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Table of Contents

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 


 

FORM 10-Q

 

(Mark One)

 

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

 

For the quarterly period ended December 31, 2010

 

OR

 

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

 

For the transition period from                    to                   

 

Commission File Number 333-138425

 


 

MXENERGY HOLDINGS INC.

(Exact Name of Registrant as Specified in Its Charter)

 

Delaware

 

20-2930908

(State or Other Jurisdiction of

 

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

Incorporation or Organization)

 

 

 

 

 

595 Summer Street, Suite 300

 

 

Stamford, Connecticut

 

06901

(Address of Principal Executive Offices)

 

(Zip Code)

 

(203) 356-1318

(Registrant’s telephone number, including area code)

 


 

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

 

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

 

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

 

Large accelerated filer o

 

Accelerated filer o

 

 

 

Non-accelerated filer x

 

Smaller reporting company o

 

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

 

As of January 31, 2011, there were 33,710,902 shares of the Registrant’s Class A Common Stock (par value $0.01 per share), 4,002,290 shares of the Registrant’s Class B Common Stock (par value $0.01 per share) and 17,007,965 shares of the Registrant’s Class C Common Stock (par value $0.01 per share) outstanding.

 

Documents incorporated by reference: None

 


*  The registrant is not currently required to submit electronically and post Interactive Data Files in accordance with Rule 405 of Regulation S-T.

 

 

 



Table of Contents

 

MXENERGY HOLDINGS INC.

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED DECEMBER 31, 2010

 

TABLE OF CONTENTS

 

Item
Number

 

 

Page
Number

 

 

 

 

PART I — FINANCIAL INFORMATION

 

 

 

 

 

Cautionary Note Regarding Forward-Looking Statements

3

 

 

 

 

1.

 

Financial Statements (unaudited):

 

 

 

Condensed Consolidated Balance Sheets at December 31, 2010 and June 30, 2010

4

 

 

Condensed Consolidated Statements of Operations for the Three Months and Six Months Ended December 31, 2010 and 2009

5

 

 

Condensed Consolidated Statements of Stockholders’ Equity for the Six Months Ended December 31, 2010 and 2009

6

 

 

Condensed Consolidated Statements of Cash Flows for the Six Months Ended December 31, 2010 and 2009

7

 

 

Notes to Condensed Consolidated Financial Statements

8

2.

 

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

33

3.

 

Quantitative and Qualitative Disclosures about Market Risk

55

4T.

 

Controls and Procedures

59

 

 

 

 

PART II — OTHER INFORMATION

 

 

 

 

 

1.

 

Legal Proceedings

60

1A.

 

Risk Factors

60

2.

 

Unregistered Sales of Equity Securities and Use of Proceeds

60

3.

 

Defaults Upon Senior Securities

60

4.

 

(Removed and Reserved)

60

5.

 

Other Information

60

6.

 

Exhibits

60

 

 

 

 

 

 

Signatures

61

 



Table of Contents

 

PART I — FINANCIAL INFORMATION

 

Cautionary Note Regarding Forward-Looking Statements

 

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

 

·                  future performance generally;

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

·                  our post-acquisition integration of acquired businesses;

·                  expectations concerning future operations, margins, profitability, attrition, bad debts, expenses, interest rates, liquidity and capital resources; and

·                  expectations regarding the effectiveness of our hedging practices and the performance of suppliers, pipelines and transmission companies, storage operators, independent system operators, financial hedge providers, banks providing working capital and other counterparties supplying, transporting, and storing physical commodity.

 

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

 

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

 

·                  failures in our risk management policies and hedging procedures;

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

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

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

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

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

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

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

·                  failure to collect imbalance receivables;

·                  inaccuracy of data in our billing systems;

·                  disruptions in local transportation and transmission facilities;

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

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

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

·                  failure to properly manage our growth;

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

·                  changes in general economic conditions;

·                  competition from utilities and other marketers;

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

·                  natural disasters, including hurricanes; and

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

 

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

 

3



Table of Contents

 

Item 1 — Financial Statements

 

MXENERGY HOLDINGS INC.

Condensed Consolidated Balance Sheets (Unaudited)

(dollars in thousands)

 

 

 

Balance at

 

 

 

December 31, 
2010

 

June 30, 
2010

 

 

 

 

 

 

 

Assets

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

 

$

4,288

 

$

6,220

 

Restricted cash

 

1,683

 

1,574

 

Fixed Rate Notes Escrow Account (Note 14)

 

8,977

 

8,977

 

Accounts receivable from customers and LDCs, net (Note 5)

 

115,256

 

48,925

 

Accounts receivable from RBS Sempra, net (Note 13)

 

 

43,054

 

Natural gas inventories (Note 6)

 

16,918

 

15,861

 

Current portion of unrealized gains from risk management activities, net (Notes 11 and 12)

 

1,830

 

 

Income taxes receivable

 

6,959

 

6,063

 

Deferred income taxes (Note 9)

 

994

 

1,378

 

Other current assets (Note 7)

 

12,906

 

16,272

 

Total current assets

 

169,811

 

148,324

 

Goodwill

 

3,810

 

3,810

 

Customer acquisition costs, net (Note 8)

 

33,708

 

30,425

 

Fixed assets, net

 

3,756

 

2,739

 

Deferred income taxes (Note 9)

 

7,644

 

3,629

 

Deferred debt issuance costs (Notes 13, 14 and 15)

 

10,190

 

12,552

 

Other assets

 

529

 

541

 

Total assets

 

$

229,448

 

$

202,020

 

 

 

 

 

 

 

Liabilities and stockholders’ equity

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Accounts payable and accrued liabilities (Note 10)

 

$

29,821

 

$

30,302

 

Accounts payable to RBS Sempra, net (Note 13)

 

31,027

 

 

Current portion of unrealized losses from risk management activities, net (Notes 11 and 12)

 

4,257

 

16,731

 

Deferred revenue

 

10,276

 

7,457

 

Current portion of long-term debt (Note 14)

 

6,394

 

 

Total current liabilities

 

81,775

 

54,490

 

Unrealized losses from risk management activities, net (Notes 11 and 12)

 

 

1,857

 

Long-term debt (Note 14)

 

54,174

 

58,722

 

Other long-term liabilities (Note 9)

 

3,756

 

 

Total liabilities

 

139,705

 

115,069

 

 

 

 

 

 

 

Commitments and contingencies (Note 17)

 

 

 

 

 

 

 

 

 

Stockholders’ equity:

 

 

 

 

 

Common stock (Note 15)

 

 

 

 

 

Class A Common Stock (par value $0.01; 50,000,000 shares authorized; 33,940,683 shares issued and 33,710,902 shares outstanding at December 31, 2010 and June 30, 2010)

 

339

 

339

 

Class B Common Stock (par value $0.01; 10,000,000 shares authorized; 4,002,290 shares issued and outstanding at December 31, 2010 and June 30, 2010)

 

40

 

40

 

Class C Common Stock (par value $0.01; 40,000,000 shares authorized; 17,007,965 shares and 16,413,159 shares issued and outstanding at December 31, 2010 and June 30, 2010, respectively)

 

170

 

164

 

Total common stock

 

549

 

543

 

Additional paid-in capital

 

140,316

 

139,702

 

Class A treasury stock (229,781 shares at December 31, 2010 and June 30, 2010)

 

(99

)

(99

)

Accumulated other comprehensive loss

 

(255

)

(156

)

Accumulated deficit

 

(50,768

)

(53,039

)

Total stockholders’ equity

 

89,743

 

86,951

 

Total liabilities and stockholders’ equity

 

$

229,448

 

$

202,020

 

 

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

 

4



Table of Contents

 

MXENERGY HOLDINGS INC.

