,000

 

Gina Goldberg

 

281,865

 

244,963

 

 

For fiscal year 2009, the Compensation Committee approved a 5% increase for Messrs. Mayer, Parikh and Murray to keep their salaries within targeted market levels.  Ms. Goldberg received a 15% salary increase to adjust her salary to the targeted market level for her position.  Ms. Artman-Hodge did not receive a base salary increase for fiscal year 2009 because her base salary already exceeded targeted market levels for her position.

 

Annual Incentive-Based Compensation

 

Our named executive officers have the opportunity to receive cash incentive awards tied to our company’s overall performance and their individual performance.

 

Specific performance goals are established for the payment of annual incentive-based compensation, which are based on the specific individual and business performance factors described below.  The establishment of business and individual goals for each named executive officer reinforces two of our compensation goals: (1) to motivate our named executive officers toward even higher achievement and business results; and (2) to enable us to attract and retain highly qualified individuals.

 

Individual Performance Factors (“IPFs”) represent ratings assigned to the named executive officers that are based on several performance factors and accomplishment of individual goals.  IPFs are calculated after a systematic review of each named executive officer, which results in assessment of specific accomplishments and job skills that generally fall within the following categories: (1) leadership, team management and organizational skills; (2) primary job responsibilities; (3) judgment and decision-making; (4) individual attributes; (5) peer relationships; and (6) industry, departmental and company knowledge.  Mr. Mayer is graded by the Compensation Committee, while the other named executive officers are graded by his or her manager.  For all named executive officers, the overall IPF rating is applied to 25% of their target bonus.  The Compensation Committee reviews and approves IPFs for the named executive officers.

 

Business Performance Factors (“BPFs”) represent corporate operational goals that are considered to be essential to our success for the fiscal year.  BPFs are used to assess corporate performance and result in a weighted resultant business factor, which is generally assigned to all employees.  For all named executive officers, the BPF rating is applied to 75% of their target bonus.  The BPFs for the fiscal year ended June 30, 2009 were as follows:

 

·                  34% weighting for achievement of targeted levels of RCEs at June 30, 2009;

·                  33% weighting for operational excellence, which is measured by accomplishment of key business performance factors; and

·                  33% weighting for achievement of Adjusted EBITDA for fiscal year 2009.

 

The weighted resultant business factor is applied to that portion of the named executive officer’s bonus that is subject to the BPF weighting.  That cumulative result is then further adjusted for the named executive officer’s IPF rating.

 

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Incentive-based compensation accrued for the named executive officers for the fiscal year ended June 30, 2009, subject to final approval by the Compensation Committee, is summarized in the following table.

 

 

 

 

 

Actual Payout

 

 

 

Target % of

 

% of

 

 

 

Name

 

Salary (1)

 

Salary

 

Amount

 

 

 

 

 

 

 

 

 

Jeffrey Mayer

 

100

%

84

%

$

500,545

 

Chaitu Parikh

 

100

%

92

%

387,198

 

Steven Murray

 

100

%

82

%

400,000

 

Carole R. Artman-Hodge

 

100

%

49

%

190,944

 

Gina Goldberg

 

100

%

52

%

147,489

 

 


(1)   Based upon employment agreements in place as of June 30, 2009.

 

All named executive officers were awarded higher IPFs and BPFs for fiscal year 2009, as compared with the prior fiscal year, due to improved operating results.

 

Equity-Based Compensation

 

As of June 30, 2009, we have adopted, by a vote of our shareholders, three separate stock-based compensation plans pursuant to which stock options and warrants have been granted to named executive officers and to other employees.  These stock-based compensation plans are described in the footnotes to the Company’s consolidated financial statements included elsewhere in this Annual Report.  Stock-based awards provide our executive officers, employees and other individuals who have provided services to us with the right to purchase shares of our common stock at a fixed exercise price typically for a period of up to ten years, subject to continued employment with us.  These plans do not allow us to establish an exercise price that is below fair market value of our common stock on the award date.  We have granted stock options as incentive stock options in accordance with Section 422 of the Code, as well as non-qualified stock options.  In general, options granted are service-based stock options that have a three year vesting schedule and a ten year term.  In the case of options intended to qualify as incentive stock options, the exercise price for options awarded to employees who own greater than 10% of our common stock as of the date of grant is 110% of the fair market value of our common stock and the term of the option is reduced to 5 years instead of 10 years.

 

Stock options are an important component in our executive compensation program because we have benefited from dedicated employees who take ownership pride in its business.  Decisions regarding the amount and timing of stock option awards are made: (1) at the time of the executive’s employment; (2) upon periodic review; or (3) on rare occasions, following a significant event such as an acquisition.

 

The date of grant and the fair market value of the awards are approved by the Compensation Committee.  The fair value of option awards generally are equivalent to the fair value of our common stock.  Because our common stock is not publicly traded, we obtain an independent valuation of its fair value at June 30 of each fiscal year and we calculate its fair value at September 30, December 31 and March 31 of each fiscal year using an internally developed model that approximates the independent model.

 

The CEO makes recommendations to the Compensation Committee regarding the award of stock options to all named executive officers, which are based on the following considerations:  (1) the officer’s performance; (2) future responsibilities and expectations of the officer during the vesting period for the awards; (3) retention concerns, if any; (4) rating of the officer as a “top performer”; and (5) comparisons with peers within the Company.  Any grants are approved by the Compensation Committee after consideration of the CEO recommendations, its members’ knowledge of market practice, our actual performance for the current fiscal year and expectations of our future performance.  We do not make decisions regarding equity awards based on the gains or losses from prior equity awards. In addition, we do not have any formal security ownership requirements.  Generally, stock awards granted to the named executive officers vest over a three-year period with the first vesting period ending on the first anniversary of the date of grant.

 

During the fiscal year ended June 30, 2009, we did not grant any stock option awards to named executive

 

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officers.

 

Other Compensation

 

All of our executive officers are eligible for benefits generally offered to all employees, including, but not limited to; life, health, disability and dental insurance and participation in our 401(k) plan.  We intend to continue to maintain our current benefits for our executive officers, as well as for all of our employees.  The Compensation Committee may, in its sole discretion revise, amend or add to the named executive officer’s benefits and perquisites if deemed advisable. We do not believe it is necessary for the attraction or retention of management talent to provide the officers with a substantial amount of compensation in the form of perquisites.  During fiscal year 2009, in addition to matching the 401(k) contributions of all of the named executive officers, we made reimbursement payments to Messrs. Mayer and Murray for professional association and club membership fees.

 

Additionally, our executive officers may be awarded special compensation, at the sole discretion of the Compensation Committee, in recognition of extraordinary initiative or efforts related to purchase acquisitions or other transactions.  No such special compensation was awarded to any of our named executives during fiscal year 2009.

 

Accounting and Tax Considerations

 

Effective July 1, 2006, we adopted, on a prospective basis, the fair market value provisions of SFAS No. 123R.  Under SFAS No. 123R, the estimated fair value of options granted, net of forfeitures expected to occur, is amortized as compensation expense over the vesting period of the options based on the accelerated attribution method as specified in FASB Interpretation No. 28.  For additional information, see Notes 2 and 17 of our audited consolidated financial statements included elsewhere in this Annual Report.

 

We have granted stock options as incentive stock options in accordance with Section 422 of the Code subject to the volume limitations contained in the Code.  Generally, the exercise of an incentive stock option does not trigger any recognition of income or gain to the holder.  If the stock is held until at least one year after the date of exercise (or two years from the date the option is granted, whichever is later), all of the gain on the sale of the stock will be capital gain when recognized for income tax purposes, rather than ordinary income to the recipient. Consequently, we do not receive a tax deduction.  For stock options that do not qualify as incentive stock options, we are entitled to a tax deduction in the year in which the stock options are exercised equal to the spread between the exercise price and the fair market value of the stock for which the stock option was exercised. The holders of the non-qualified stock options are generally taxed on this same amount in the year of exercise.

 

Post Fiscal Year 2009 Actions

 

Restructuring Bonuses

 

In September 2009, the Company paid a total of $750,000 of bonuses to 19 of its executive officers and employees related to consummation of the Restructuring, of which the following amounts were paid to named executive officers:  Mr. Mayer: $240,000; Mr. Parikh: $240,000; and Mrs. Artman-Hodge: $30,000.

 

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Summary Compensation Table

 

Annual compensation for the named executive officers is summarized in the following table.

 

 

 

 

 

 

 

 

 

 

 

 

 

Non-

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

equity

 

 

 

 

 

 

 

 

 

 

 

Stock

 

 

 

Option

 

Incentive

 

 

 

 

 

Name and Principal

 

 

 

 

 

Awards

 

Bonus

 

Awards

 

Plan

 

All Other

 

 

 

Position

 

Year

 

Salary

 

(1)

 

(2)

 

(3)

 

(4)

 

(5)

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Jeffrey Mayer

 

2009

 

$

594,825

 

$

 

$

 

$

39,664

 

$

519,240

 

$

53,859

 

$

1,207,588

 

President and Chief Executive

 

2008

 

566,183

 

475,950

 

 

92,019

 

236,115

 

366,564

 

1,736,831

 

Officer

 

2007

 

547,745

 

 

250,000

 

87,260

 

324,500

 

13,702

 

1,223,207

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Chaitu Parikh

 

2009

 

421,785

 

 

 

87,181

 

403,768

 

16,936

 

929,670

 

Vice President and Chief

 

2008

 

401,475

 

 

 

202,261

 

202,859

 

16,189

 

822,784

 

Financial Officer

 

2007

 

389,098

 

 

200,000

 

191,799

 

253,100

 

16,500

 

1,050,497

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Steven Murray

 

2009

 

486,675

 

 

 

335,313

 

419,119

 

49,055

 

1,290,162

 

Chief Operating Officer

 

2008

 

463,180

 

 

 

777,925

 

222,406

 

37,539

 

1,501,050

 

 

 

2007

 

389,423

 

 

150,000

 

737,688

 

229,800

 

43,128

 

1,550,039

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Carole R. Artman-Hodge

 

2009

 

390,000

 

 

 

87,181

 

207,032

 

20,962

 

705,175

 

Executive Vice President

 

2008

 

390,000

 

475,950

 

 

202,261

 

180,925

 

390,086

 

1,639,222

 

 

 

2007

 

389,662

 

 

150,000

 

191,799

 

159,600

 

20,249

 

911,310

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gina Goldberg

 

2009

 

281,865

 

 

 

46,944

 

158,408

 

15,739

 

502,956

 

Vice President, Marketing

 

2008

 

244,963

 

 

 

108,910

 

117,574

 

12,255

 

483,702

 

 

 

2007

 

237,859

 

 

25,000

 

103,276

 

102,900

 

13,485

 

482,520

 

 


(1)        In March 2008, the Compensation Committee approved the issuance of 9,500 shares to both Mr. Mayer and Ms. Artman-Hodge.  The fair value of these awards was $475,950 for both Mr. Mayer and Ms. Artman-Hodge.

(2)        For Messrs. Mayer and Parikh and Ms. Artman-Hodge, the 2007 amount represents a cash bonus paid in recognition of their work in the SESCo Acquisition.  For Mr. Murray, the 2007 amount represents a sign-on bonus paid in accordance with his employment agreement.

(3)        This column reflects the compensation cost of stock options over the requisite service period as defined by SFAS No. 123R and reflects expense recognized in earnings for financial statement reporting purposes for the fiscal years ended June 30, 2009, 2008 and 2007.

(4)        Amounts include annual incentive-based compensation awards.  Amounts reflected are exclusively cash awards.

(5)        For fiscal year 2009, amounts include: (1) contributions to the Company-sponsored employee savings plan under Section 401(k) of the Code (Mr. Mayer: $22,000; Mr. Parikh: $16,936; Mr. Murray: $24,230; Ms. Artman-Hodge: $20,962; and Ms. Goldberg: $15,739); (2) club membership fees (Mr. Mayer:  $12,480; Mr. Murray: $24,825); and (3) reimbursement of legal expenses in connection with preparation of employment agreements (Mr. Mayer: $19,379).

 

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2009 Grants of Plan-Based Awards

 

We did not grant any equity-based compensation awards during the fiscal year ended June 30, 2009.  Information with respect to incentive-based compensation awards granted to named executive officers for fiscal year 2009 are summarized in the following table.