Condensed Consolidated Statements of Operations (Unaudited)

(dollars in thousands)

 

 

 

Three Months Ended  
December 31,

 

 

 

2010

 

2009

 

 

 

 

 

 

 

Sales of natural gas and electricity

 

$

183,816

 

$

152,769

 

Cost of goods sold (excluding depreciation and amortization):

 

 

 

 

 

Cost of natural gas and electricity sold

 

131,493

 

97,855

 

Realized losses from risk management activities, net

 

11,512

 

19,328

 

Unrealized gains from risk management activities, net

 

(17,153

)

(16,713

)

 

 

125,852

 

100,470

 

Gross profit

 

57,964

 

52,299

 

 

 

 

 

 

 

Operating expenses:

 

 

 

 

 

General and administrative expenses

 

14,949

 

12,415

 

Advertising and marketing expenses

 

1,698

 

390

 

Reserves and discounts

 

2,660

 

1,972

 

Depreciation and amortization

 

6,551

 

5,275

 

Total operating expenses

 

25,858

 

20,052

 

 

 

 

 

 

 

Operating profit

 

32,106

 

32,247

 

Interest expense, net of interest income of $11 and $8, respectively

 

7,250

 

8,248

 

Income before income tax benefit (expense)

 

24,856

 

23,999

 

Income tax benefit (expense)

 

846

 

(5,774

)

Net income

 

$

25,702

 

$

18,225

 

 

 

 

Six Months Ended  
December 31,

 

 

 

2010

 

2009

 

 

 

 

 

 

 

Sales of natural gas and electricity

 

$

278,180

 

$

228,742

 

Cost of goods sold (excluding depreciation and amortization):

 

 

 

 

 

Cost of natural gas and electricity sold

 

211,353

 

146,666

 

Realized losses from risk management activities, net

 

15,076

 

33,235

 

Unrealized gains from risk management activities, net

 

(14,274

)

(28,452

)

 

 

212,155

 

151,449

 

Gross profit

 

66,025

 

77,293

 

 

 

 

 

 

 

Operating expenses:

 

 

 

 

 

General and administrative expenses

 

30,626

 

26,912

 

Advertising and marketing expenses

 

3,123

 

742

 

Reserves and discounts

 

4,714

 

3,815

 

Depreciation and amortization

 

12,180

 

10,896

 

Total operating expenses

 

50,643

 

42,365

 

 

 

 

 

 

 

Operating profit

 

15,382

 

34,928

 

Interest expense, net of interest income of $47 and $57, respectively

 

13,957

 

21,165

 

Income before income tax benefit (expense)

 

1,425

 

13,763

 

Income tax benefit (expense)

 

846

 

(5,774

)

Net income

 

$

2,271

 

$

7,989

 

 

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

 

5



Table of Contents

 

MXENERGY HOLDINGS INC.

Condensed Consolidated Statements of Stockholders’ Equity (Unaudited)

(dollars in thousands)

 

 

 

Six Months Ended December 31, 2010

 

 

 

Common
Stock

 

Additional
Paid-in
Capital

 

Class A 
Treasury 
Stock

 

Accumulated
Other
Comprehensive
Loss

 

Retained
Earnings
 
(Accumulated
Deficit)

 

Total
Stockholders’
Equity

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance at June 30, 2010

 

$

543

 

$

139,702

 

$

(99

)

$

(156

)

$

(53,039

)

$

86,951

 

Issuance of Class C Common Stock

 

10

 

 

 

 

 

10

 

Retirement of Class C Common Stock

 

(4

)

(1,167

)

 

 

 

 

(1,171

)

Stock compensation expense

 

 

1,781

 

 

 

 

1,781

 

Comprehensive loss:

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

 

 

 

 

2,271

 

2,271

 

Foreign currency translation loss

 

 

 

 

(99

)

 

(99

)

Total comprehensive income

 

 

 

 

 

 

 

 

 

 

 

2,172

 

Balance at December 31, 2010

 

$

 549

 

$

140,316

 

$

(99

)

$

(255

)

$

(50,768

)

$

89,743

 

 

 

 

Six Months Ended December 31, 2009

 

 

 

Common
Stock

 

Additional
Paid-in
Capital

 

Class A 
Treasury
 
Stock

 

Accumulated
Other
Comprehensive
Loss

 

(Accumulated
Deficit) 
Retained 
Earnings

 

Total
Stockholders’
Equity

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance at June 30, 2009

 

$

47

 

$

18,275

 

$

 

$

(3

)

$

(90,469

)

$

(72,150

)

Issuance of Class A Common Stock

 

339

 

81,468

 

 

 

 

81,807

 

Issuance of Class B Common Stock

 

40

 

9,005

 

 

 

 

9,045

 

Issuance of Class C Common Stock

 

164

 

28,591

 

 

 

 

28,755

 

Acquisition of Class A Treasury Stock

 

 

 

(99

)

 

 

(99

)

Cancellation of common stock

 

(47

)

 

 

 

 

(47

)

Stock compensation benefit

 

 

(117

)

 

 

 

(117

)

Revaluation of redeemable convertible preferred stock

 

 

 

 

 

25,925

 

25,925

 

Comprehensive income:

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

 

 

 

 

7,989

 

7,989

 

Foreign currency translation

 

 

 

 

(150

)

 

(150

)

Total comprehensive income

 

 

 

 

 

 

 

 

 

 

 

7,839

 

Balance at December 31, 2009

 

$

543

 

$

137,222

 

$

(99

)

$

(153

)

$

(56,555

)

$

80,958

 

 

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

 

6



Table of Contents

 

MXENERGY HOLDINGS INC.

Condensed Consolidated Statements of Cash Flows (Unaudited)

(dollars in thousands)

 

 

 

Six Months Ended 
December 31,

 

 

 

2010

 

2009

 

 

 

 

 

 

 

Operating activities:

 

 

 

 

 

Net income

 

$

2,271

 

$

7,989

 

Adjustments to reconcile net income to net cash provided by operating activities:

 

 

 

 

 

Unrealized gains from risk management activities, net

 

(14,274

)

(28,452

)

Stock compensation expense (benefit)

 

1,781

 

(117

)

Provision for doubtful accounts

 

3,200

 

3,096

 

Depreciation and amortization

 

12,180

 

10,896

 

Deferred tax (benefit) expense

 

(3,631

)

5,774

 

Non-cash interest expense, primarily unrealized losses on interest rate swaps and amortization of debt issuance costs

 

6,008

 

7,059

 

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

 

 

 

 

 

Restricted cash

 

(109

)

73,111

 

Accounts receivable

 

(69,531

)

(48,305

)

Accounts receivable — RBS Sempra

 

43,054

 

 

Natural gas inventories

 

(1,057

)

1,062

 

Income taxes receivable

 

(896

)

(930

)

Fixed Rate Notes Escrow Account

 

 

(8,977

)

Option premiums

 

66

 

(335

)

Other assets

 

(403

)

(2,149

)

Customer acquisition costs

 

(14,435

)

(6,009

)

Accounts payable and accrued liabilities

 

(481

)

(13,086

)

Accounts payable — RBS Sempra

 

31,027

 

26,324

 

Deferred revenue

 

2,819

 

5,613

 

Other long-term liabilities

 

3,756

 

 

Net cash provided by operating activities

 

1,345

 

32,564

 

 

 

 

 

 

 

Investing activities:

 

 

 

 

 

Asset acquisitions and business combinations

 

(117

)

(207

)

Purchases of fixed assets

 

(1,928

)

(445

)

Net cash used in investing activities

 

(2,045

)

(652

)

 

 

 

 

 

 

Financing activities:

 

 

 

 

 

Repayment of Floating Rate Notes due 2011

 

 

(26,700

)

Repayment of Denham Credit Facility

 

 

(12,000

)

Repayment of Bridge Financing Loans under the Revolving Credit Facility

 

 

(5,400

)

Debt issuance costs

 

(71

)

(6,220

)

Payroll taxes paid in connection with issuance of common stock from RSUs

 

(1,161

)

 

Acquisition of Class A treasury stock

 

 

(99

)

Stock issuance costs

 

 

(329

)

Net cash used in financing activities

 

(1,232

)

(50,748

)

Net decrease in cash and cash equivalents

 

(1,932

)

(18,836

)

Cash and cash equivalents at beginning of period

 

6,220

 

23,266

 

Cash and cash equivalents at end of period

 

$

4,288

 

$

4,430

 

 

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

 

7



Table of Contents

 

MXENERGY HOLDINGS INC.

Notes to Condensed Consolidated Financial Statements (Unaudited)

Three Months and Six Months Ended December 31, 2010

 

Note 1.   Organization and Basis of Presentation

 

MXenergy Holdings Inc. (“Holdings”) was founded in 1999 as a retail energy marketer, and was incorporated in Delaware on January 24, 2005 as part of a corporate reorganization.  The two principal operating subsidiaries of Holdings are MXenergy Inc. and MXenergy Electric Inc., which are engaged in the marketing and supply of natural gas and electricity, respectively.  Holdings and its subsidiaries (collectively, the “Company”) collectively operate in 41 market areas located in 14 states in the United States (the “U.S.”) and in two Canadian provinces.

 

The accompanying unaudited condensed consolidated financial statements of the Company have been prepared in accordance with requirements of the Securities and Exchange Commission (the “SEC”).  Accordingly, they do not include all of the information and footnotes required by accounting principles generally accepted in the U.S. (“U.S. GAAP”) for complete financial statements.  The condensed consolidated balance sheet at June 30, 2010 was derived from the audited consolidated financial statements included in the Company’s Annual Report on Form 10-K for the fiscal year ended June 30, 2010 (the “2010 Form 10-K”), but does not include all of the information and footnotes required by U.S. GAAP for complete financial statements.  These unaudited condensed consolidated financial statements should be read in conjunction with the 2010 Form 10-K.

 

In the opinion of management, all normal and recurring adjustments considered necessary for a fair presentation of financial position, results of operations and cash flows for the interim periods have been made.  The accounting and reporting policies of the Company are consistent, in all material respects, with those used to prepare the 2010 Form 10-K, except for the impact, if any, of new accounting pronouncements summarized in Note 2 below.  The preparation of financial statements in conformity with U.S. GAAP requires the use of estimates and assumptions that affect reported amounts and disclosures.  Actual amounts could differ from those estimates.  Interim results should not be considered indicative of results for future periods.

 

Certain reclassifications have been made to prior period amounts to conform to the current period presentations.  Capitalized customer acquisition costs of $6.0 million were reclassified from investing activities to operating activities on the consolidated statement of cash flows for the six months ended December 31, 2009.

 

Note 2.   New Accounting Pronouncements

 

Accounting Pronouncements Adopted During the Six Months Ended December 31, 2010

 

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

 

The requirement to disclose purchases, sales, issuances and settlements of instruments that are valued using Level 3 measurements on a gross basis became effective and were adopted for the Company’s quarterly reporting period ended September 30, 2010.  The adoption of this provision of ASU 2010-06 did not have any impact on the Company’s financial statement disclosures as of December 31, 2010.

 

Accounting Pronouncements Not Yet Adopted as of December 31, 2010

 

In December 2010, the FASB issued Accounting Standards Update No. 2010-28 (“ASU 2010-28”), which amends FASB ASC Topic 350, “Intangibles — Goodwill and Other.”  The amended guidance in ASU 2010-28 modifies Step 1 of the goodwill impairment test for reporting units with zero or negative carrying amounts.  For those units, the amendments in ASU 2010-28 require an entity to perform Step 2 of the goodwill impairment test if it is more likely than not that a goodwill impairment exists.  In determining whether it is more likely than not that an impairment loss exists, an entity should consider

 

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whether there are any adverse qualitative factors indicating that an impairment loss may exist.  ASU 2010-28 will become effective for the Company’s interim reporting period ending March 31, 2011.  Adoption of the provisions of ASU 2010-28 is not expected to have any impact on the Company’s financial position, results of operations or financial statement disclosures.

 

Note 3.  Debt and Equity Restructuring

 

In September 2009, the Company completed a debt and equity restructuring (the “Restructuring”), which included a number of transactions and amendments to corporate documents.  Material impacts of the Restructuring on the Company’s financial position, results of operations and cash flows were disclosed in the consolidated financial statements included in the Company’s 2010 Form 10-K.

 

The Restructuring resulted in the following material sources and uses of cash during the six months ended December 31, 2009:

 

·                  $75.0 million of restricted cash was released to operating cash upon maturity of the Company’s former supply and hedging facilities;

·                  $26.7 million was paid to holders of Holdings’ floating rate senior notes due 2011 (the “Floating Rate Notes due 2011”) in partial exchange for their notes;

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

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

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

·                  $5.4 million of principal outstanding of bridge financing loans under the Company’s former credit facility (the “Bridge Financing Loans”), plus accrued and unpaid interest, were repaid and the Bridge Financing Loans were terminated.

 

In connection with the Restructuring, the Company recorded approximately $2.2 million of incremental, non-recurring general and administrative expenses during the three months ended September 30, 2009, including $0.8 million of Restructuring-related bonuses, $1.2 million of professional fees incurred in connection with various potential liquidity events considered prior to completion of the Restructuring and $0.2 million of staff severance costs.

 

Note 4.   Seasonality of Operations

 

Natural gas and electricity sales accounted for approximately 65% and 35%, respectively, of the Company’s total sales for the six months ended December 31, 2010 and 82% and 18%, respectively, of the Company’s total sales for the fiscal year ended June 30, 2010.  The mix of natural gas and electricity sales varies significantly during the reporting quarters within the Company’s fiscal year due to the seasonality of its natural gas and electricity businesses.  The majority of natural gas customer consumption occurs during the months of November through March.  By contrast, electricity customer consumption peaks during the months of June through September.  Because the natural gas business segment comprises such a large component of the Company’s overall business operations for its entire fiscal year, the second and third fiscal quarters represent the seasonal peak of operating results for the Company’s full fiscal year.

 

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

 

Weather conditions have a significant impact on customer demand and market prices for natural gas and electricity.  Customer demand exposes the Company to a high degree of seasonality in sales, cost of sales, billing and collection of customer accounts receivable, inventory requirements and cash flows.  In addition, budget billing programs and payment terms of local distribution companies (“LDCs”) can cause timing differences between the billing and collection of accounts receivable and the recording of revenues.

 

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

 

Note 5.   Accounts Receivable from Customers and LDCs, Net

 

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

 

 

 

Balances at 

 

 

 

December 31, 
2010

 

June 30,
2010

 

 

 

(in thousands)

 

Billed customer accounts receivable:

 

 

 

 

 

Guaranteed by LDCs

 

$

 34,605

 

$

 11,736

 

Non-guaranteed by LDCs

 

25,860

 

21,543

 

 

 

60,465

 

33,279

 

Unbilled customer accounts receivable (1):

 

 

 

 

 

Guaranteed by LDCs

 

32,805

 

10,206

 

Non-guaranteed by LDCs

 

23,143

 

7,211

 

 

 

55,948

 

17,417

 

Total customer accounts receivable

 

116,413

 

50,696

 

Less: Allowance for doubtful accounts

 

(4,860

)

(5,074

)

Customer accounts receivable, net

 

111,553

 

45,622

 

Cash imbalance settlements and other receivables, net (2)

 

3,703

 

3,303

 

Accounts receivable, net

 

$

 115,256

 

$

 48,925

 

 


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

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

 

The Company operates in 41 market areas located in 14 U.S. states and two Canadian provinces.  The Company’s diversified geographic coverage reduces the credit exposure that 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.

 

Imbalance settlements represent differences between the natural gas or electricity delivered to LDCs or independent service operators (“ISOs”) for consumption by our customers and actual usage by our customers.  We expect that such imbalances will be settled with cash within twelve months 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 or ISOs.  These receivables are generally due from counterparties with investment grade credit ratings.

 

The Company has limited exposure to risk associated with high concentrations of sales volumes with individual customers.  In April 2010, the Company began delivering natural gas to an LDC in Ohio as part of a Standard Service Offer program (the “SSO Program”).  As a result of the Company’s participation in the SSO Program, the LDC in Ohio became the Company’s largest single customer, accounting for approximately 17% of the Company’s natural gas sales volume for the six months ended December 31, 2010.  Under the SSO Program, for the 12-month period from April 1, 2010 through March 31, 2011, the Company will receive a NYMEX-referenced price plus a price adjustment for natural gas delivered by the LDC to its customers who are eligible to participate in the SSO Program.  The Company will no longer participate in the SSO Program effective April 1, 2011.  The Company’s largest electricity customer accounted for less than 1% of the Company’s electricity sales volume.

 

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 December 31, 2010, and for the six months 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, credit quality and accounts receivable concentrations are provided in the following table.

 

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Table of Contents

 

 

 

Three Months ended 
December 31,

 

Six Months ended 
December 31,

 

 

 

2010

 

2009

 

2010

 

2009

 

 

 

(in thousands)

 

Allowance for doubtful accounts activity:

 

 

 

 

 

 

 

 

 

Balance at beginning of period

 

$

4,480

 

$

6,340

 

$

5,074

 

$

7,344

 

Add: Provision for doubtful accounts

 

1,808

 

1,503

 

3,200

 

3,096

 

Less: Net charge offs of customer accounts receivable

 

(1,428

)

(2,715

)

(3,414

)

(5,312

)

Balance at end of period

 

$

4,860

 

$

5,128

 

$

4,860

 

$

5,128

 

 

 

 

 

 

 

 

 

 

 

Credit quality statistics:

 

 

 

 

 

 

 

 

 

Allowance for doubtful accounts as a percentage of total customer accounts receivable in non-guaranteed markets at end of period

 

9.9

%

9.2

%

9.9

%

9.2

%

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

 

2.7

%

1.9

%

2.9

%

2.4

%

 

 

 

 

 

 

 

 

 

 

Percentage of total sales of natural gas and electricity:

 

 

 

 

 

 

 

 

 

In markets where LDCs guarantee customer accounts receivable (1)

 

63

%

48

%

61

%

44

%

In markets where LDCs do not guarantee customer accounts receivable

 

37

%

52

%

39

%

56

%

 


(1)         For fiscal year 2011, higher percentage of revenue in guaranteed markets primarily reflects incremental revenues related to the SSO Program, and revenue in new electricity markets where customer accounts receivable are guaranteed by the LDC.

 

The allowance for doubtful accounts as a percentage of total customer accounts receivable in non-guaranteed markets fluctuates significantly during the Company’s fiscal year depending on seasonal sales activity.  The percentage is generally lower at December 31 and March 31, when total customer accounts receivable is high and aged accounts receivable are a relatively small percentage of the total.  The percentage is generally higher at June 30 and September 30, when total customer accounts receivable is low and aged accounts receivable are a relatively large percentage of the total.

 

Certain LDCs guarantee billed and unbilled customer accounts receivable or amounts due for delivered gas and electricity, which mitigates the Company’s direct credit risk since the Company is exposed only to the credit risk of the LDC, rather than that of its customers.  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.  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 December 31, 2010, all of the Company’s customer accounts receivable in LDC-guaranteed markets were with LDCs with investment grade credit ratings.