 

 

 

Estimated Future Payouts Under
Incentive Plan Awards (1)

 

All Other
Stock
Awards:
Number
of Shares

 

Grant
Date Fair
Value of
Stock

 

Name

 

Threshold

 

Target

 

Maximum

 

of Stock

 

Awards

 

 

 

 

 

 

 

 

 

 

 

 

 

Jeffrey Mayer

 

$

0

 

$

594,825

 

$

713,790

 

 

$

 

Chaitu Parikh

 

0

 

421,785

 

506,142

 

 

 

Steven Murray

 

0

 

486,675

 

486,675

 

 

 

Carole R. Artman-Hodge

 

0

 

390,000

 

390,000

 

 

 

Gina Goldberg

 

0

 

140,933

 

281,865

 

 

 

 


(1)          Amounts reflect the range of potential short-term incentive payouts under the Company’s incentive compensation program.  For fiscal year 2009 performance, the actual payout, as well as the business objectives and percentage of target achieved, are disclosed above under “Annual Cash Incentive Compensation”.

 

Outstanding Equity Awards at June 30, 2009

 

Outstanding equity awards for named executive officers as of June 30, 2009 are summarized in the following table.

 

 

 

Option Awards

 

Name

 

Number of
Securities
Underlying
Unexercised
Options/
Warrants
Exercisable

 

Number of
Securities
Underlying
Unexercised
Options/
Warrants
Unexercisable

 

Option
Exercise
Price

 

Option
Expiration
Date

 

 

 

 

 

 

 

 

 

 

 

Jeffrey Mayer

 

48,000

 

 

$

23.65

 

10/19/2009

 

Jeffrey Mayer

 

21,000

 

 

30.25

 

6/26/2010

 

Jeffrey Mayer

 

26,000

 

13,000

 

46.83

 

11/13/2011

 

Chaitu Parikh

 

7,500

 

 

8.00

 

3/19/2013

 

Chaitu Parikh

 

17,700

 

 

8.00

 

1/21/2014

 

Chaitu Parikh

 

36,000

 

 

21.50

 

10/19/2014

 

Chaitu Parikh

 

18,000

 

 

27.50

 

6/26/2015

 

Chaitu Parikh

 

26,000

 

13,000

 

42.57

 

11/13/2016

 

Steven Murray

 

100,000

 

50,000

 

42.57

 

11/13/2016

 

Carole R. Artman-Hodge

 

16,550

 

 

8.00

 

1/21/2014

 

Carole R. Artman-Hodge

 

48,000

 

 

21.50

 

10/19/2014

 

Carole R. Artman-Hodge

 

21,000

 

 

27.50

 

6/26/2015

 

Carole R. Artman-Hodge

 

26,000

 

13,000

 

42.57

 

11/13/2016

 

Gina Goldberg

 

2,500

 

 

25.00

 

2/1/2010

 

Gina Goldberg

 

2,500

 

 

33.67

 

2/1/2011

 

Gina Goldberg

 

2,500

 

 

48.74

 

2/1/2012

 

Gina Goldberg

 

1,200

 

 

8.00

 

1/21/2014

 

Gina Goldberg

 

12,000

 

 

21.50

 

10/19/2014

 

Gina Goldberg

 

15,000

 

 

27.50

 

6/26/2015

 

Gina Goldberg

 

14,000

 

7,000

 

42.57

 

11/13/2016

 

 

All outstanding equity awards in the table above were cancelled and terminated in connection with the Restructuring.  As of September 30, 2009, no named executive officers have any outstanding equity awards.

 

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Option Exercises

 

There were no options or warrants exercised by named executive officers during the fiscal year ended June 30, 2009.

 

Pension Benefits

 

We do not provide any post-retirement pension benefits to any of our named executive officers.

 

Nonqualified Deferred Compensation Plans

 

We do not provide any nonqualified deferred compensation programs for any of our named executive officers.

 

Agreements with Named Executive Officers

 

Jeffrey Mayer Employment Agreement

 

On February 13, 2008, we entered into a new employment agreement with Mr. Mayer (the “Mayer Agreement”).  The Mayer Agreement replaces a previous employment agreement dated April 1, 1999.  The material differences in the Mayer Agreement include the following:  (i) reducing both the initial and automatic renewal terms of the agreement; (ii) providing increased severance upon a termination without business reasons (and including the concept of a constructive termination); (iii) providing for severance upon a change in control in connection with a qualifying termination; and (iv) including a Code Section 280G provision, which provides for either a reduction of payments or a tax gross-up.  In each case, we included these revised terms to reflect market practices, and Mr. Mayer’s increased responsibilities and authority.

 

The initial term of the Mayer Agreement is four years and is automatically renewed for successive one-year terms unless either party gives the other 180 days’ notice that the Mayer Agreement will not be extended or if the Mayer Agreement is otherwise terminated.  Pursuant to the Mayer Agreement, Mr. Mayer’s office will be located in our headquarters in Stamford, Connecticut, and he will report to our Board of Directors.  In addition to his position as CEO, we agree to use its best efforts to ensure that Mr. Mayer will continue to serve as a member of the Board of Directors.

 

Pursuant to the Mayer Agreement, Mr. Mayer will receive an annual base salary of $566,500, which may be increased from time to time by the Compensation Committee, at its discretion.  In addition, Mr. Mayer’s annual target bonus shall be equal to 100% of his then current base salary, 75% of which is payable based on achievement of Company and/or individual objectives specified by the Compensation Committee and 25% of which may be awarded solely at the discretion of the Compensation Committee.  In addition, the Compensation Committee may, in its sole discretion, award Mr. Mayer an additional bonus of up to 20% of his base salary then in effect for extraordinary performance in connection with a significant business event.

 

In the event that Mr. Mayer is terminated involuntarily and without “business reasons” (as such term is defined in the Mayer Agreement, which generally includes “cause” events such as felony conviction, fraud or insubordination) or a “constructive termination” (as such term is defined in the Mayer Agreement, such as a material reduction in salary or authority or a relocation) occurs, Mr. Mayer will be entitled to receive (i) his then current base salary, any paid time off and any earned and unpaid target bonus accrued through the date of termination; (ii) a lump sum payment equal to the greater of (a) his then current base salary for a period of twelve months following the date of termination, or (b) his then current base salary for the remainder of the then current employment term; and (iii) a lump sum payment equal to (a) 100% of the target bonus for the fiscal year in which the date of termination occurs, (b) 100% of the target bonus for any full fiscal year remaining during the then applicable employment term, and (c) a pro rata portion of 100% of the target bonus being paid for the final fiscal year that begins during the then applicable employment term.  In addition, all of Mr. Mayer’s unvested stock options, restricted stock, and other equity awards shall become fully vested and all stock options that are vested and outstanding (but unexercised) on the date of termination will be cancelled and we will pay to Mr. Mayer, with respect to each option, an amount equal to the excess of the fair market value per share of the shares underlying such option over the exercise price

 

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of such option multiplied by the number of shares underlying such option.  In addition, Mr. Mayer’s benefits will continue for the duration of the then current employment term.

 

If there is a change in control (as such term is defined in the Mayer Agreement) and either a constructive termination occurs or we terminate Mr. Mayer’s employment without business reasons prior to the expiration of the then current employment term, Mr. Mayer will be entitled to receive (i) his then current base salary, any paid time off, and any earned and unpaid target bonus accrued through the date of termination; (ii) a lump sum payment equal to the greater of (a) two times his then current base salary or (b) his then current base salary for the remainder of the then current employment term; (iii) a lump sum payment equal to the greater of (a) 200% of the target bonus for the fiscal year in which the termination occurs, or (b) 100% of the target bonus for the fiscal year in which the termination occurs times the number of years for the remainder of the then current employment term.  In addition, all of Mr. Mayer’s unvested stock options, restricted stock, and other equity awards shall become fully vested.

 

If Mr. Mayer is terminated as a result of death or disability (as such term is defined in the Mayer Agreement), he or his representative, as the case may be, is entitled to receive (i) any accrued and unpaid salary; (ii) any accrued and unpaid target bonus for the prior fiscal year; (iii) a pro rata portion of any target bonus that he would have otherwise earned during the fiscal year in which the termination occurs; and (iv) any accrued and unpaid time off.  Mr. Mayer’s outstanding stock options, restricted stock, and other equity arrangements shall expire in accordance with the terms of the applicable award agreements.

 

If Mr. Mayer voluntarily terminates his employment (other than in the case of a constructive termination), or he is terminated involuntarily for business reasons, he will be entitled to receive (i) all accrued and unpaid salary, all accrued and unpaid target bonus for the prior fiscal year, and a pro rata portion of any target bonus that he would have otherwise earned during the fiscal year in which such termination occurs and (ii) all accrued but unpaid time off and other benefits due to him through his termination date under any Company-provided or paid plans, policies, and arrangements.  Mr. Mayer’s stock options, restricted stock, and other equity arrangements will cease vesting immediately and such awards will expire in accordance with the terms of the applicable award agreements.

 

If Mr. Mayer’s employment is terminated for any reason, we have the initial right to purchase all (but not less than all) of the common stock of the Company held by Mr. Mayer by making a written offer within 60 days of termination.  If Mr. Mayer is involuntarily terminated for any reason (including a constructive termination) other than for business reasons, but we do not offer to purchase his shares of common stock within 60 days of termination, Mr. Mayer has the right to cause us to repurchase all (but not less than all) of his common stock.  The foregoing rights terminate upon an initial public offering of our common stock.

 

The Mayer Agreement provides that in the event that Mr. Mayer becomes entitled to payments or benefits that would constitute an “excess parachute payment” within the meaning of Section 280G of the Code, the payment and/or benefits will be reduced to the extent that such payments will not be subject to the excise tax or any interest or penalties imposed by Section 4999 of the Code, referred to herein as the 280G Reduction. The 280G Reduction will only take place if Mr. Mayer’s “net after tax benefit” (as defined in the Mayer Agreement) exceeds the net after tax benefit he would realize if the 280G Reduction were not made. To the extent, the 280G Reduction is unavailable because Mr. Mayer’s net after tax benefit would be greater if the 280G Reduction were not made, we will pay Mr. Mayer a gross up payment in an amount such that after the payment by Mr. Mayer of all taxes (including any income taxes, interest, penalties or any excise taxes), Mr. Mayer would retain an amount of the gross-up payment equal to seventy-five (75%) of any excise tax imposed upon the payments received by Mr. Mayer.

 

The Mayer Agreement also contains restrictive covenants, which apply for the remainder of the then-current agreement term.  Pursuant to the restrictive covenants, Mr. Mayer is generally prohibited from (1) owning or providing services for any business competing us for the remainder of the agreement term; (2) inducing employees to leave the our employ or hiring them (unless the employee contacts Mr. Mayer on an unsolicited basis); (3) soliciting any of our customers, suppliers, licensees or other business relations; or (4) disparaging us, our executive officers, or our directors.  In the event that Mr. Mayer violates the provisions of the restrictive covenants, he will not be entitled to any severance benefits upon a termination without business reasons or upon a constructive termination.  Additionally, upon any such violation, all of Mr. Mayer’s unexercised options, whether vested or unvested, shall be cancelled.

 

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Chaitu Parikh Employment Agreement

 

On February 13, 2008, we entered into a new employment agreement with Mr. Parikh, as our Chief Financial Officer and Senior Vice President (the “Parikh Agreement”).  The Parikh Agreement replaces a previous employment agreement dated November 1, 2002.  The material differences in the Parikh Agreement include the following:  (i) providing for a specified term; (ii) providing increased severance upon a termination without business reasons (and including the concept of a constructive termination), or upon a change in control in connection with a qualifying termination; and (iii) including a Code Section 280G provision, which provides for either a reduction of payments or a tax gross-up.  In each case, we included these revised terms to reflect market practices, and Mr. Parikh’s increased responsibilities and authority.

 

The initial term of the Parikh Agreement is three years and is automatically renewed for successive one-year terms unless either party gives the other 180 days’ notice that the Parikh Agreement will not be extended or if the Parikh Agreement is otherwise terminated.  Pursuant to the Parikh Agreement, Mr. Parikh’s office will be located in our headquarters in Stamford, Connecticut, and he will report to the Company’s Board of Directors.

 

Pursuant to the Parikh Agreement, Mr. Parikh will receive an annual base salary of $401,700, which may be increased from time to time by the Compensation Committee, at its discretion.  In addition, Mr. Parikh’s annual target bonus shall be equal to 100% of his then current base salary, 75% of which is payable based on achievement of Company and/or individual objectives specified by the Compensation Committee and 25% of which may be awarded solely at the discretion of the Compensation Committee.  In addition, the Compensation Committee may, in its sole discretion, award Mr. Parikh an additional bonus of up to 20% of his base salary then in effect for extraordinary performance in connection with a significant business event.

 

In the event that Mr. Parikh is terminated involuntarily and without “business reasons” (as such term is defined in the Parikh Agreement, which generally includes “cause” events such as felony conviction, fraud or insubordination) or a “constructively termination” (as such term is defined in the Parikh Agreement, such as a material reduction in salary or authority or a relocation) occurs, Mr. Parikh will be entitled to receive (i) his then current base salary, any unpaid time off and any earned and unpaid target bonus accrued through the date of termination; (ii) a lump sum payment equal to the greater of (a) his then current base salary for a period of twelve months following the date of termination, or (b) his then current base salary for the remainder of the then current employment term; and (iii) a lump sum payment equal to (a) 100% of the target bonus for the fiscal year in which the date of termination occurs, (b) 100% of the target bonus for any full fiscal year remaining during the then applicable employment term, and (c) a pro rata portion of 100% of the target bonus being paid for the final fiscal year that begins during the then applicable employment term.  In addition, all of Mr. Parikh’s unvested stock options, restricted stock, and other equity awards shall become fully vested and all stock options that are vested and outstanding (but unexercised) on the date of termination will be cancelled and we will pay to Mr. Parikh, with respect to each option, an amount equal to the excess of the fair market value per share of the shares underlying such option over the exercise price of such option multiplied by the number of shares underlying such option.  In addition, Mr. Parikh’s benefits will continue for the duration of the then current employment term.

 

If there is a change in control (as such term is defined in the employment agreement) and either a constructive termination occurs or we terminate Mr. Parikh’s employment without business reasons prior to the expiration of the then current employment term, he will be entitled to receive (i) his then current base salary, any paid time off, and any earned and unpaid target bonus accrued through the date of termination; (ii) a lump sum payment equal to the greater of (a) two times his then current base salary or (b) his then current base salary for the remainder of the then current employment term; (iii) a lump sum payment equal to the greater of (a) 200% of the target bonus for the fiscal year in which the termination occurs, or (b) 100% of the target bonus for the fiscal year in which the termination occurs times the number of years for the remainder of the then current employment term.  In addition, all of Mr. Parikh’s unvested stock options, restricted stock, and other equity awards shall become fully vested.

 

If Mr. Parikh is terminated as a result of death or disability (as such term is defined in the Parikh Agreement), he or his representative, as the case may be, will be entitled to receive (i) any accrued and

 

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unpaid salary; (ii) any accrued and unpaid target bonus for a prior fiscal year; (iii) a pro rata portion of any target bonus that he would have otherwise earned during the fiscal year in which the termination occurs; and (iv) any accrued and unpaid paid time off.  Mr. Parikh’s outstanding stock options, restricted stock, and other equity arrangements shall expire in accordance with the terms of the applicable award agreements.

 

If Mr. Parikh voluntarily terminates his employment (other than in the case of a constructive termination), or he is terminated involuntarily for business reasons, he will be entitled to receive (i) all accrued and unpaid salary, all accrued and unpaid target bonus for a prior fiscal year, and a pro rata portion of any target bonus that he would have otherwise earned during the fiscal year in which such termination occurs and (ii) all accrued but unpaid paid time off and other benefits due to him through his termination date under any Company-provided or paid plans, policies, and arrangements.  Mr. Parikh’s stock options, restricted stock, and other equity arrangements will cease vesting immediately and such awards will expire in accordance with the terms of the applicable award agreements.

 

If Mr. Parikh’s employment is terminated for any reason, we have the initial right to purchase all (but not less than all) of the common stock of the Company held by Mr. Parikh by making a written offer within 60 days of termination.  If Mr. Parikh is involuntarily terminated for any reason (including a constructive termination) other than for business reasons, but we do not offer to purchase his shares of common stock of the Company within 60 days of termination, Mr. Parikh has the right to cause us to repurchase all (but not less than all) of his common stock of the Company.  The foregoing rights terminate upon an initial public offering of our common stock.

 

The Parikh Agreement provides that in the event that Mr. Parikh becomes entitled to payments or benefits that would constitute an “excess parachute payment” within the meaning of Section 280G of the Code, the payment and/or benefits will be reduced to the extent that such payments will not be subject to the excise tax or any interest or penalties imposed by Section 4999 of the Code, referred to herein as the 280G Reduction. The 280G Reduction will only take place if Mr. Parikh’s “net after tax benefit” (as defined in the Parikh Agreement) exceeds the net after tax benefit he would realize if the 280G Reduction were not made. To the extent, the 280G Reduction is unavailable because Mr. Parikh’s net after tax benefit would be greater if the 280G Reduction were not made, we will pay Mr. Parikh a gross up payment in an amount such that after the payment by Mr. Parikh of all taxes (including any income taxes, interest, penalties or any excise taxes), Mr. Parikh would retain an amount of the gross-up payment equal to seventy-five (75%) of any excise tax imposed upon the payments received by Mr. Parikh.

 

The Parikh Agreement also contains restrictive covenants, which apply for the remainder of the then-current agreement term.  Pursuant to the restrictive covenants, Mr. Parikh is generally prohibited from (1) owning or providing services for any business competing with us for the remainder of the agreement term; (2) inducing employees to leave the our employ or hiring them (unless the employee contacts Mr. Parikh on an unsolicited basis); (3) soliciting any of our customers, suppliers, licensees or other business relations; or (4) disparaging us, our executive officers, or our directors.  In the event that Mr. Parikh violates the provisions of the restrictive covenants, he will not be entitled to any severance benefits upon a termination without business reasons or upon a constructive termination.  Additionally, upon any such violation, all of Mr. Parikh’s unexercised options, whether vested or unvested, shall be cancelled.

 

Steven Murray Employment Agreement

 

During 2009, we entered into discussions with Mr. Murray, our COO, about restating his employment agreement, dated August 4, 2006 (the “Murray Agreement”).  The initial term of the Murray Agreement was three years and such term is automatically extended for one year at the end of the initial term, unless we or Mr. Murray gives the other party at least 180 days’ advance notice to the contrary.  On February 6, 2009, we provided notice to Mr. Murray that the Murray Agreement would expire on the earlier of August 4, 2009 or execution of a new employment agreement. The Murray Agreement expired on August 4, 2009.

 

Pursuant to the Murray Agreement, Mr. Murray’s office will be located in our Houston, Texas offices and he will report to the CEO of the Company. In addition to his position as COO, the Murray Agreement provides that Mr. Murray will be a member of the Board of Directors of the Company.

 

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The Murray Agreement provides that Mr. Murray will receive an annual base salary of $450,000, which may be increased at the Compensation Committee’s discretion.  The Murray Agreement also provides that Mr. Murray is eligible for an executive bonus, which may be 100% of Mr. Murray’s base salary.  The target bonus is based on the following: (1) 75% is based on the performance of the Company or Mr. Murray and (2) 25% is based on the Company’s discretion. Additionally we may award Mr. Murray up to 20% of his base salary in connection with his extraordinary performance with respect to a significant business event, provided that the maximum actual bonus will not exceed 120% of base salary.  The Murray Agreement also provides that we will grant to Mr. Murray an option to purchase 150,000 shares of common stock which will vest in three equal installments over three years commencing with the first anniversary of the initial term.

 

On July 31, 2009, we entered into a supplement to the Murray Agreement with Mr. Murray (the “Murray Supplemental Agreement”). Under the Murray Supplemental Agreement, the Company acknowledged that, as of July 31, 2009, $140,788 of Mr. Murray’s fiscal year 2008 bonus remains unpaid and Mr. Murray’s fiscal year 2009 bonus has not yet been determined, but will be a minimum of $400,000. Mr. Murray will be entitled to payment for his fiscal year 2008 bonus and fiscal year 2009 bonus at the earlier of (i) the earliest date that we are not restricted under our debt agreements from paying such bonuses, or (ii) the earliest date as of which any member of the senior management team receives his or her bonus for fiscal year 2008 or fiscal year 2009. In addition, under the terms of the Murray Supplemental Agreement, Mr. Murray agreed to terminate all of his options to purchase shares of common stock.

 

In the event Mr. Murray’s employment is terminated prior to an initial public offering of our common stock, we shall have the right to purchase all of the common stock owned by Mr. Murray and Mr. Murray shall have the right to require us to purchase all of such stock, both based upon the fair market value of the common stock.

 

In the event that we terminate Mr. Murray’s employment without a “business reason” (as defined in the Murray Employment Agreement, which generally includes “cause” events such as felony conviction, fraud or insubordination) or a “constructive termination” (as defined in the Murray Agreement, such as a material reduction in salary or authority or a relocation) occurs Mr. Murray will be entitled to: (1) a lump sum payment equal to the greater of (a) base salary for a period of 12 months following the date of termination or (b) base salary for the remainder of the then-current agreement term; (2) a lump sum payment equal to (a) 100% of the target bonus for the fiscal year in which the termination occurs; (b) 100% of the target bonus for any full fiscal year remaining during the initial term of the agreement; and (c) a pro rata portion of 100% of the target bonus for the final fiscal year that begins during the applicable agreement term; (3) Mr. Murray’s unvested stock options, restricted stock and other equity awards shall become fully vested, and all vested but outstanding stock options shall be cancelled in consideration of our payment to Mr. Murray of an amount equal to (x) the fair market value for the shares underlying the option, (y) over the exercise price of such option, (z) multiplied by the number of shares subject to the option; and (4) any accrued, but unpaid, compensation.

 

If there is a change of control during the initial term of the Murray Agreement and we terminate Mr. Murray’s employment without business reasons prior to the end of the initial term of the agreement (or within a year following a change of control) prior to the end of the initial term of the agreement (or within a year following a change of control) or a constructive termination occurs, Mr. Murray will be entitled to receive the following: (1) a lump sum payment equal to the greater of (a) base salary for a period of two years following the date of termination or (b) base salary for the remainder of the then-current agreement term and (2) a lump sum payment equal to the greater of (a) 200% of the target bonus for the fiscal year in which the termination occurs; (b) 100% of the target bonus for any full fiscal year remaining during the initial term of the agreement times the number of years for the remainder of the then-current agreement term; (3) Mr. Murray’s unvested stock option, restricted stock and other equity awards shall become fully vested and (4) any accrued, but unpaid, compensation.

 

In the event of termination due to disability, Mr. Murray will be entitled to all earned, but unpaid compensation, payments and benefits in accordance with our disability policy, the “in the money” value of all vested options, a pro rata portion of any target bonus Mr. Murray would have otherwise earned during the fiscal year in which the disability occurs, and any accrued, but unpaid, compensation.

 

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If Mr. Murray voluntarily terminates his employment or we involuntarily terminate his employment for business reasons, all equity awards will expire according to the terms of the award agreement, Mr. Murray will receive any accrued, but unpaid, compensation, and Mr. Murray will receive a pro rata portion of any target bonus that he would have otherwise earned during the fiscal year in which his termination occurs.

 

If Mr. Murray’s employment terminates due to death, Mr. Murray’s representative will receive payments and benefits in accordance with the then applicable plans, policies, or arrangements, all equity awards will expire according to the terms of the award agreement (provided Mr. Murray will be entitled to the “in the money” value of all vested options), Mr. Murray will receive any accrued, but unpaid, compensation, and Mr. Murray will be entitled to receive a pro rata portion of any target bonus that he would have otherwise earned during the fiscal year in which his termination occurs.

 

The Murray Agreement also contains restrictive covenants, which apply for the remainder of the then-current agreement term. Pursuant to the restrictive covenants, Mr. Murray is generally prohibited from (1) owning or providing services for any business competing with us for the remainder of the agreement term; (2) inducing employees to leave the our employ or hiring them; (3) soliciting any of our customers, suppliers, licensees or other business relations; or (4) disparaging us, our executive officers, or our directors.  In the event that Mr. Murray violates the provisions of the restrictive covenants, he will not be entitled to any severance benefits upon a termination without business reasons or upon a constructive termination.  Additionally, upon any such violation, all of Mr. Murray’s unexercised options, whether vested or unvested, shall be cancelled.

 

Carole R. Artman-Hodge Employment Agreement

 

We entered into an employment agreement with Ms. Artman-Hodge dated April 1, 1999 (the “Artman-Hodge Agreement”).  The Artman-Hodge Agreement commenced on the date of the closing of our initial equity capital transaction in connection with Ms. Artman-Hodge’s employment as our Executive Vice President and Chief Financial Officer.  The initial term of the agreement was five years and is automatically extended for successive five-year terms, unless we or Ms. Artman-Hodge gives the other party at least six months’ advance notice to the contrary.

 

The Artman-Hodge Agreement provides that Ms. Artman-Hodge’s base salary may be increased from time to time.  In fiscal year 2007, Ms. Artman-Hodge’s base salary was $389,662.  The Artman-Hodge Agreement also provides that Ms. Artman-Hodge is eligible for an annual year-end bonus and to participate in our incentive stock option plans.  Under a provision of the Artman-Hodge Agreement, Ms. Artman-Hodge also acknowledges and agrees that as a founder and owner of a substantial equity interest in the Company that she is subject to the Shareholders Agreement, dated as of May 1, 1999, between the Company and certain shareholders.