 

Note 6.  Natural Gas Inventories

 

Natural gas inventories are summarized in the following table.

 

 

 

Balances at

 

 

 

December 31, 
2010

 

June 30, 
2010

 

 

 

(in thousands)

 

 

 

 

 

 

 

Storage inventory for delivery to customers

 

$

11,097

 

$

9,956

 

Imbalance settlements in-kind (1)

 

5,821

 

5,905

 

Total

 

$

16,918

 

$

15,861

 

 


(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.   The Company expects these inventories to be transferred to the Company or its customers within the upcoming 12-month period.

 

The Company reports the volume of natural gas held in storage in million British thermal units (“MMBtus”), which is a standard unit of heating equivalent measure for natural gas.  The increase in storage inventory for delivery to customers from June 30, 2010 to December 31, 2010 was primarily due to normal seasonal accumulation of natural gas held in storage for the

 

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Company to serve its natural gas customers during the winter season.  The volume of natural gas held in storage increased 28% from 1.8 million MMBtus at June 30, 2010 to 2.3 million MMBtus at December 31, 2010.

 

Natural gas inventories are valued on a weighted-average cost basis, which includes related transportation and storage costs, and which does not exceed net realizable value.  The weighted-average cost per MMBtu of natural gas held in storage decreased 10% from June 30, 2010 to December 31, 2010.

 

Note 7.  Other Current Assets

 

Other current assets are summarized in the following table.

 

 

 

Balance at

 

 

 

December 31, 
2010

 

June 30,
2010

 

 

 

(in thousands)

 

Security deposits:

 

 

 

 

 

Collateral required by hedging counterparties (1)

 

$

4,090

 

$

6,180

 

Collateral posted in connection with the SSO Program

 

4,569

 

4,569

 

Collateral required by transmission, pipeline and transportation counterparties

 

1,745

 

3,295

 

Prepaid expenses

 

1,491

 

1,448

 

Other

 

1,011

 

780

 

Total other current assets

 

$

12,906

 

$

16,272

 

 


(1)         Primarily includes cash collateral required to secure unrealized losses from risk management activities associated with interest rate swaps (refer to Note 11).

 

Note 8.  Customer Acquisition Costs, Net

 

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

 

 

 

Balance at December 31, 2010

 

 

 

Gross 
Book Value

 

Accumulated
Amortization

 

Net Book 
Value

 

 

 

(in thousands)

 

Customer contracts acquired from:

 

 

 

 

 

 

 

Asset acquisitions and business combinations (1)

 

$

8,313

 

$

(8,085

)

$

228

 

Success-based third-party marketing activities

 

50,050

 

(20,762

)

29,288

 

Hourly-paid third-party direct-response telemarketing activities

 

11,347

 

(7,155

)

4,192

 

Totals

 

$

69,710

 

$

(36,002

)

$

33,708

 

 

 

 

Balance at June 30, 2010

 

 

 

Gross 
Book Value

 

Accumulated
Amortization

 

Net Book Value

 

 

 

(in thousands)

 

Customer contracts acquired from:

 

 

 

 

 

 

 

Asset acquisitions and business combinations (1)

 

$

8,196

 

$

(6,424

)

$

1,772

 

Success-based third-party marketing activities

 

42,010

 

(17,237

)

24,773

 

Hourly-paid, third-party direct-response telemarketing activities

 

13,261

 

(9,381

)

3,880

 

Totals

 

$

63,467

 

$

(33,042

)

$

30,425

 

 


(1)         Includes the fair value of customer portfolios acquired in transactions accounted for as asset acquisitions or business combinations.  Also includes contingent consideration paid by the Company subsequent to the acquisition date in accordance with the respective acquisition agreements.  The Company’s most recent asset acquisition or business combination was completed in October 2008.

 

Amortization expense associated with capitalized customer acquisition costs was $6.1 million and $4.8 million for the three months ended December 31, 2010 and 2009, respectively, and $11.3 million and $9.5 million for the six months ended December 31, 2010 and 2009, respectively.  Amortization expense associated with customer acquisition costs capitalized as of December 31, 2010 is expected to approximate $9.8 million for the remainder of fiscal year 2011, $13.8 million for fiscal year 2012, $9.0 million for fiscal year 2013 and $1.1 million for fiscal year 2014.  At December 31, 2010, the weighted average remaining amortization period associated with all customer acquisition costs was approximately 1.5 years.

 

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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 six months ended December 31, 2010, no impairment was indicated as a result of these comparisons.

 

Note 9.   Income Taxes

 

The Company’s effective income tax rate was a benefit of 3.4% and expense of 24.1% for the three months ended December 31, 2010 and 2009, respectively.  The Company’s effective income tax rate was a benefit of 59.4% and expense of 42.0% for the six months ended December 31, 2010 and 2009, respectively.

 

The effective income tax rate for the three months and six months ended December 31, 2010 included adjustments necessary to conform the Company’s tax provision to its tax return to be filed for the fiscal year ended June 30, 2010.  These adjustments resulted in a net tax benefit of $1.4 million and a significant reduction in the effective income tax rate for the three months and six months ended December 31, 2010.

 

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.  Such valuation allowance is deducted from deferred income tax assets on the consolidated balance sheets.  As of December 31, 2010 and June 30, 2010, 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’s valuation allowances of $23.3 million and $28.1 million at December 31, 2010 and June 30, 2010, respectively, related to non-recovery of deferred tax assets.  The change during the period related to the provision to return adjustments for prior years.

 

During the three months ended December 31, 2010, the Company recorded an unrecognized tax benefit of approximately $3.8 million, which is included in other long-term liabilities on the consolidated balance sheet at December 31, 2010.  This liability relates to the timing of expense recognition and does not impact the effective tax rate.

 

Note 10.   Accounts Payable and Accrued Liabilities

 

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

 

 

 

Balance at

 

 

 

December 31, 
2010

 

June 30, 
2010

 

 

 

(in thousands)

 

 

 

 

 

 

 

Trade accounts payable and accrued liabilities (1)

 

$

17,174

 

$

16,069

 

Accrued commodity purchases

 

2,901

 

2,083

 

Interest payable

 

3,990

 

3,951

 

Payroll and related expenses

 

3,102

 

4,301

 

Sales and other taxes

 

1,909

 

1,630

 

Other

 

745

 

2,268

 

Total accounts payable and accrued liabilities

 

$

29,821

 

$

30,302

 

 


(1)         Includes $0.1 million and $0.2 million due to related parties at December 31, 2010 and June 30, 2010, respectively, for legal services, financial advisory services and management fees.  Refer to Note 16 for additional information regarding related party transactions.

 

Note 11.  Derivatives and Hedging Activities

 

The Company is exposed to commodity price risk and interest rate risk related to its business operations, which it manages with derivative instruments.  The Company has a risk management policy that is intended to reduce its financial exposure related to changes in the price of natural gas and electricity and to changes in the interest rates associated with its exclusive credit, supply and commodity hedging agreement (the “Commodity Supply Facility”) with Sempra Energy Trading LLC (“RBS Sempra”) and the Floating Rate Notes due 2011.  The Company’s risk management policy defines various risk management controls and limits that are designed to monitor its commodity price risk position and ensure that hedging performance is in line with objectives established by its board of directors (the “Board of Directors”) and management.  Speculative trading activities are explicitly prohibited under the Company’s risk management policy.

 

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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 (gains) losses from risk management activities in the consolidated statements of operations with offsetting adjustments to unrealized gains or losses from risk management activities in the consolidated balance sheets.  Unrealized gains from risk management activities on the consolidated balance sheets represent receivables from derivative counterparties, net of amounts due to the same counterparties when master netting agreements exist.  Unrealized losses from risk management activities represent liabilities to 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 settlement price as quoted on New York Mercantile Exchange (“NYMEX”) or other published index.

 

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).

 

The Company utilizes the Commodity Supply Facility to enter into swaps, basis swaps and options to economically hedge the risk of variability in the cost of natural gas and electricity.  As of December 31, 2010, the Company has the ability to enter into new derivative transactions through August 2012 under the Commodity Supply Facility, and the terms of such transactions may extend through October 2013.

 

As of December 31, 2010, the Company had entered into forward physical contracts with RBS Sempra to purchase natural gas and electricity beginning in January 2011 and ending in October 2011.  Based on the terms of these purchases, most of these contracts are accounted for as derivative instruments under U.S. GAAP, and are therefore included in the fair value measurements reported by the Company as of December 31, 2010.  Certain of the Company’s forward physical contracts qualify as “normal purchases” under U.S. GAAP and are therefore not reported on the consolidated balance sheets at December 31, 2010.

 

Weather Risk Management Activities

 

The Company is exposed to weather-related risk during its peak seasonal operating periods for natural gas and electricity.  Unusually warm temperatures during the winter months or unusually cool temperatures during the summer months can have a negative impact on the Company’s results of operations.  As of December 31, 2010, the Company entered into a heating degree day (“HDD”) derivative agreement to mitigate the risk that actual temperatures experienced in its largest natural gas market during January 2011 may be warmer than normally experienced in that market based on historical weather data.