 

In the event that we terminate Ms. Artman-Hodge’s employment relationship without “cause” (as defined in the Artman-Hodge Agreement, which generally means felony conviction, fraud or a material breach of the agreement), Ms. Artman-Hodge will be entitled to a lump sum severance payment of 36 months of her base salary in effect at the time of her termination plus any unvested warrants, options or other securities awarded to her pursuant to the incentive stock option plans by us. Additionally, she will vest in the pro rata portion of any warrants or options that are scheduled to vest on the vesting date next succeeding the effective date of her termination and forfeit the right to receive all remaining unvested warrants or options. In the event that Ms. Artman-Hodge terminates her employment or we terminate her employment with cause, Ms. Artman-Hodge will forfeit her right to receive any unvested options or warrants.

 

The Artman-Hodge Agreement also contains a non-compete provision, which applies during the term of Ms. Artman-Hodge’s employment and for a period of one year thereafter, whether her termination of employment is with or without cause or whether the termination is initiated by Ms. Artman-Hodge or us. Pursuant to the non-compete provision, Ms. Artman-Hodge is prohibited from (1) working with, or providing services to, any person or entity which was our customer at the date of cessation of her consulting or employment relationship, as the case may be or within the twelve-month period preceding such date, or which was contracted as a client prospect by any representative of the Company within 90 days prior to such date of cessation; or (2) soliciting or inducing any of our employees to leave our employ or to hire or attempt to hire any such employee.

 

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For purposes of the Artman-Hodge Agreement, cause means: (i) conviction of, or pleading guilty to, a felony-class crime; (ii) any action taken in bad faith by Ms. Artman-Hodge that has, or is likely to have, in our reasonable judgment, a material, detrimental effect on the reputation of the Company or its business; (iii) an act of fraud, dishonesty or gross misconduct by Ms. Artman-Hodge; (iv) a material breach by Ms. Artman-Hodge of any provision of the Artman-Hodge Agreement that has not been cured within 30 days after our written notice of such breach.

 

Gina Goldberg Employment Agreement

 

We entered into an employment agreement with Ms. Goldberg dated June 13, 2007, referred to herein as the Goldberg Agreement, in connection with Ms. Goldberg’s employment as our Vice President of Sales and Marketing. Under the Goldberg Agreement, the parties may terminate the Goldberg Agreement at any time provided either party gives the other at least 60 days’ advance notice of termination. Ms. Goldberg’s office will be located in the Company’s Stamford, Connecticut offices and she will report to the Chief Operating Officer or the Chief Executive Officer of the Company.

 

The Goldberg Agreement provides that Ms. Goldberg will receive an annual base salary of $238,000. The Goldberg Agreement also provides that Mr. Goldberg is eligible for a bonus, which is expected to range from 50 to 100% of Ms. Goldberg’s base salary.

 

Because the Company had already granted warrants and options to Ms. Goldberg prior to June 13, 2007, the Goldberg Agreement provides that the terms of the warrants and options would not be impacted by the Goldberg Agreement. If the Company terminates Ms. Goldberg’s employment for business reasons (as defined below) all unvested stock options will be forfeited.

 

Additionally, if Ms. Goldberg’s employment is terminated for any reason, the Company shall have the right to purchase all of the common stock owned by Ms. Goldberg, provided that if the amount payable to Ms. Goldberg exceeds $200,000, the Company may pay the excess to Ms. Goldberg in quarterly installments with 5% interest over a period of three years and the Company’s obligation to make such payment shall be suspended during any period that the payment would cause the Company to violate a loan or similar financial covenant.

 

In the event that the Company terminates Ms. Goldberg’s employment without a “business reason” (as defined below) or Ms. Goldberg terminates her employment for any reason that constitutes a constructive termination (as defined below), Ms. Goldberg will be entitled to (i) a lump sum payment equal to the greater of her base salary for the remainder of the employment term or (ii) her base salary for a period of 12 months. For purposes of severance, Ms. Goldberg’s employment term will be deemed to be two years. If the Company terminates Ms. Goldberg’s employment for business reasons or Ms. Goldberg terminates her employment for any reason that does not constitute a constructive termination, she will be entitled to any accrued and unpaid salary.

 

For purposes of the Goldberg Agreement, “business reasons” mean: (i) gross negligence, willful misconduct or other willful malfeasance in the performance of his duties; (ii) conviction of, or plea of nolo contendere to, or written admission of the commission of a felony, or any other criminal offense involving moral turpitude; (iii) any act by Ms. Goldberg involving moral turpitude, fraud or misrepresentation with respect to his duties for the Company or its affiliates; (iv) any act by Ms. Goldberg constituting a failure to follow the directions of the Chief Executive Officer, the Chief Operating Officer, or the board of directors, provided written notice of such failure is provided to Ms. Goldberg and the failure continues for five days after receipt of such notice; and (v) subject to certain conditions, Ms. Goldberg’s material breach of the Goldberg Agreement that has not been cured within 30 days after written notice of such breach by the board of directors.

 

For purposes of the Goldberg Agreement, “constructive termination” occurs if Ms. Goldberg gives the Company written notice of the existence of any of the following: (i) Ms. Goldberg is required to relocate her place of employment, other than a relocation that is within 30 miles of the Company’s Stamford offices; (ii) there an intentional and material reduction in Ms. Goldberg’s base salary (other than a reduction that is consistent with a general reduction for the executive staff as a group); (iii) there occurs any

 

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other material breach of the Goldberg Agreement by the Company provided Ms. Goldberg provides a written demand for substantial performance to the Company. Constructive termination will only be deemed to occur if the Company fails to cure the event within 31 days following the date such notice is given.

 

The Goldberg Agreement also contains a non-compete provision, which applies during the term of the Goldberg Agreement and, provided Ms. Goldberg has received a severance payment for a period of one year after she has received such payment. Pursuant to the non-compete provision, Ms. Goldberg is prohibited from (1) inducing or attempting to induce any employee of the Company or such subsidiary (other than his own assistant) to leave the employ of the Company, or in any way interfere with the relationship between the Company or any subsidiary and any employee thereof; (2) hiring or attempt to hire an employee of the Company or any subsidiary at any time during the preceding 12 months (unless the employee contacts Ms. Goldberg on an unsolicited basis); (3) directly or indirectly inducing or attempting to induce any customer, supplier, licensee or other business relation of the Company or (4) disparaging the Company, its executive officers, or its directors.

 

Post-Employment Payments

 

The following table summarizes the payments that we would have been required to make to the named executive officers as of June 30, 2009 as a result of their termination, retirement, disability or death or a change in control of the Company as of that date.  The specific circumstances identified in the table that would trigger such payments are described in the employment agreement for each executive.

 

 

 

Termination Event

 

 

 

Involuntary
Without Cause
or For
Constructive
Termination

 

Involuntary
With Cause or
Without
Constructive
Termination

 

Change in
Control

 

Disability

 

Death

 

 

 

 

 

 

 

 

 

 

 

 

 

Jeffrey Mayer:

 

 

 

 

 

 

 

 

 

 

 

Cash severance payment

 

$

4,345,186

 

$

677,098

 

$

3,750,360

 

$

677,098

 

$

677,098

 

Acceleration of stock options

 

 

 

 

 

 

Health and life insurance

 

33,919

 

 

 

 

 

Continuation of perquisites

 

36,000

 

 

 

 

 

Total termination benefits

 

$

4,415,105

 

$

677,098

 

$

3,750,360

 

$

677,098

 

$

677,098

 

 

 

 

 

 

 

 

 

 

 

 

 

Chaitu Parikh:

 

 

 

 

 

 

 

 

 

 

 

Cash severance payment

 

$

2,294,230

 

$

536,793

 

$

1,872,445

 

$

536,793

 

$

536,793

 

Acceleration of stock options

 

 

 

 

 

 

Health and life insurance

 

20,983

 

 

 

 

 

Total termination benefits

 

$

2,315,213

 

$

536,793

 

$

1,872,445

 

$

536,793

 

$

536,793

 

 

 

 

 

 

 

 

 

 

 

 

 

Steven Murray:

 

 

 

 

 

 

 

 

 

 

 

Cash severance payment

 

$

1,424,758

 

$

542,660

 

$

1,424,758

 

$

542,660

 

$

542,660

 

Total termination benefits

 

$

1,424,758

 

$

542,660

 

$

1,424,758

 

$

542,660

 

$

542,660

 

 

 

 

 

 

 

 

 

 

 

 

 

Carole Artman-Hodge:

 

 

 

 

 

 

 

 

 

 

 

Cash severance payment

 

$

1,190,250

 

$

20,250

 

$

20,250

 

$

20,250

 

$

20,250

 

Total termination benefits

 

$

1,190,250

 

$

20,250

 

$

20,250

 

$

20,250

 

$

20,250

 

 

 

 

 

 

 

 

 

 

 

 

 

Gina Goldberg:

 

 

 

 

 

 

 

 

 

 

 

Cash severance payment

 

$

520,600

 

$

238,735

 

$

238,735

 

$

238,735

 

$

238,735

 

Total Termination benefits

 

$

520,600

 

$

238,735

 

$

238,735

 

$

238,735

 

$

238,735

 

 

Director Compensation

 

During Fiscal year 2009, Michael Hamilton earned the following fees: (1) $40,000 for his membership and participation on the Board of Directors and (2) $10,000 for his role as Chairman of the Audit Committee.  No other director compensation was earned or paid during fiscal year 2009.

 

Pursuant to the terms of the Company’s Third Amended and Restated Certificate of Incorporation filed in connection with the Restructuring, as of September 22, 2009, the Company will pay each independent director a retainer of $35,000 per year and a retainer of $5,000 per year for each committee on which such

 

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director serves.  In addition, the Company will pay each independent director $2,500 for attendance in person at each regular or special board meeting or committee meeting and $500 for attendance by telephone at each regular or special board or committee meeting.  The chairman of the Board of Directors, if he or she is an independent director, will receive an additional retainer of $5,000 per year.

 

We do not provide any defined benefit or defined contribution plan benefits to any of our directors.  During the fiscal year ended June 30, 2009, we did not grant any stock awards, stock option awards, non-equity incentive compensation or other deferred compensation to any of our directors, nor did we recognize any compensation expense for such awards granted in prior fiscal years.

 

During the fiscal year ended June 30, 2009, Daniel Bergstein provided management consulting services to us, for which we recorded $260,000 of expense during the year.  Refer to “Item 13.  Certain Relationships and Related Transactions and Director Independence” for additional information.

 

Compensation Committee Interlocks and Insider Participation

 

Messrs. Daniel Bergstein (Chair), William Landuyt and Stuart Porter served on the Compensation Committee during the fiscal year ended June 30, 2009.  None of these directors were, during fiscal year 2009 or previously, officers or employees of Holdings.  The Board of Directors has determined that Messrs. Bergstein and Landuyt were not independent directors based on the definition of independence of the New York Stock Exchange.  For more information, refer to “Item 13. Certain Relationships and Related Transactions, and Director Independence — Independence of Directors.”  During the fiscal year ended June 30, 2009, we had no Compensation Committee “interlocks”, meaning that none of our executive officers served as a director or member of the Compensation Committee of another entity of which an executive officer served as a director or a member of the Compensation Committee of the Company.

 

Messrs. James Chapman (Chair), Michael Goldstein, Michael Hamilton, Randal Maffett and Stuart Porter serve on the Compensation Committee as of September 29, 2009.  None of these directors were, prior to such date, or are currently officers or employees of Holdings.  The Board of Directors has not yet determined whether such directors are independent.  As of September 29, 2009, we have not determined whether any of our executive officers serve as a director or member of the compensation committee of another entity of which an executive officer serves as a director or a member of our Compensation Committee.

 

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

 

The following table sets forth, as of September 30, 2009, information with respect to shares of common stock beneficially owned by: (1) each of the named executive officers; (2) each director; (3) all executive officers and directors as a group; and (4) each person known to be the beneficial owner of more than five percent of our outstanding shares of common stock.

 

The percentages of common stock and Preferred Stock beneficially owned are reported on the basis of SEC regulations governing the determination of beneficial ownership of securities.  Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security.  A person is also deemed to be a beneficial owner of any securities for which that person has a right to acquire beneficial ownership within 60 days.  All persons listed have sole voting and investment power with respect to their shares (subject to community property laws where applicable) unless otherwise indicated.

 

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Common Stock (1)

 

Name or Description

 

Number

 

Percentage
of Total
Common
Stock

 

 

 

 

 

 

 

Executive Officers and Directors:

 

 

 

 

 

Jeffrey Mayer (2)

 

860,830

 

1.6

%

Chaitu Parikh (3)

 

278,308

 

0.5

 

Steven Murray

 

 

 

Carole R. (“Robi”) Artman-Hodge (4)

 

434,964

 

0.8

 

Gina Goldberg (5)

 

776

 

 

Mark Bernstein

 

 

 

James Chapman

 

 

 

Michael Goldstein

 

 

 

Michael J. Hamilton

 

 

 

William Landuyt (6)

 

10,004,705

 

18.4

 

Randal T. Maffett

 

 

 

Jonathon Moore

 

 

 

Stuart Porter (7)

 

8,737,436

 

16.1

 

All directors and executive officers as a group (15 persons) (8)

 

20,317,980

 

37.4

 

5% Stockholders:

 

 

 

 

 

Charter Mx LLC (6)
1105 Market Street, Suite 1300, Wilmington, DE 19899

 

10,004,705

 

18.4

 

Camulos Capital LP (9)
Three Landmark Square, Stamford, CT 06901

 

8,976,179

 

16.5

 

Denham Commodity Partners Fund LP (7)
200 Clarendon Street, 25th Floor, Boston, MA 02116

 

8,737,436

 

16.1

 

Taconic Capital Advisors LP (10)
450 Park Avenue, 9th Floor, New York, NY 10022

 

4,274,570

 

7.9

 

Morgan Stanley & Co. on behalf of certain funds and accounts, as holders (11)
2000 Westchester Avenue, Purchase, NY 10577

 

4,183,728

 

7.7

 

AIG Global Investment Corp on behalf of certain funds and accounts, as holders (12)
2929 Allen Parkway, A37, Houston, TX 77019

 

3,960,782

 

7.3

 

Sempra Energy Trading LLC (13)
600 Washington Blvd., Stamford, CT 06901

 

4,002,290

 

7.4

 

 


(1)

 

The percentage of beneficial ownership is based on 54,305,112 shares of our common stock outstanding as of September 30, 2009.

(2)

 

Includes 258,339 shares of Class A Common Stock (0.8% of total shares of Class A Common Stock outstanding) and 31,538 shares of Class C Common Stock (3.7% of total shares of Class C Common Stock outstanding) received in connection with the consummation of the Restructuring on September 22, 2009. Also includes 570,953 shares of Class C Common Stock (3.5% of total shares of Class C Common Stock outstanding) issued to Pequot Enterprises LLC in connection with the Restructuring. Pequot Enterprises LLC is a limited liability company owned 23% by Mr. Mayer and for which Mr. Mayer, as manager, has both voting and disposition power.

(3)

 

Includes 258,339 shares of Class A Common Stock (0.8% of total shares of Class A Common Stock outstanding) and 19,969 shares of Class C Common Stock (0.1% of total shares of Class C Common Stock outstanding) received in connection with the consummation of the Restructuring on September 22, 2009.

(4)

 

Includes 103,336 shares of Class A Common Stock (0.3% of total shares of Class A Common Stock outstanding) and 87,399 shares of Class C Common Stock (0.5% of total shares of Class C Common Stock outstanding) received in connection with the consummation of the Restructuring on September 22, 2009. Also includes 244,229 shares of Class C Common Stock (1.5% of total shares of Class C Common Stock outstanding) owned by the Carole R. Artman-Hodge 2005 7 Yr. GRAT for which Ms. Artman-Hodge has both voting and disposition power.

(5)

 

Includes 766 shares of Class C Common Stock (less than 0.1% of total shares of Class C Common Stock outstanding) received in connection with the consummation of the Restructuring on September 22, 2009.

(6)

 

Includes 10,004,705 shares of Class C Common Stock (61.1% of total shares of Class C Common Stock outstanding) received in connection with the consummation of the Restructuring on September 22, 2009. All of the shares of Class C Common Stock are held by Charter Mx LLC. Charter Mx LLC is wholly-owned by Charterhouse Equity Partners IV, L.P. The general partner of Charterhouse Equity Partners IV, L.P. is CHUSA Equity Investors IV, L.P., whose general partner is Charterhouse Equity IV, LLC, a wholly owned subsidiary of Charterhouse Group, Inc. As a result of the foregoing, all of the shares held by Charter Mx LLC would be deemed to be beneficially owned by Charterhouse Group, Inc. We have been advised by Charterhouse Group, Inc. that all decisions regarding investments by Charterhouse Equity Partners IV, L.P. (the “Fund”) are made by an investment committee whose composition may change. No individual has authority to make any such decisions without the approval of the Fund’s investment committee. William Landuyt is an executive officer of Charterhouse Group, Inc. and a member of the Fund’s investment committee, the members of which, including Mr. Landuyt, each disclaim beneficial ownership of the shares held by Charter Mx LLC except to the extent of his or her pecuniary interest therein.

(7)

 

Includes 6,476,722 shares of Class A Common Stock (19.1% of total shares of Class A Common Stock outstanding) and 2,260,714 shares of Class C Common Stock (13.8% of total shares of Class C Common Stock outstanding) received in connection with the consummation of the Restructuring on September 22, 2009. The shares of Class C Common Stock are held by Denham Commodity Partners Fund LP. Mr. Porter is a principal of Denham Capital Management LP and is Chief Investment Officer for Denham Commodity Partners Fund LP.

(8)

 

Includes 7,096,736 shares of Class A Common Stock (20.9% of total shares of Class A Common Stock outstanding) and 13,221,244 shares of Class C Common Stock (80.8% of total shares of Class C Common Stock outstanding) received in

 

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connection with the consummation of the Restructuring on September 22, 2009. Represents beneficial ownership as a group for all directors and executive officers as of September 30, 2009 listed in the tables under “Item 10. Directors, Executive Officers and Corporate Governance — Directors and Executive Officers.”

(9)

 

Includes 8,976,179 shares of Class A Common Stock (26.4% of total shares of Class A Common Stock outstanding) received by holders of Fixed Rate Notes due 2014 in connection with the consummation of the Restructuring on September 22, 2009.

(10)

 

Includes 4,274,570 shares of Class A Common Stock (12.6% of total shares of Class A Common Stock outstanding) received by holders of Fixed Rate Notes due 2014 in connection with the consummation of the Restructuring on September 22, 2009.

(11)

 

Includes 4,183,728 shares of Class A Common Stock (12.3% of total shares of Class A Common Stock outstanding) received by holders of Fixed Rate Notes due 2014 in connection with the consummation of the Restructuring on September 22, 2009, which are managed by Morgan Stanley & Co. on behalf of certain funds and accounts, and over which Morgan Stanley & Co. has voting control.

(12)

 

Includes 3,960,782 shares of Class A Common Stock (11.7% of total shares of Class A Common Stock outstanding) received by holders of Fixed Rate Notes due 2014 in connection with the consummation of the Restructuring on September 22, 2009, which are managed by AIG Global Investment Corp on behalf of certain funds and accounts, and over which AIG Global Investment Corp has voting control.

(13)

 

Includes 4,002,290 shares of Class B Common Stock (100% of total shares of Class B Common Stock outstanding) received by Sempra Commodity Trading LLC in connection with the consummation of the Restructuring on September 22, 2009.

 

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

 

Our Code of Ethics, which is posted on our website at www.mxholdings.com, prohibits directors and executive officers from engaging in transactions on behalf of the Company with a family member, or with a company with which they or any family member are a significant owner or associated or employed in a significant role.  Our Audit Committee must review and approve in advance all related party transactions or business or professional relationships.  All instances involving potential related party transactions or business or professional relationships must be reported to the Company’s inhouse legal counsel, who is responsible to assess the materiality of the transaction or relationship and elevate the matter to the Audit Committee as appropriate.

 

Stockholders’ Agreement

 

Prior to the Restructuring, we entered into a Third Amended and Restated Stockholders’ Agreement with holders of our common stock and Preferred Stock, which contained, among other things, the agreement among our stockholders to restrict their ability to transfer our stock as well as rights of first refusal, tag-along rights and drag-along rights. Pursuant to the stockholders’ agreement, certain of our stockholders had, subject to certain exceptions, preemptive rights on future offerings of equity securities by us. In addition, if we issued or sold shares of our common stock below a certain price, we must offer to sell such common stock to certain of our existing stockholders at a similarly low price.

 

On September 22, 2009, in connection with the consummation of our Restructuring, we entered into a new stockholders agreement (the “Stockholders Agreement”).  Pursuant to the Stockholders Agreement, holders of Class A Common Stock are not subject to any restrictions on the transfer of their shares while holders of Class B Common Stock and certain holders of Class C Common Stock are subject to certain restrictions.  Moreover, transfers of all 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.  No shares of Common Stock may be transferred to competitors of the Company or in any transaction that, among other things, violates or causes a default, “change in control” or similar event under any of the Company’s or any of its subsidiaries’ material debt agreements, indentures and other agreements or instruments evidencing material indebtedness of the Company of any of its subsidiaries (with certain exceptions), violates applicable securities laws or certain other laws, or results in certain other specified consequences, unless such transaction has been approved by (i) a majority of the authorized Class A Directors, (ii) a majority of all authorized directors and (iii) in the case of certain specified actions, for so long as holders of shares of Class B Common Stock have the exclusive right to nominate and elect the Class B Director, the Class B Director.

 

All shares of common stock will have preemptive rights, subject to certain exceptions, and information rights.  If a party that did not acquire shares of common stock on September 22, 2009 (a “New Shareholder”) acquires, together with its affiliates, or proposes to acquire, from any person (such person, a “Selling Shareholder”), whether through one or a series of transactions, such number of shares of common stock as would result in the New Shareholder (together with its affiliates) holding a majority of the then-issued and outstanding shares of common stock, then such New Shareholder, prior to consummating the proposed acquisition, must make a mandatory offer (a “Mandatory Offer”) to purchase the remaining shares of common stock that it does not own at a price equal to the higher of (a) the highest price per share paid by the New Shareholder and its affiliates for any shares of common stock acquired by the New Shareholder and its affiliates during the preceding nine months and (b) the purchase price per share to be paid by the New Shareholder to the Selling Shareholder for the shares of common stock to be acquired by the New Shareholder from the Selling Shareholder.

 

Customary tag-along rights are provided to all shareholders under the Stockholders Agreement with respect to sales of shares of common stock representing in the aggregate a majority of the then-issued and outstanding shares of all classes of common stock, on a fully diluted basis, to a single purchaser, or group of related purchasers, in any transaction or series of related transactions, including where the conditions of a tag-along transfer are satisfied as a result of a Mandatory Offer, subject to certain exceptions.

 

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Customary drag-along rights are provided under the Stockholders Agreement if holders of shares representing at least 75% of all classes of common stock and holders of shares representing at least 70% of the Class B Common Stock (until shares of Class B Common Stock are converted into shares of Class C Common Stock or Class D Common Stock in connection with an initial public offering (an “IPO”)) determine to sell all of the shares of common stock to a person or persons (other than a person that (i) has among its shareholders, members, partners or other equity holders, holders of common stock that collectively hold more than 20% of the outstanding shares of common stock, or any affiliates of such holders, or (ii) is more than 20% owned or controlled, directly or indirectly, by holders of common stock, and other than an affiliate of any of the selling stockholders or a group including one or more affiliates of any of the selling stockholders) in any transaction, or series of related transactions, that is proposed to be effected on an arms-length basis.  The Company will have the right (but not the obligation) to purchase all (but not less than all) of the shares of Class A Common Stock or Class C Common Stock held by any holder who has not executed the Stockholders Agreement and who fails to sell its shares of Common Stock to the purchaser in a drag-along transaction following a valid exercise of the drag-along rights contained in the Stockholders Agreement.

 

The following matters require approval of (a) holders of at least 70% of the issued and outstanding shares of Class A Common Stock, (b) holders of at least 70% of the issued and outstanding shares of Class B Common Stock (provided, with respect to clause (ii) below only, that such amendment affects the rights of holders of the Class B Common Stock or increases the number of authorized shares of Class B Common Stock), (c) in the case of clause (ii) below only, and solely to the extent that such amendment affects the rights of the Class C Common Stock or increases the number of authorized shares of Class C Common Stock, holders of at least 70% of the issued and outstanding shares of Class C Common Stock, and (d) holders of at least 75% of all issued and outstanding shares of common stock:

 

·                  commencement of a voluntary liquidation, winding up or dissolution of the Company or any of its subsidiaries, filing of any petition in bankruptcy or insolvency or entering into any arrangement for the benefit of creditors, commencing any other proceeding for the reorganization, recapitalization or adjustment or marshalling of the assets or liabilities of the Company or any of its subsidiaries, or the adoption by the Company or any of its subsidiaries of a plan with respect to any of the foregoing, or acquiescence or agreement by the Company or any of its subsidiaries to any of the foregoing commenced or petitioned for on an involuntary basis;

·                  amendment or modification of the certificate of incorporation or the bylaws of the Company or any subsidiary of the Company;

·                  reorganization of the Company or reclassification of any of its securities; and

·                  waiver of preemptive rights in connection with a strategic investment in the Company by any person.