 

Interest Rate Risk Management Activities

 

The Company manages its exposure to interest rate fluctuations by utilizing interest rate swaps to effectively convert the interest rate exposure from a variable rate to a fixed rate of interest.  Under the Commodity Supply Facility, the Company is subject to variable interest rates in connection with cash borrowings and credit support, primarily in the form of letters of credit, provided by RBS Sempra.  The total amount of letters of credit outstanding under the Commodity Supply Facility will fluctuate throughout the Company’s fiscal year due to the seasonality of its business.  As of December 31, 2010, approximately $31.1 million of letters of credit were outstanding under the Commodity Supply Facility.  The Company is also exposed to interest rate fluctuations in connection with the $6.4 million aggregate principal amount of Floating Rate Notes due 2011 that was outstanding at December 31, 2010.

 

As of December 31, 2010, an $80.0 million fixed-for-floating interest rate swap was outstanding, which expires on August 1, 2011, and which effectively fixes the six-month LIBOR rate at 5.72% per annum.  During the fiscal year ended June 30, 2010, the $80.0 million interest rate swap agreement was novated to RBS Sempra from the previous counterparty, as required by the terms of the Commodity Supply Facility.  Such novation did not have any impact on the Company’s rights, obligations, risks or accounting methodology associated with the interest rate swap agreement.

 

As of December 31, 2010 and June 30, 2010, the total unrealized loss from risk management activities on the consolidated balance sheets related to interest rate swaps was approximately $4.1 million and $6.0 million, respectively.  The Company was required to post $4.1 million and $6.0 million of cash collateral at December 31, 2010 and June 30, 2010, respectively, which is recorded in other current assets on the consolidated balance sheets, for its mark-to-market exposure related to the outstanding interest rate swap agreement.

 

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Table of Contents

 

Derivatives Activity

 

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

 

 

 

Open Positions as of

 

 

 

December 31, 
2010

 

June 30, 
2010

 

 

 

 

 

 

 

Natural gas instruments (amounts reflected in MMBtus) (1):

 

 

 

 

 

Financial forward derivative contracts:

 

 

 

 

 

NYMEX-referenced over the counter contracts

 

20,313,000

 

21,358,000

 

Basis contracts

 

19,109,000

 

18,794,000

 

Option contracts

 

1,870,000

 

550,000

 

Physical forward contracts (2):

 

 

 

 

 

Physical fixed contracts

 

4,884,000

 

4,218,000

 

Physical basis contracts

 

856,000

 

276,000

 

Physical index contracts

 

526,000

 

1,375,000

 

 

 

 

 

 

 

Electricity instruments (amounts reflected in MWhrs) (3):

 

 

 

 

 

Financial forward derivative contracts:

 

 

 

 

 

Swaps and fixed price contracts

 

748,000

 

677,000

 

Physical forward contracts (2)

 

95,000

 

139,000

 

 

 

 

 

 

 

Interest rate swaps (in millions)

 

$

80.0

 

$

80.0

 

 


(1)          MMBtus represent a standard unit of heating equivalent measure for natural gas. A unit of heat equal to 1,000,000 Btus, or 1 MMBtu, is the thermal equivalent of approximately 1,000 cubic feet of natural gas.

(2)          Represents agreements for the purchase and sale of natural gas or electricity that are accounted for as derivatives because the Company did not elect the “normal purchases and sales” exclusion under U.S. GAAP.

(3)          Megawatt Hours (“MWhrs”) represent 1 million watt hours or a thousand kilowatt hours, which is the amount of electric energy produced or consumed in a period of time.

 

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

 

Type of Derivative

 

Location on the Consolidated Balance Sheet

 

Prior to 
Netting

 

Impact of 
Master Netting 
Agreements

 

After Netting

 

 

 

 

 

(in thousands)

 

Fair value as of December 31, 2010:

 

 

 

 

 

 

 

Asset derivatives:

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

Unrealized gains from risk management activities, net

 

$

25,695

 

$

(23,865

)

$

1,830

 

Total

 

 

 

$

25,695

 

$

(23,865

)

$

1,830

 

 

 

 

 

 

 

 

 

 

 

Liability Derivatives:

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

Unrealized losses from risk management activities, net

 

$

23,865

 

$

(23,865

)

$

 

Weather derivatives

 

Unrealized losses from risk management activities, net

 

116

 

 

116

 

Interest rate derivatives

 

Unrealized losses from risk management activities, net

 

4,141

 

 

4,141

 

Total

 

 

 

$

28,122

 

$

(23,865

)

$

4,257

 

 

 

 

 

 

 

 

 

 

 

Fair value as of June 30, 2010:

 

 

 

 

 

 

 

Asset derivatives:

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

Unrealized gains from risk management activities, net

 

$

13,756

 

$

(13,756

)

$

 

Total

 

 

 

$

13,756

 

$

(13,756

)

$

 

 

 

 

 

 

 

  

 

 

 

Liability Derivatives:

 

 

 

 

 

  

 

 

 

Commodity derivatives

 

Unrealized losses from risk management activities, net

 

$

26,315

 

$

(13,756

)

$

12,559

 

Interest rate derivatives

 

Unrealized losses from risk management activities, net

 

 6,029

 

  —

 

 6,029

 

Total

 

 

 

$

32,344

 

$

(13,756

)

$

18,588

 

 

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

 

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Table of Contents

 

Type of Derivative

 

Location of (Gains) Losses Recognized on the 

 

Amount of (Gains) Losses 
Recognized for the Three 
Months Ended December 
31,

 

Instrument

 

Consolidated Statement of Operations

 

2010

 

2009

 

 

 

 

 

(in thousands)

 

 

 

 

 

 

 

 

 

Commodity

 

Cost of goods sold — realized losses from risk management activities, net

 

$

11,512

 

$

19,328

 

Commodity

 

Cost of goods sold — unrealized gains from risk management activities, net

 

(17,269

)

(16,713

)

Weather

 

Cost of goods sold — unrealized gains from risk management activities, net

 

116

 

 

Interest rate

 

Interest expense, net of interest income

 

11

 

419

 

Total

 

 

 

$

(5,630

)

$

3,034

 

 

Type of Derivative

 

Location of (Gains) Losses Recognized on the 

 

Amount of (Gains) Losses 
Recognized for the Six 
Months Ended December 
31,

 

Instrument

 

Consolidated Statement of Operations

 

2010

 

2009

 

 

 

 

 

(in thousands)

 

 

 

 

 

 

 

 

 

Commodity

 

Cost of goods sold — realized losses from risk management activities, net

 

$

15,076

 

$

33,235

 

Commodity

 

Cost of goods sold — unrealized gains from risk management activities, net

 

(14,390

)

(28,452

)

Weather

 

Cost of goods sold — unrealized gains from risk management activities, net

 

116

 

 

Interest rate

 

Interest expense, net of interest income

 

(1,888

)

1,391

 

Total

 

 

 

$

(1,086

)

$

6,174

 

 

The Company is exposed to credit risk associated with its economic hedging program and derivative financial instruments.  Credit risk relates to the potential 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 Commodity Supply Facility, the Company’s risk management activities are with a financial institution that has an investment grade credit rating.  The Company’s risk management policy sets forth guidelines for monitoring, managing and mitigating credit risk exposures, establishes credit limits and requires ongoing financial reviews of counterparties.

 

Note 12.  Fair Value of Financial Instruments

 

The Company measures assets and liabilities associated with various financial forward derivative instruments and physical forward purchase and sale agreements at fair value on a recurring basis.  The recorded values of derivative instruments reflect management’s best estimate of fair value.  The Company generally utilizes a market approach for its recurring fair value measurements.  In forming its fair value estimates, the Company utilizes the most observable inputs available for the respective valuation technique.  If a fair value measurement reflects inputs from different levels within the fair value hierarchy, the measurement is classified based on the lowest level of input that is significant to the fair value measurement.  The key inputs and assumptions utilized for the fair value measurements recorded by the Company are summarized as follows:

 

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

 

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

 

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

 

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enhancements, if any, and time value.

 

Heating degree day swaps — Heating degree day swaps are valued by multiplying an agreed-upon dollar value by the number of HDDs that are projected to be in excess of or less than an agreed-upon HDD strike amount.