 

In addition to any vote by holders of common stock required under Delaware law, a vote of holders of at least 70% of the issued and outstanding shares of Class A Common Stock and holders of at least 70% of the issued and outstanding shares of Class B Common Stock (in the case of the Class B Common Stock, until shares of Class B Common Stock are converted into shares of Class C Common Stock or shares of Class D Common Stock or unless the contemplated merger or other transaction would, as a condition to the consummation thereof, result in, and does result in, the full pay-off and termination of the Commodity Supply Facility) is required to approve any merger, consolidation or other business combination involving the Company or any of its subsidiaries (other than mergers of wholly owned subsidiaries of the Company with each other or the Company) or any transaction having the effect (economic or otherwise) of a sale of all or substantially all of the assets of the Company or any of its subsidiaries (other than transfers of assets of wholly owned subsidiaries of the Company to each other or the Company).

 

Pursuant to the Stockholders Agreement, the Board of Directors consists of nine directors, elected as follows:

 

·                  Holders of the Class A Common Stock are entitled to nominate and five Class A Directors, at least two of whom shall be independent and qualify as a “financial expert”.

 

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·                  Holders of the Class B Common Stock are entitled to nominate and elect one Class B Director until the shares of Class B Common Stock have been converted and are no longer outstanding.  At such time as the shares of Class B Common Stock have been converted and are no longer outstanding, the Class B Director position will be filled by the vote of a plurality of all holders of Common Stock voting as a single class at any meeting of the stockholders of the Company at which the Class B Director would otherwise have been permitted to be elected, or as otherwise permitted under the Bylaws, and the Class B Director will be required to be independent and qualify as a “financial expert.”

·                  Holders of the Class C Common Stock are entitled to nominate and elect two Class C Directors.

·                  The ninth Director will be the Company’s president and chief executive officer, who initially, shall be Jeffrey A. Mayer.

 

Following the conversion of the shares of Class A Common Stock, Class B Common Stock (if applicable) and Class C Common Stock into shares of Class D Common Stock in connection with an IPO, the Board of Directors will consist of such number of directors as will be determined by the Board from time to time, which number will not be less than seven (7) nor more than fifteen (15) directors, and directors will be elected by holders of shares of common stock, voting as a single class at any meeting of the stockholders of the Company at which directors are permitted to be elected, or as otherwise permitted under the Bylaws, provided, however, that, for so long as the shares of Class B Common Stock are outstanding and have not been converted into shares of Class C Common Stock or into shares of Class D Common Stock, the Board will include one director nominated and elected by holders of shares of Class B Common Stock.

 

In order to conduct meetings of the Board of Directors, a quorum requires the presence of (i) a majority of the directors then in office, and (ii) prior to the conversion of shares of Class A Common Stock, Class B Common Stock (if applicable) and Class C Common Stock into shares of Class D Common Stock, (A) a majority of the Class A Directors then in office, (B) the Class B Director and (C) a Class C Director, provided, however, that if a meeting for which notice has been duly given or waived in accordance with the Bylaws is adjourned due to the failure of either the Class B Director or a Class C Director to be in attendance, then so long as notice is duly delivered of the time and place of the reconvened meeting in accordance with the Bylaws, the presence of either the Class B Director or a Class C Director at the reconvened meeting will not be required to establish quorum.

 

Class A Voting Agreement and Class C Voting Agreement

 

In addition, on September 22, 2009, holders of Class A Common Stock entered into a Class A Voting Agreement (the “Class A Voting Agreement”) that governs their rights to nominate and elect the Class A Directors and certain related matters and holders of Class C Common Stock entered into a Class C Voting Agreement (the “Class C Voting Agreement”) that governs their rights to nominate and elect the Class C Directors and certain related matters.  The Class A Voting Agreement also provides that so long as AIG Global Investment Corp., as the investment advisor for certain entities that will hold shares of Class A Common Stock (“AIG”), Camulos Capital LP, as the investment manager for certain entities that will hold shares of Class A Common Stock (“Camulos”), and/or Taconic Capital Advisors LP (“Taconic”), as the investment manager for certain entities that will hold shares of Class A Common Stock, hold at least 35% of the Class A Common Stock held by it on September 22, 2009 (after giving effect to stock splits or combinations or similar events), such stockholder shall be entitled to designate one of the Class A Directors.  The fourth and fifth Class A Directors will be designated by AIG, Camulos and Taconic by mutual agreement and will be independent and qualify as “financial experts.”  The Class C Voting Agreement provides that one of the Class C Directors shall be designated by Charterhouse so long as Charterhouse holds at least 35% of the outstanding shares of Class C Common Stock held by it on September 22, 2009 (after giving effect to stock splits or combinations or similar events) and who shall initially be William Landuyt, and the other Class C Director shall be designated by Denham so long as Denham holds at least 35% of the outstanding shares of Class C Common Stock held by it on September 22, 2009 (after giving effect to stock splits or combinations or similar events) and who shall initially be Stuart Porter.  If either Charterhouse or Denham loses its right to designate a Class C Director, thereafter such Class C Director position will be elected by a plurality vote of the shares of Class C Common Stock.

 

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Denham Credit Facility

 

Denham is a significant stockholder of the Company.  Stuart Porter, a principal of Denham Capital Management LP and Chief Investment Officer for the Denham Commodity Partners Fund, is a director of Holdings.

 

As of June 30, 2009, Denham had extended a $12.0 million line of credit to the Company, which bears interest at 9% per annum.  The termination date of the Denham Credit Facility was May 19, 2010, at which time any outstanding principal balance was to become due.  In December 2007, the agreement governing the Denham Credit Facility was amended to allow the Company to draw principal until November 14, 2008.

 

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

 

The Company had $12 million and $0 of borrowings outstanding under the Denham Credit Facility at June 30, 2009 and 2008, respectively.  The entire outstanding balance under the Denham Credit Facility was repaid by the Company in September 2009 and the facility was terminated.  Interest expense related to the Denham Credit Facility was $0.8 million for the fiscal year ended June 30, 2009.

 

Legal Services

 

Paul, Hastings, Janofsky & Walker LLP is a law firm that provides legal services to the Company.  Daniel Bergstein, a former director of Holdings and significant stockholder of the Company, is senior counsel to Paul Hastings.  During the fiscal year ended June 30, 2009, Paul Hastings provided the Company with legal services totaling $1.9 million.  The Company expects that Paul Hastings will continue to provide legal services to the Company in future periods.

 

Financial Advisory Services

 

GCP is a significant stockholder of the Company.  The Company has a financial advisory services agreement with Greenhill & Co., LLC (“Greenhill”), an affiliate of GCP.  In April 2008, the Company entered into an engagement letter with Greenhill that amends the Greenhill Agreement by: (1) expanding the definition of the potential transaction specified in the Greenhill Agreement; and (2) outlining fees associated with the occurrence of such a transaction.  In November 2008, the April 2008 engagement letter was amended to: (1) extend the engagement; (2) further expand the definition of the potential transaction; and (3) revise the potential fees associated with such a transaction.  Greenhill provided services to the Company totaling approximately $0.3 million related to the Restructuring.

 

Management Fees

 

As of June 30, 2009, the Company had agreed to pay Denham, Charter Mx LLC, a significant stockholder of the Company, and Daniel Bergstein, an aggregate annual fee of $0.9 million, payable in equal quarterly amounts, for management consulting services provided to the Company.  Management fees of approximately $0.9 million related to these arrangements were recorded in general and operating expenses during fiscal year 2009.

 

Options and Warrants Issued to Related Parties

 

There were no options or warrants to purchase the Company’s common stock granted to or exercised by any related parties during fiscal year 2009.

 

As of June 30, 2008, Denham held 1,544,736 fully-vested warrants to purchase an equivalent number of shares of Holdings’ common stock with a weighted average exercise price of $9.79 per share.  These

 

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warrants were issued in connection with various previous debt financings.  In September 2008, Denham exercised these warrants in a cashless transaction, resulting in the issuance of 1,054,982 shares of the Holding’s common stock.  Denham forfeited the right to acquire 489,754 shares of Holdings’ common stock under the warrants as consideration for the cashless exercise.

 

Fixed Rate Notes due 2014 Held by Holders of Class A Common Stock and Class C Common Stock

 

In connection with the Restructuring, Camulos Capital LP, Denham, Mr. Jeffrey Mayer, Mr. Chaitu Parikh and Ms. Artman-Hodge, all of whom were issued shares of Class A Common Stock and Class C Common Stock (refer to Item 12 of this Annual Report), also acquired the Company’s Floating Rate Notes due 2014.

 

Independence of Directors

 

The Company is a closely held corporation and does not have a class of equity securities listed on a national securities exchange.  The Company has adopted the definition of independence of the New York Stock Exchange.  However, because our securities are not listed on a national securities exchange, none of our directors are required to qualify as an independent director.

 

As of June 30, 2009, the Board of Directors determined that under such standard, John Stewart and Michael J. Hamilton were independent directors.  Messrs. Mayer or Murray and Ms. Artman-Hodge were not deemed to be independent because they are currently employed by the Company.  Stuart Porter was not an independent director as a result of his affiliation with Denham, a significant stockholder of the Company to which the Company also paid a management fee. Daniel Bergstein was not an independent director because: (1) he is a senior counsel in the New York office of Paul, Hastings, Janofsky & Walker LLP, a law firm that performs substantial legal services to the Company on a regular basis; and (2) in June 2004, he received a finder’s fee in connection with our issuance of Preferred Stock.  William Landuyt was not an independent director as a result of his affiliation with Charterhouse, a significant holder of Preferred Stock of the Company to which the Company also paid a management fee.

 

As of October 12, 2009, the Nominating and Governance Committee had not recommended to the Board of Directors, for its approval, which members are independent following the Restructuring. However, the Nominating and Governance Committee intends to take such action shortly following the filing of this Annual Report.

 

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ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

 

The total fees and expenses for professional services provided by our independent registered public accounting firm, Ernst & Young LLP are presented in the table below:

 

 

 

Year ended June 30,

 

 

 

2009

 

2008

 

 

 

(in thousands)

 

 

 

 

 

 

 

Audit fees

 

$

1,418

 

$

1,446

 

Audit-related fees

 

 

 

Tax fees

 

57

 

84

 

Total

 

$

1,475

 

$

1,530

 

 

Audit Fees consist primarily of: (1) fees billed for the audit of the consolidated financial statements and review of other financial information included in our Annual Report on Form 10-K for fiscal years 2009 and 2008; (2) reviews of our Quarterly Reports on Form 10-Q; (3) review of our compliance with new U.S. GAAP pronouncements, including SEC regulations; (4) review our accounting and reporting methodology for certain specific transactions; and (5) review of our financial and other records and issuance of a comfort letter associated with the exchange of bonds pursuant to the Restructuring.

 

Tax Fees consist of fees for tax compliance, tax advice and tax planning.

 

The Audit Committee has the responsibility to consider the compatibility of non-audit services provided by its independent auditors with maintaining the auditors’ independence.  There were no such non-audit services performed by the independent auditors during the fiscal year ended June 30, 2008.

 

Pre-Approval Policy

 

The services performed by the independent registered public accounting firm during the fiscal year ended June 30, 2009 were pre-approved by the Audit Committee, in accordance with the Audit Committee’s independent auditor pre-approval policy.  This policy describes the permitted audit, audit-related and tax services (collectively, referred to as the disclosure categories) that the independent registered public accounting firm may perform up to a pre-determined dollar limit per project. The policy requires a description of the material services (referred to as the standard services list) expected to be performed by the independent registered public accounting firm in each of the disclosure categories presented to the audit committee for approval.

 

Any requests for audit, audit-related and tax services not contemplated on the standard services list or exceeding the pre-determined dollar limit per project must be submitted to the Audit Committee for specific pre-approval and cannot commence until such approval has been granted.  Normally, pre-approval is provided on an informal, as-needed basis.  The Audit Committee may delegate pre-approval authority to one of its members, who shall initially be the chairman of the Audit Committee.  The decisions of any Audit Committee member to whom pre-approval authority is delegated must be presented to the full Audit Committee at its next scheduled meeting.