 

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

 

The Company categorizes its fair value measurements in accordance with a fair value hierarchy that prioritizes the assumptions, or “inputs,” used in applying valuation techniques.  The three levels of inputs within the fair value hierarchy are:

 

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

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

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

 

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

 

 

 

Balance at December 31, 2010

 

 

 

Level 1

 

Level 2

 

Level 3

 

Total

 

 

 

(in thousands)

 

Assets:

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

$

 

$

1,830

 

$

 

$

1,830

 

Total

 

$

 

$

1,830

 

$

 

$

1,830

 

 

 

 

 

 

 

 

 

 

 

Liabilities:

 

 

 

 

 

 

 

 

 

Weather derivatives

 

$

 

$

116

 

$

 

$

116

 

Interest rate derivatives

 

 

4,141

 

 

4,141

 

Total

 

$

 

$

4,257

 

$

 

$

4,257

 

 

 

 

Balance at June 30, 2010

 

 

 

Level 1

 

Level 2

 

Level 3

 

Total

 

 

 

(in thousands)

 

Liabilities:

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

$

 

$

12,559

 

$

 

$

12,559

 

Interest rate derivatives

 

 

6,029

 

 

6,029

 

Total

 

$

 

$

18,588

 

$

 

$

18,588

 

 

The aggregate principal amount of long-term debt recorded on the consolidated balance sheets, before original issue discount, is $73.7 million at December 31, 2010 (refer to Note 14).  The Company has elected not to record the Fixed Rate Notes due 2014 or the Floating Rate Notes due 2011 at fair value.  Utilizing observable market data, the aggregate fair value of long-term debt was approximately $69.3 million as of December 31, 2010.

 

Note 13.  Commodity Supply Facility

 

In connection with the Restructuring (refer to Note 3), all of the Company’s former supply and commodity hedging facilities were terminated and were replaced by the Commodity Supply Facility.  The Commodity Supply Facility provides for the exclusive supply of physical (other than as needed for balancing) and financial natural gas and electricity, credit support (including letters of credit and guarantees) for certain collateral needs, cash advances for natural gas inventory and seasonal financing as needed, and associated hedging transactions in order to maintain the balanced trading book required by the Company’s risk management policies.

 

The Commodity Supply Facility is governed by separate master supply and hedge agreements for natural gas and electricity

 

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(the “ISDA Master Agreements”).  Under the Commodity Supply Facility, the primary obligors are Holdings’ two significant operating subsidiaries, MXenergy Inc. and MXenergy Electric Inc. All obligations under the Commodity Supply Facility are guaranteed by Holdings and its other domestic subsidiaries and are secured by a first priority lien on substantially all existing and future assets of Holdings and its domestic subsidiaries other than the Fixed Rate Notes Escrow Account defined in Note 3.   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.  RBS Sempra may give such notice no earlier than April 30, 2011 and no later than 180 days prior to the then current termination date.

 

RBS Sempra has indicated its intent to complete an orderly sale of its assets including, but not limited to, the entity that provides our Commodity Supply Facility.  Although the Company has received assurances from RBS Sempra that it will continue to fulfill its obligations under the Commodity Supply Facility, the Company is actively exploring alternatives for potential new supply, credit and hedging counterparties.

 

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

 

As of December 31, 2010, the Company had a Collateral Coverage Ratio of approximately 2.12:1.00.  The calculation of the Collateral Coverage Ratio as of December 31, 2010 resulted in available liquidity of approximately $58.5 million, of which $45.0 million represents the maximum credit available for cash advances and $13.5 million represents excess liquidity that can be used for additional letters of credit, commodity purchases and other operating purposes.  At December 31, 2010, the Company had no outstanding cash advances and had $31.1 million of letters of credit outstanding under the Commodity Supply Facility.

 

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

 

During the first contract year of the Commodity Supply Facility, the Company’s actual purchases of natural gas and electricity from RBS Sempra exceeded the minimum purchase obligations.  Under the terms of the ISDA Master Agreements, such excess of actual purchases over the minimum purchase obligations are deducted from the minimum purchases requirement for the second contract year of the Commodity Supply Facility.  As of December 31, 2010, the commodity to be purchased for delivery to the Company’s customers during the second contract year of the Commodity Supply Facility is expected to exceed the minimum purchase obligation for natural gas and electricity for that year.

 

With regard to the Company’s fixed price customer mix, the Company may not, without the prior written consent of RBS Sempra, enter into any fixed price contracts, excluding renewals of existing fixed price contracts, if:

 

·                  During any 12-month period, more than 75% of all residential customer equivalents (“RCEs”) have been added under fixed price contracts;

·                  During any 12-month period, more than 235,000 RCEs have been added under fixed price contracts; and

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

 

The Company received a limited waiver from RBS Sempra, which allowed the Company to add more than 235,000 RCEs under fixed price contracts during the first contract year of the Commodity Supply Facility.

 

The Company incurred approximately $10.8 million of legal fees, consulting fees and other costs directly related to the Commodity Supply Facility, which were recorded as deferred debt issuance costs on the consolidated balance sheets, and which are being amortized as an increase to interest expense over the remaining term of the Commodity Supply Facility. 

 

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These deferred costs include the value of 4,002,290 shares of Class B Common Stock issued to RBS Sempra in connection with the Restructuring (refer to Note 15).  Amortization expense associated with these deferred costs was approximately $0.9 million for the three months ended December 31, 2010 and 2009 and $1.8 million and $1.0 million for the six months ended December 31, 2010 and 2009, respectively.

 

Transaction fees and interest expense associated with activity under the Commodity Supply Facility are included in interest expense, net of interest income on the consolidated statements of operations.  The Company recorded approximately $2.6 million and $3.1 million of fee and interest expense during the three months ended December 31, 2010 and 2009, respectively, and $4.6 million and $3.2 million of fee and interest expense during the six months ended December 31, 2010 and 2009, respectively, in connection with activity under the Commodity Supply Facility.

 

Other key provisions of the ISDA Master Agreements are described in the consolidated financial statements included in the Company’s 2010 Form 10-K.  As of December 31, 2010, the Company was in compliance with all provisions of the ISDA Master Agreements.

 

Accounts Receivable from RBS Sempra, Net and Accounts Payable to RBS Sempra, Net

 

The ISDA Master Agreements include provisions that allow for net settlement of various amounts due from or due to RBS Sempra resulting from activity under the Commodity Supply Facility.  Amounts due from or due to RBS Sempra are summarized in the following table.

 

 

 

Balances at

 

Amount receivable from (payable to) RBS Sempra for:

 

December 31, 
2010

 

June 30, 
2010

 

 

 

(in thousands)

 

 

 

 

 

 

 

 

 

Cash received and held by RBS Sempra (1)

 

$

24,621

 

$

64,819

 

Commodity purchases from RBS Sempra

 

(54,070

)

(19,030

)

Transportation costs, derivative settlements, interest and fees charged by RBS Sempra

 

(1,578

)

(2,735

)

Accounts (payable to) receivable from RBS Sempra, net on the consolidated balance sheet

 

$

(31,027

)

$

43,054

 

 


(1)          In connection with the Commodity Supply Facility, certain banking relationships that previously belonged to the Company are now under RBS Sempra’s name and control.  RBS Sempra releases cash to the Company as required to meet the Company’s ongoing operating cash requirements.

 

Note 14.  Long-Term Debt

 

Long-term debt is summarized in the following table.

 

 

 

Balance at December 31, 2010

 

 

 

Aggregate 
Debt 
Balance

 

Unamortized 
Discount

 

Net 
Book
Value

 

 

 

(in thousands)

 

 

 

 

 

 

 

 

 

Current portion of long-term debt:

 

 

 

 

 

 

 

Floating Rate Notes due 2011

 

$

6,413

 

$

19

 

$

6,394

 

 

 

 

 

 

 

 

 

Long-term debt:

 

 

 

 

 

 

 

Fixed Rate Notes due 2014

 

67,293

 

$

13,119

 

$

54,174

 

Total debt

 

$

73,706

 

$

13,138

 

$

60,568

 

 

 

 

Balance at June 30, 2010

 

 

 

Aggregate 
Debt 
Balance

 

Unamortized 
Discount

 

Net 
Book
Value

 

 

 

(in thousands)

 

Long-term debt:

 

 

 

 

 

 

 

Fixed Rate Notes due 2014

 

$

67,293

 

$

14,949

 

$

52,344

 

Floating Rate Notes due 2011

 

6,413

 

35

 

6,378

 

Total debt

 

$

73,706

 

$

14,984

 

$

58,722

 

 

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In connection with the Restructuring (refer to Note 3), the Company exchanged $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.  This debt exchange transaction was accounted for as a troubled-debt restructuring in accordance with U.S. GAAP.

 

Fixed Rate Notes due 2014

 

The Fixed Rate Notes due 2014 will mature on August 1, 2014 and bear interest at the rate of 13.25% per annum, which is payable in cash semi-annually on February 1 and August 1 of each year.  Interest expense associated with the Fixed Rate Notes due 2014 was approximately $2.3 million for the three months ended December 31, 2010 and 2009 and approximately $4.5 million and $2.5 million for the six months ended December 31, 2010 and 2009, respectively.

 

The Fixed Rate Notes due 2014 were issued at a discount of approximately $17.8 million, which was recorded as a reduction from the Fixed Rate Notes due 2014 balance on the Company’s consolidated balance sheets, and which is being amortized as an increase to interest expense over the remaining life of the Fixed Rate Notes due 2014.  Total interest expense associated with amortization of this discount was approximately $0.9 million for the three months ended December 31, 2010 and 2009 and $1.8 million and $1.0 million for the six months ended December 31, 2010 and 2009, respectively.