 

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PART IV

 

ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

 

The following documents are filed as part of this Annual Report:

 

(1)

 

Financial Statements.  See Index to Financial Statements under “Item 8. Financial Statements and Supplementary Data.”

(2)

 

Financial Statement Schedules.  Schedules are omitted as the required information is inapplicable or the information is presented in the consolidated financial statements or related notes under “Item 8. Financial Statements and Supplementary Data.”

(3)

 

Exhibits. The exhibits filed as part of this Annual Report are listed in the exhibit index immediately preceding such exhibits.  Such index is incorporated herein by reference.

 

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SIGNATURES

 

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

 

 

MXENERGY HOLDINGS INC.

 

 

 

 

Date: October 13, 2009

 

 

 

 

 

By:

/s/ JEFFREY A. MAYER

 

 

 

 

Jeffrey A. Mayer

 

 

 

 

President and Chief Executive Officer

 

 

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

 

Signatures

 

Title

 

Date

 

 

 

 

 

/s/ JEFFREY A. MAYER

 

Director, President and Chief Executive Officer

 

 

Jeffrey A. Mayer

 

(Principal Executive Officer)

 

October 13, 2009

 

 

 

 

 

/s/ CHAITU PARIKH

 

Vice President of Finance and Chief Financial Officer 

 

 

Chaitu Parikh

 

(Principal Financial Officer and Principal Accounting Officer)

 

 

 

 

 

October 13, 2009

 

 

 

 

 

/s/ MARK BERNSTEIN

 

Director

 

 

Mark Bernstein

 

 

 

October 13, 2009

 

 

 

 

 

/s/ JAMES CHAPMAN

 

Director

 

 

James Chapman

 

 

 

October 13, 2009

 

 

 

 

 

/s/ MICHAEL GOLDSTEIN

 

Director

 

 

Michael Goldstein

 

 

 

October 13, 2009

 

 

 

 

 

/s/ MICHAEL J. HAMILTON

 

Director

 

 

Michael J. Hamilton

 

 

 

October 13, 2009

 

 

 

 

 

/s/ WILLIAM LANDUYT

 

Director

 

 

William Landuyt

 

 

 

October 13, 2009

 

 

 

 

 

/s/ RANDAL T. MAFFETT

 

Director

 

 

Randal T. Maffett

 

 

 

October 13, 2009

 

 

 

 

 

/s/ JONATHAN MOORE

 

Director

 

 

Jonathan Moore

 

 

 

October 13, 2009

 

 

 

 

 

/s/ STUART PORTER

 

Director

 

 

Stuart Porter

 

 

 

October 13, 2009

 

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Index to Exhibits

 

Exhibit
Number

 

Title

2.1

 

Asset Purchase Agreement, dated as of May 12, 2006, by and between MXenergy Inc. and Shell Energy Services Company L.L.C. (1)

2.2

 

First Amendment to Asset Purchase Agreement and Acknowledgement, dated as of July 28, 2006, by and between MXenergy Inc. and Shell Energy Services Company L.L.C. (1)

2.3

 

Asset Purchase Agreement, dated November 9, 2007 by and between PS Energy Group, Inc. and MXenergy Inc. (2)

2.4

 

First Amendment to Asset Purchase Agreement and Determination Date Loan Documents, dated as of December 31, 2007, by and between PS Energy Group, Inc. and MXenergy Inc. (5)

2.5

 

Second Amendment to Asset Purchase Agreement and Determination Date Loan Documents, dated as of January 10, 2008, by and between PS Energy Group, Inc. and MXenergy Inc. (5)

2.6

 

Third Amendment to Asset Purchase Agreement and Determination Date Loan Documents, dated as of December 31, 2007, by and between PS Energy Group, Inc. and MXenergy Inc. (5)

2.7

 

Fourth Amendment to Asset Purchase Agreement and Determination Date Loan Documents, dated as of January 14, 2008, by and between PS Energy Group, Inc. and MXenergy Inc. (5)

2.8

 

Fifth Amendment to Asset Purchase Agreement and Determination Date Loan Documents, dated as of January 15, 2008, by and between PS Energy Group, Inc. and MXenergy Inc. (5)

2.9

 

Sixth Amendment to Asset Purchase Agreement and Determination Date Loan Documents, dated as of January 22, 2008, by and between PS Energy Group, Inc. and MXenergy Inc. (5)

3.1

 

Second Amended and Restated Certificate of Incorporation of MXenergy Holdings Inc. (21)

3.2

 

Third Amended and Restated Bylaws of MXenergy Holdings Inc. (21)

4.1

 

Indenture, dated as of August 4, 2006, by and among MXenergy Holdings Inc., Law Debenture Trust Company of New York, as trustee, and Deutsche Bank Trust Company Americas, as registrar and paying agent, related to MXenergy’s Floating Rate Senior Notes due 2011 (1)

4.2

 

Supplemental Indenture, dated as of August 1, 2007, by and among MXenergy Holdings Inc., Law Debenture Trust Company of New York, as trustee, and Deutsche Bank Trust Company Americas, as registrar and paying agent, related to MXenergy’s Floating Rate Senior Notes due 2011 (3)

4.3

 

Second Supplemental Indenture, dated as of September 22, 2009, by and among MXenergy Holdings Inc., the subsidiary guarantors party thereto and Law Debenture Trust Company of New York, as trustee, related to MXenergy’s Floating Rate Senior Notes due 2011 (21)

4.4

 

Form of Senior Floating Rate Note due 2011 (included in Exhibit 4.1) (1)

4.5

 

Registration Rights Agreement, dated as of August 4, 2006, by and among MXenergy Holdings Inc., the guarantors named therein and Deutsche Bank Securities Inc. and Morgan Stanley & Co. Incorporated, as initial purchasers (1)

4.6

 

Registration Rights Agreement dated as of June 25, 2004, by and among MXenergy Inc., Denham Commodity Partners Fund LP (formerly known as Sowood Commodity Partners Fund LP) (as successor to Lathi LLC), Charter Mx LLC, Greenhill Capital Partners, L.P., Greenhill Capital Partners (Cayman), L.P., Greenhill Capital Partners (Executives), L.P., Greenhill Capital, L.P., Jeffrey A. Mayer, Carole R. Artman-Hodge and Daniel P. Burke, Sr. (1)

4.7

 

Indenture, dated as of September 22, 2009, by and among MXenergy Holdings Inc., the subsidiary guarantors party thereto and Law Debenture Trust Company of New York, as trustee, related to MXenergy’s 13.25% Senior Subordinated Secured Notes due 2014 (21)

4.8

 

Form of 13.25% Senior Subordinated Secured Note due 2014 (included in Exhibit 4.7) (21)

4.9

 

Intercreditor and Subordination Agreement, dated as of September 22, 2009, by and among MXenergy Holdings Inc., Sempra Energy Trading LLC, as facility agent, the other pledgors from time to time party thereto and Law Debenture Trust Company of New York, as trustee (21)

4.10

 

Notes Registration Rights Agreement, dated as of September 22, 2009, by and among MXenergy Holdings Inc., the subsidiary guarantors party thereto and the holders of 13.25% Senior Subordinated Secured Notes due 2014 party thereto (21)

4.11

 

Equity Registration Rights Agreement, dated as of September 22, 2009, by and among MXenergy Holdings Inc. and the stockholders of MXenergy Holdings Inc. party thereto (21)

9.1

 

Class A Voting Agreement, dated as of September 22, 2009, by and among the holders of Class A common stock party thereto (21)

 

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9.2

 

Class C Voting Agreement, dated as of September 22, 2009, by and among the holders of Class C common stock party thereto (21)

10.1

 

First Amended and Restated Credit Agreement, dated as of August 1, 2006, by and among MXenergy Inc. and MXenergy Electric Inc., as borrowers, MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, lenders party thereto and Société Générale, as administrative agent, syndication agent, lead arranger and sole bookrunner (1)

10.2

 

First Amendment to First Amended and Restated Credit Agreement, dated as of April 6, 2007, by and among MXenergy Inc. and MXenergy Electric Inc., as borrowers, MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, and lenders party thereto (1)

10.3

 

Second Amendment to First Amended and Restated Credit Agreement, dated as of December 17, 2007, by and among MXenergy Inc. and MXenergy Electric Inc., as borrowers, MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, and lenders party thereto (5)

10.4

 

Third Amendment to First Amended and Restated Credit Agreement, dated as of May 12, 2008 but effective as of March 1, 2008, by and among MXenergy Inc. and MXenergy Electric Inc., as borrowers, MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, and lenders party thereto (6)

10.5

 

Second Amended and Restated Credit Agreement, dated as of September 30, 2008, by and among MXenergy Inc. and MXenergy Electric Inc., as borrowers, MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, and lenders party thereto (9)

10.6

 

Waiver Agreement and Amendment No. 1 to Second Amended and Restated Credit Agreement, dated as of November 7, 2008, by and among MXenergy Inc. and MXenergy Electric Inc., as borrowers, MXenergy Holdings Inc. and certain of its subsidiaries, as guarantors, the lenders party thereto and Société Générale, as administrative agent (10)

10.7

 

Third Amended and Restated Credit Agreement, dated as of November 17, 2008, by and among MXenergy Inc. and MXenergy Electric Inc., as borrowers, MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, and lenders party thereto (11)

10.8

 

First Amendment to Third Amended and Restated Credit Agreement, dated as of March 11, 2009, by and among MXenergy Inc. and MXenergy Electric Inc., as borrowers, MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, and lenders party thereto (12)

10.9

 

Second Amendment to Third Amended and Restated Credit Agreement, dated as of May 15, 2009, by and among MXenergy Inc. and MXenergy Electric Inc., as borrowers, MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, and lenders party thereto (13)

10.10

 

Third Amendment and Waiver to Third Amended and Restated Credit Agreement, dated as of May 29, 2009, by and among MXenergy Inc. and MXenergy Electric Inc., as borrowers, MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, the lenders party thereto and Société Générale, as administrative agent (14)

10.11

 

Fourth Amendment and Waiver to the Third Amended and Restated Credit Agreement, dated as of June 8, 2009, by and among MXenergy Inc. and MXenergy Electric Inc., as borrowers, MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, the lenders party thereto and Société Générale, as administrative agent (15)

10.12

 

Fifth Amendment to the Third Amended and Restated Credit Agreement, dated as of June 15, 2009, by and among MXenergy Inc. and MXenergy Electric Inc., as borrowers, MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, the lenders party thereto and Société Générale, as administrative agent (16)

10.13

 

Sixth Amendment, Waiver and Consent to the Third Amended and Restated Credit Agreement, dated as of July 31, 2009, by and among MXenergy Inc. and MXenergy Electric Inc., as borrowers, MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, the lenders party thereto and Société Générale, as administrative agent (17)

10.14

 

Seventh Amendment and Waiver to the Third Amended and Restated Credit Agreement, dated as of August 14, 2009, by and among MXenergy Inc. and MXenergy Electric Inc., as borrowers, MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, the lenders party thereto and Société Générale, as administrative agent (18)

10.15

 

Eighth Amendment and Waiver to the Third Amended and Restated Credit Agreement, dated as of August 31, 2009, by and among MXenergy Inc. and MXenergy Electric Inc., as borrowers, MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, the lenders party thereto and Société Générale, as administrative agent (19)

10.16

 

Ninth Amendment and Waiver to the Third Amended and Restated Credit Agreement, dated as

 

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of September 14, 2009, by and among MXenergy Inc. and MXenergy Electric Inc., as borrowers, MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, the lenders party thereto and Société Générale, as administrative agent (20)

10.17

 

First Amended and Restated Pledge Agreement, dated as of August 1, 2006, by and among MXenergy Inc. and MXenergy Electric Inc., as borrowers, MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, and Société Générale (1)

10.18

 

First Amended and Restated Security Agreement, dated as of August 1, 2006, by and among MXenergy Inc. and MXenergy Electric Inc., as borrowers, MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, and Société Générale (1)

10.19

 

Amended and Restated Loan Agreement, dated as of November 14, 2003, by and between Denham Commodity Partners Fund LP (formerly known as Sowood Commodity Partners Fund LP) (as successor to Lathi LLC) and MXenergy Inc. (1)

10.20

 

Amended and Restated Security Agreement, dated as of November 14, 2003, by and between Denham Commodity Partners Fund LP (formerly known as Sowood Commodity Partners Fund LP) (as successor to Lathi LLC) and MXenergy Inc. (1)

10.21

 

Amendment No. 1 to Amended and Restated Loan Agreement, dated as of March 22, 2004, by and between Denham Commodity Partners Fund LP (formerly known as Sowood Commodity Partners Fund LP) (as successor to Lathi LLC) and MXenergy Inc. (1)

10.22

 

Amendment No. 2 to Amended and Restated Loan Agreement and Amendment No. 1 to Amended and Restated Security Agreement, dated as of December 19, 2005, by and between Denham Commodity Partners Fund LP (formerly known as Sowood Commodity Partners Fund LP) (as successor to Lathi LLC) and MXenergy Inc. (1)

10.23

 

Amendment No. 3 to Amended and Restated Loan Agreement and Amendment No. 2 to Amended and Restated Security Agreement, dated as of August 1, 2006, by and between Denham Commodity Partners Fund LP (formerly known as Sowood Commodity Partners Fund LP) (as successor to Lathi LLC) and MXenergy Inc. (1)

10.24

 

Amendment No. 4 to Amended and Restated Loan Agreement, dated as of January 9, 2008, by and between Denham Commodity Partners Fund LP and MXenergy Inc. (5)

10.25

 

Subordination and Intercreditor Agreement, dated as of December 19, 2005, by and among Société Générale and certain counterparties, Denham Commodity Partners Fund LP (formerly known as Sowood Commodity Partners Fund LP), MXenergy Holdings Inc., MXenergy Inc., MXenergy Electric Inc. and certain of their respective subsidiaries and Virginia Power Energy Marketing, Inc. (1)

10.26

 

Amendment No. 1, dated as of August 1, 2006, to the Subordination and Intercreditor Agreement, dated as of December 19, 2005, by and among Société Générale and certain counterparties, Denham Commodity Partners Fund LP (formerly known as Sowood Commodity Partners Fund LP), MXenergy Holdings Inc., MXenergy Inc. and certain of their respective subsidiaries (1)

10.27

 

Amendment No. 2, dated as of November 7, 2008, to the Subordination and Intercreditor Agreement dated as of December 19, 2005, by and among Société Générale (as Administrative Agent for various secured counterparties), Denham Commodity Partners Fund LP, MXenergy Holdings Inc., MXenergy Inc., MXenergy Electric Inc. and certain of their respective subsidiaries *

10.28

 

Amendment No. 3, dated as of June 8, 2009, to the Subordination and Intercreditor Agreement dated as of December 19, 2005, by and among Société Générale, Denham Commodity Partners Fund LP, MXenergy Holdings Inc., MXenergy Inc., MXenergy Electric Inc. and certain of their respective subsidiaries (15)

10.29

 

Master Transaction Agreement, dated as of August 1, 2006, by and among MXenergy Inc., MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, and Société Générale (1)

10.30

 

First Amendment to Master Transaction Agreement, dated as of April 6, 2007, by and among MXenergy Inc., MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, and Société Générale (1)

10.31

 

Second Amendment to Master Transaction Agreement, dated as of December 17, 2007, by and among MXenergy Inc., MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, and Société Générale (5)

10.32

 

Third Amendment to Master Transaction Agreement, dated as of May 12, 2008, by and among MXenergy Inc., MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, and

 

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Société Générale (6)

10.33

 

Fourth Amendment to Master Transaction Agreement, dated as of July 31, 2008, by and among MXenergy Inc., MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, and Société Générale (8)

10.34

 

Fifth Amendment to Master Transaction Agreement, dated as of September 30, 2008, by and among MXenergy Inc., MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, and Société Générale (7)

10.35

 

Sixth Amendment to Master Transaction Agreement, dated as of November 5, 2008, by and among MXenergy Inc., MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, and Société Générale (10)

10.36

 

Seventh Amendment to Master Transaction Agreement, dated as of November 7, 2008, by and among MXenergy Inc., MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, and Société Générale (10)

10.37

 

Eighth Amendment to Master Transaction Agreement, dated as of November 17, 2008, by and among MXenergy Inc., MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, and Société Générale (11)

10.38

 

Ninth Amendment to Master Transaction Agreement, dated as of March 16, 2009, by and among MXenergy Inc., MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, and Société Générale (12)

10.39

 

Tenth Amendment to Master Transaction Agreement, dated as of May 15, 2009, by and among MXenergy Inc., MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, and Société Générale (13)

10.40

 

Eleventh Amendment to Master Transaction Agreement, dated as of May 29, 2009, by and among MXenergy Inc., MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, and Société Générale, as hedge provider (14)

10.41

 

Twelfth Amendment to the Master Transaction Agreement, dated as of June 8, 2009, by and among MXenergy Inc., MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, and Société Générale, as hedge provider (15)

10.42

 

Thirteenth Amendment to the Master Transaction Agreement, dated as of July 31, 2009, by and among MXenergy Inc., MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, and Société Générale, as hedge provider (17)

10.43

 

Fourteenth Amendment to the Master Transaction Agreement, dated as of August 14, 2009, by and among MXenergy Inc., MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, and Société Générale, as hedge provider (18)

10.44

 

Fifteenth Amendment to the Master Transaction Agreement, dated as of August 31, 2009, by and among MXenergy Inc., MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, and Société Générale, as hedge provider (19)

10.45

 

Sixteenth Amendment to the Master Transaction Agreement, dated as of September 3, 2009, by and among MXenergy Inc., MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, and Société Générale, as hedge provider *

10.46

 

Seventeenth Amendment and Waiver to the Master Transaction Agreement, dated as of September 14, 2009, by and among MXenergy Inc., MXenergy Holdings Inc. and certain subsidiaries thereof, as guarantors, and Société Générale, as hedge provider (20)

10.47

 

Third Amended and Restated Stockholders’ Agreement, dated as of June 25, 2004, by and among MXenergy Inc., Charter Mx LLC, Denham Commodity Partners Fund LP (formerly known as Sowood Commodity Partners Fund LP) (as successor to Lathi LLC), Jeffrey A. Mayer, Carole R. Artman-Hodge, Daniel P. Burke and certain other investors party thereto (1)

10.48

 

First Amendment to Third Amended and Restated Stockholders’ Agreement, dated as of June 9, 2008, by and among MXenergy Inc., Charter Mx LLC, Denham Commodity Partners Fund LP (formerly known as Sowood Commodity Partners Fund LP) (as successor to Lathi LLC), and stockholders holding a majority of the outstanding shares of Voting Stock as of the effective date (7)

10.49

 

Transition Services Agreement, dated as of August 1, 2006, by and between MXenergy Inc. and Shell Energy Services Company L.L.C. (1)

10.50

 

Employment Agreement, dated as of February 13, 2008, by and between MXenergy Inc. and Jeffrey Mayer #(5)

10.51

 

Employment Agreement, dated as of August 4, 2006, by and between MXenergy Inc. and Steven Murray #(1)

 

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10.52

 

Supplemental Employment Agreement, dated as of July 31, 2009, by and between MXenergy Inc. and Steven Murray #*

10.53

 

Employment Agreement, dated as of April 1, 1999, by and between MXenergy Inc. and Carole R. (“Robi”) Artman- Hodge #(1)

10.54

 

Employment Agreement, dated as of February 13, 2008, by and between MXenergy Inc. and Chaitu Parikh #(5)

10.55

 

Employment Agreement, dated as of December 24, 2004, by and between MXenergy Inc. and Thomas Hartmann #(1)

10.56

 

Employment Agreement, dated as of June 13, 2007, by and between MXenergy Inc. and Gina Goldberg #(4)

10.57

 

Employment Agreement, dated as of August 14, 2006, by and between MXenergy Inc. and Robert Werner #(4)

10.58

 

2001 Stock Option Plan, as amended (1)

10.59

 

2003 Stock Option Plan, as amended (1)

10.60

 

2006 Equity Incentive Compensation Plan (1)

10.61

 

Form of Award Agreement under 2001 Stock Option Plan #(1)

10.62

 

Form of Award Agreement under 2003 Stock Option Plan #(1)

10.63

 

Form of Stock Option Award Agreement under 2006 Equity Incentive Compensation Plan #(1)

10.64

 

Financial Advisory Agreement, dated as of May 1, 2007, by and between MXenergy Inc. and Greenhill & Co., LLC (1)

10.65

 

ISDA Master Agreement, dated as of September 22, 2009, between Sempra Energy Trading LLC and MXenergy Inc. (including the schedule thereto) (21)

10.66

 

ISDA Master Agreement, dated as of September 22, 2009, between Sempra Energy Trading LLC and MXenergy Electric Inc. (including the schedule thereto) (21)

10.67

 

Guarantee and Collateral Agreement, dated as of September 22, 2009, among MXenergy Holdings Inc., MXenergy Electric Inc., MXenergy Inc. and the other subsidiaries of MXenergy Holdings Inc. party thereto, as grantors, and Sempra Energy Trading LLC, as secured party (21)

10.68

 

Stockholders Agreement, dated as of September 22, 2009, by and among MXenergy Holdings Inc. and the stockholders of MXenergy Holdings Inc. party thereto (21)

10.69

 

Amendment and Waiver Agreement, dated as of September 22, 2009, among MXenergy Holdings Inc. and the stockholders of MXenergy Holdings Inc. party thereto (21)

10.70

 

Amendment and Waiver Agreement, dated as of September 22, 2009, among MXenergy Holdings Inc. and the stockholders of MXenergy Holdings Inc. party thereto (21)

10.71

 

Second Lien Collateral Agreement, dated as of September 22, 2009, by and among MXenergy Holdings Inc., the subsidiary guarantors party thereto and Law Debenture Trust Company of New York, as collateral agent (21)

10.72

 

Notes Escrow and Security Agreement, dated as of September 22, 2009, by and among MXenergy Holdings Inc., Law Debenture Trust Company of New York, as trustee, and Law Debenture Trust Company of New York, as collateral agent (21)

10.73

 

Form of Guarantee of 13.25% Senior Subordinated Notes due 2014 (included in Exhibit 4.7) (21)

21

 

Subsidiaries of MXenergy Holdings Inc. *

31.1

 

Certification as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 *

31.2

 

Certification as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 *

32

 

Certification required by 18 United States Code Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 *†

 


*

 

Filed herewith.

 

 

 

 

Pursuant to Securities and Exchange Commission Release No. 33-8238, this certification will be treated as “accompanying” this Annual Report on Form 10-K and not “filed” as part of such report for purposes of Section 18 of the Securities Exchange Act of 1934, or otherwise subject to the liability of Section 18 of the Securities Exchange Act of 1934 and this certification will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that the registrant specifically incorporates it by reference.

 

#

 

Material compensation contract.

 

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(1)

 

Incorporated by reference to the Company’s Registration Statement on Form S-4 (File No. 333-138425) declared effective on April 30, 2007.

 

 

 

(2)

 

Incorporated by reference to the Company’s Current Report on Form 8-K filed on November 14, 2007.

 

 

 

(3)

 

Incorporated by reference to the Company’s Current Report on Form 8-K filed on August 7, 2007.

 

 

 

(4)

 

Incorporated by reference to the Company’s Annual Report on Form 10-K for the fiscal year ended June 30, 2007.

 

 

 

(5)

 

Incorporated by reference to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended December 31, 2007.

 

 

 

(6)

 

Incorporated by reference to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2008.

 

 

 

(7)

 

Incorporated by reference to the Company’s Annual Report on Form 10-K for the fiscal year ended June 30, 2008.

 

 

 

(8)

 

Incorporated by reference to the Company’s Current Report on Form 8-K filed on August 1, 2008.

 

 

 

(9)

 

Incorporated by reference to the Company’s Current Report on Form 8-K filed on October 2, 2008.

 

 

 

(10)

 

Incorporated by reference to the Company’s Current Report on Form 8-K filed on November 12, 2008.

 

 

 

(11)

 

Incorporated by reference to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2008.

 

 

 

(12)

 

Incorporated by reference to the Company’s Current Report on Form 8-K filed on March 18, 2009.

 

 

 

(13)

 

Incorporated by reference to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2009.

 

 

 

(14)

 

Incorporated by reference to the Company’s Current Report on Form 8-K filed on June 3, 2009.

 

 

 

(15)

 

Incorporated by reference to the Company’s Current Report on Form 8-K filed on June 12, 2009.

 

 

 

(16)

 

Incorporated by reference to the Company’s Current Report on Form 8-K filed on June 18, 2009.

 

 

 

(17)

 

Incorporated by reference to the Company’s Current Report on Form 8-K filed on August 3, 2009.

 

 

 

(18)

 

Incorporated by reference to the Company’s Current Report on Form 8-K filed on August 18, 2009.

 

 

 

(19)

 

Incorporated by reference to the Company’s Current Report on Form 8-K filed on September 3, 2009.

 

 

 

(20)

 

Incorporated by reference to the Company’s Current Report on Form 8-K filed on September 16, 2009.

 

 

 

(21)

 

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

 

154