 

The Company incurred approximately $5.3 million of legal fees, consulting fees and other costs directly related to issuance of the Fixed Rate Notes due 2014, which were recorded as deferred debt issuance costs on the consolidated balance sheets, and which are being amortized as an increase to interest expense over the remaining term of the Fixed Rate Notes due 2014.  Total interest expense associated with amortization of these deferred costs was approximately $0.3 million for the three months ended December 31, 2010 and 2009 and approximately $0.6 million and $0.3 million for the six months ended December 31, 2010 and 2009, respectively.

 

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

 

The Fixed Rate Notes due 2014 are secured by a first priority security interest in the Fixed Rate Notes Escrow Account and by a second priority security interest in substantially all other existing and future assets of the Company.  The Fixed Rate Notes Escrow Account balance of approximately $9.0 million approximates the interest payable by the Company on the Fixed Rate Notes due 2014 for a 12-month period.

 

The key provisions of the indenture that governs the Fixed Rate Notes due 2014 are fully described in the consolidated financial statements included in the Company’s 2010 Form 10-K.  As of December 31, 2010, the Company was in compliance with all provisions of the indenture.

 

Holdings has no significant independent operations.  Each of Holdings’ domestic subsidiaries jointly and severally, fully and unconditionally guarantees the Fixed Rate Notes due 2014.  Refer to Note 19 for consolidating financial statements for Holdings and its guarantor and non-guarantor subsidiaries.

 

On December 15, 2010, the Company commenced an offer to exchange its outstanding original Fixed Rate Notes due 2014 (the “Original Fixed Rate Notes”), which were not registered under the Securities Act, for an equal principal amount of new Fixed Rate Notes due 2014 (the “Registered Fixed Rate Notes”) which are registered under the Securities Act.  On January 18, 2011, the Company exchanged $66.6 million aggregate principal amount of Original Fixed Rate Notes for an equal principal amount of Registered Fixed Rate Notes.  Holders of approximately $1.2 million of Original Fixed Rate Notes did not exchange their notes for Registered Fixed Rate Notes.

 

Pursuant to the terms of the registration rights agreement relating to the Original Fixed Rate Notes, the interest rate applicable to the Original Fixed Rate Notes increased by 0.25% per annum effective as of September 30, 2010, and by an additional 0.25% effective as of December 29, 2010, because the Company did not complete an exchange offer for the Original Fixed Rate Notes within five business days following the one year anniversary of the issue date of the Original Fixed Rate Notes.  When the exchange offer was completed on January 18, 2011, the Company ceased accruing additional interest on the Original Fixed Rate Notes.  The Company recorded less than $0.1 million of incremental interest expense through the closing date of the exchange offer on January 18, 2011.

 

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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 Floating Rate Notes due 2011 were issued at 97.5% of par value and bear interest at LIBOR plus 7.5% per annum.  Each of Holdings’ domestic subsidiaries jointly and severally, fully and unconditionally guarantees the Floating Rate Notes due 2011.  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 8.18% and 7.88% at December 31, 2010 and June 30, 2010, respectively.

 

During fiscal years 2007 and 2008, the Company purchased $24.8 million aggregate principal amount of outstanding Floating Rate Notes due 2011, plus accrued interest, from noteholders for amounts less than face value.

 

In connection with the Restructuring (refer to Note 3), 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.  Holders of approximately $6.4 million aggregate principal amount of Floating Rate Notes due 2011 did not tender their notes pursuant to the Restructuring.  These Floating Rate Notes due 2011 will remain outstanding until their maturity date in August 2011 unless acquired or retired by the Company sooner.  The indenture governing the Floating Rate Notes due 2011 was amended to eliminate substantially all of the restrictive covenants and certain events of default from such indenture.

 

As a result of the exchange offer consummated during the Restructuring, the average aggregate outstanding balance of Floating Rate Notes due 2011 decreased to $6.4 million for the first six months of fiscal year 2011 from $78.0 million for the same period in the prior fiscal year.  The weighted-average interest rate was 8.13% and 8.55% for the six months ended December 31, 2010 and 2009, respectively.  Interest expense accrued in connection with the Floating Rate Notes due 2011 was approximately $0.1 million for the three months ended December 31, 2010 and 2009 and approximately $0.3 million and $3.4 million for the six months ended December 31, 2010 and 2009, respectively.

 

The aggregate total amortization of original issue discount and deferred debt issuance costs associated with the Floating Rate Notes due 2011 was less than $0.1 million for the three months ended December 31, 2010 and 2009 and less than $0.1 million and $3.6 million for the six months ended December 31, 2010 and 2009, respectively.  Amortization for the six months ended December 31, 2009 includes the pro rata portion of discount and deferred costs associated with the Floating Rate Notes due 2011 exchanged in connection with the Restructuring.

 

The Company has entered into interest rate swap agreements to economically hedge the floating rate interest expense on the Floating Rate Notes due 2011 (refer to Note 11).

 

Note 15. Common Stock

 

On September 22, 2009, 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.  Effective July 27, 2010, the Company’s certificate of incorporation and bylaws were further amended and restated and the stockholders agreement among holders of all classes of common stock, dated September 22, 2009 (the “Stockholders Agreement”), was amended.  The second amended and restated certificate of incorporation, dated September 22, 2009, authorized issuance of new classes of common stock and changed the size and composition of the Company’s Board of Directors.  The third amended and restated certificate of incorporation, dated July 27, 2010 (the “Third Amended and Restated Certificate of Incorporation”), lowered director and committee member compensation, reduced the number of committees of the Board of Directors and revised the definitions of “Financial Expert” and “Independent Director.”  The fourth amended and restated certificate of incorporation, dated November 17, 2010 (the “Certificate of Incorporation”), (i) changed the Company’s registered agent and registered office, (ii) provided that the levels of compensation for directors and committee members specified in the Third Amended and Restated Certificate of Incorporation apply to all non-management directors and (iii) clarified that a director will only be paid one meeting attendance fee per day regardless of the number of Board of Directors or Board of Director committee meetings attended by such director on a given day.

 

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

 

·                  50,000,000 shares of Class A Common Stock.  Holders of the Class A Common Stock are not subject to any transfer restrictions and are entitled to nominate and elect five directors to the Board of Directors, at least two of whom shall be independent and qualify as a “financial expert,” as such term is defined in the Certificate of Incorporation.

 

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

 

·                  40,000,000 shares of Class C Common Stock.  Holders of Class C Common Stock who are current or former employees of the Company or any of its subsidiaries may not transfer their shares (except by will or in connection with customary estate planning) until the third anniversary of the closing date of the Restructuring and, in the case of shares acquired pursuant to the 2010 Stock Incentive Plan implemented by the Company (the “2010 SIP”), as otherwise provided in the 2010 SIP.  Transfers of shares of Class C Common Stock are subject to a right of first refusal in favor of the holders of shares of Class A Common Stock and holders of shares of Class B Common Stock.  Holders of Class C Common Stock are entitled to nominate and elect two directors to the Board of Directors.

 

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

 

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

 

·                  33,940,683 shares of Class A Common Stock to holders of the Fixed Rate Notes due 2014, which represented 62.5% of the aggregate shares of common stock outstanding after the consummation of the Restructuring.

 

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

 

·                  11,862,551 shares of Class C Common Stock to holders of redeemable convertible preferred stock issued and outstanding prior to the Restructuring, which represented 21.84% of the aggregate shares of the common stock outstanding after consummation of the Restructuring.

 

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

 

Stock-Based Compensation Activity

 

As approved by Holdings’ stockholders in connection with the Restructuring, in January 2010, Holdings’ Board of Directors authorized the creation of the 2010 SIP, pursuant to which the Company may issue Class C Common Stock not to exceed 10% of Holdings’ outstanding common stock (on a fully diluted basis) after giving effect to the Restructuring.  Also in January 2010, Holdings’ Board of Directors approved grants of restricted stock units (“RSUs”) to certain senior officers, directors and a former director, pursuant to which the Company may issue 2,960,204 shares of Class C Common Stock, representing 5% of Holdings’ outstanding common stock (on a fully-diluted basis), as follows:

 

·                  2,858,164 RSUs, with a grant date fair value of approximately $6.3 million, were granted to certain senior officers of the Company, subject to vesting according to the following schedule: (i) one-third vested in September 2010; (ii) one-third will vest in September 2011; and (iii) one-third will vest in September 2012;

·                  102,040 RSUs, with a grant date fair value of approximately $0.2 million, were granted to directors and a former director of Holdings, subject to vesting according to the following schedule: (i) 25% vested in January 2010; (ii) 25% vested in April 2010; (iii) 25% vested in July 2010; and (iv) 25% vested in October 2010.  As a result of the resignation and replacement of a director during fiscal year 2010, 5,102 previously granted RSUs were forfeited by the original grantee in July 2010 and 5,102 RSUs were granted to the new director of Holdings in August 2010 subject to vesting according to the following schedule: (i) 50% vested in August 2010; and (ii) 50% vested in October 2010.

 

22



Table of Contents

 

On September 22, 2010, the Company issued 952,721 shares of Class C Common Stock to certain senior officers of the Company when a portion of their RSUs vested without restrictions.  Pursuant to the cashless exercise provisions of the 2010 SIP, senior officers surrendered 408,936 shares of Class C Common Stock back to the Company to offset the taxable nature of the shares to the senior officers.  The Company paid approximately $1.2 million of employer and employee payroll taxes in connection with this issuance of Class C Common Stock.

 

The Company issued an aggregate total of 25,510 shares of Class C Common Stock to directors of the Company on July 1, 2010 and October 1, 2010 and 2,551 shares of Class C Common Stock to a director on August 22, 2010 when a portion of their RSUs vested without restrictions.

 

The Company recorded approximately $0.5 million and $1.8 million of non-cash compensation expense in connection with outstanding RSUs during the three months and six months ended December 31, 2010, respectively.  The Company expects to record approximately $1.0 million, $1.1 million and $0.2 million of compensation expense related to outstanding RSU awards during the remainder of fiscal year 2011 and during fiscal years 2012 and 2013, respectively.

 

Note 16.  Related Party Transactions

 

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

 

 

 

Three Months ended 
December 31,

 

Six Months ended 
December 31,

 

 

 

2010

 

2009

 

2010

 

2009

 

 

 

(in thousands)

 

Amount paid or accrued for:

 

 

 

 

 

 

 

 

 

Legal services

 

$

219

 

$

341

 

$

838

 

$

1,949

 

Management and consulting fees

 

90

 

3

 

109

 

67

 

Interest expense — Denham Credit Facility (1)

 

 

 

 

246

 

Interest expense — Bridge Financing Loans (1)

 

 

 

 

197

 

Financial advisory services (1)

 

 

 

 

32

 

 


(1)          Includes activity related to agreements in place at June 30, 2009, all of which were terminated in September 2009 in connection with the Restructuring.  Refer to the Company’s 2010 Form 10-K for additional information regarding these arrangements.

 

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

 

The Company has entered into agreements with various stockholders, directors, former directors and other related parties for management and consulting services.  None of these agreements had a material impact on the Company’s results of operations during the six months ended December 31, 2010 or 2009.  As of December 31, 2010, the Company does not anticipate that any outstanding management and consulting agreement will have a material impact on results of operations for the remainder of fiscal year 2011 or for fiscal year 2012.

 

Note 17.  Commitments and Contingencies

 

Capacity Commitments

 

The Company enters into agreements for transportation and storage of natural gas.  Since the demand for natural gas in the winter is high, the Company agreed to pay for certain capacity on the transportation systems utilized for up to a 12-month period.  These take-or-pay agreements obligate the Company to pay for the capacity committed even if it does not use that capacity.  For contracts outstanding as of December 31, 2010, the total committed capacity charges were approximately $2.0 million.  Total amounts purchased under such agreements were approximately $10.4 million and $8.8 million for the three months ended December 31, 2010 and 2009, respectively, and approximately $19.7 million and $16.4 million for the six months ended December 31, 2010 and 2009, respectively.  These agreements are due to expire during various months during the twelve months ending December 31, 2011, and may be replaced with new contracts as necessary.

 

23



Table of Contents

 

Physical Commodity Purchase Commitments

 

Under the Commodity Supply Facility, the Company is obligated to purchase minimum annual amounts of natural gas and electricity from RBS Sempra.  Refer to Note 13 for additional information regarding the minimum purchase obligations under the Commodity Supply Facility.

 

Operating Leases

 

In September 2010, the Company entered into an amendment to an expiring operating lease agreement for its Maryland office, which extended the term of the lease to September 2016.  As of December 31, 2010, future annual minimum lease payments associated with the extended lease are expected to be $0.1 million for the remainder of fiscal year 2011, $0.2 million for fiscal years 2012 through 2014 and $0.6 million thereafter.

 

Legal Proceedings and Environmental Matters

 

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

 

During fiscal years 2011 and 2010, the Company does not have physical custody or control of the natural gas provided to its customers, or any facilities used to produce or transport natural gas or electricity.  Although the Company holds title to natural gas in interstate pipelines and storage tanks, it believes that the carriers have the liability risk associated with infrastructure failures that could cause environmental issues.  Therefore, the Company does not believe that it has significant exposure to legal claims or other liabilities associated with environmental concerns.

 

Note 18.  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.

 

The Company’s principal operations are located in the U.S.  Its foreign operations, which are located in Canada, comprised less than 1% of the Company’s consolidated total assets at December 31, 2010 and June 30, 2010, and less than 1% of consolidated sales of natural gas and electricity for the six months ended December 31, 2010 and 2009.

 

Financial information for the Company’s business segments is summarized in the following table.  Only those assets allocated to the Company’s business segments are included in the table.  The Company does not allocate operating expenses, interest expense or income taxes to its business segments.

 

24



Table of Contents

 

Three Months Ended December 31,

 

Natural Gas

 

Electricity

 

Total

 

 

 

(in thousands)

 

2010:

 

 

 

 

 

 

 

Sales

 

$

138,470

 

$

45,346

 

$

183,816

 

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

 

(107,921

)

(35,084

)

(143,005

)

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

 

$

30,549

 

$

10,262

 

40,811

 

 

 

 

 

 

 

 

 

Add (less) items to reconcile total segment gross profit to income before income tax expense: 

 

 

 

 

 

 

 

Unrealized gains from risk management activities, net

 

17,153

 

Operating expenses

 

(25,858

)

Interest expense, net of interest income

 

(7,250

)

Income before income taxes

 

$

24,856

 

 

 

 

 

Assets and liabilities allocated to business segments at period end:

 

 

 

 

 

 

 

Accounts receivable, net

 

$

90,937

 

$

24,319

 

$

115,256

 

Natural gas inventories

 

16,918

 

 

16,918

 

Goodwill

 

3,810

 

 

3,810

 

Customer acquisition costs, net

 

16,704

 

17,004

 

33,708

 

Total assets allocated to business segments

 

$

128,369

 

$

41,323

 

$

169,692

 

 

 

 

 

 

 

 

 

2009:

 

 

 

 

 

 

 

Sales

 

$

134,069

 

$

18,700

 

$

152,769

 

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

 

(103,456

)

(13,727

)

(117,183

)

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

 

$

30,613

 

$

4,973

 

35,586

 

 

 

 

 

Add (less) items to reconcile total segment gross profit to income before income tax expense: 

 

 

 

 

 

 

 

Unrealized gains from risk management activities, net

 

16,713

 

Operating expenses

 

(20,052

)

Interest expense, net of interest income

 

(8,248

)

Income before income taxes

 

$

23,999

 

 

 

 

 

 

 

 

 

Assets and liabilities allocated to business segments at period end:

 

 

 

 

 

 

 

Accounts receivable

 

$

83,760

 

$

9,047

 

$

92,807

 

Natural gas inventories

 

28,353

 

 

28,353

 

Goodwill

 

3,810

 

 

3,810

 

Customer acquisition costs, net

 

18,615

 

6,101

 

24,716

 

Total assets allocated to business segments

 

$

134,538

 

$

15,148

 

$

149,686

 

 


(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.

 

25



Table of Contents

 

Six Months Ended December 31,

 

Natural Gas

 

Electricity

 

Total

 

 

 

(in thousands)

 

2010:

 

 

 

 

 

 

 

Sales

 

$

181,711

 

$

96,469

 

$

278,180

 

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

 

(149,936

)

(76,493

)

(226,429

)

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

 

$

31,775

 

$

19,976

 

51,751

 

 

 

 

 

 

 

 

 

Add (less) items to reconcile total segment gross profit to income before income tax expense:

 

 

 

 

 

 

 

Unrealized gains from risk management activities, net

 

14,274

 

Operating expenses

 

(50,643

)

Interest expense, net of interest income

 

(13,957

)

Income before income taxes

 

$

1,425

 

 

 

 

 

2009:

 

 

 

 

 

 

 

Sales

 

$

185,564

 

$

43,178

 

$

228,742

 

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

 

(147,242

)

(32,659

)

(179,901

)

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

 

$

38,322

 

$

10,519

 

48,841

 

 

 

 

 

Add (less) items to reconcile total segment gross profit to income before income tax expense: 

 

 

 

 

 

 

 

Unrealized gains from risk management activities, net

 

28,452

 

Operating expenses

 

(42,365

)

Interest expense, net of interest income

 

(21,165

)

Income before income taxes

 

$

13,763

 

 


(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.

 

Note 19.  Condensed Consolidating Financial Information

 

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

 

·      MXenergy Capital Holdings Corp.

·      MXenergy Capital Corp.

·      Online Choice Inc.

·      MXenergy Gas Capital Holdings Corp.

·      MXenergy Gas Capital Corp.

·      MXenergy Inc.

·      MXenergy Electric Capital Holdings Corp.

·      MXenergy Electric Capital Corp.

·      MXenergy Electric Inc.

·      MXenergy Services Inc.

·      Infometer.com Inc.

 

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

 

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

 

26



Table of Contents

 

MXENERGY HOLDINGS INC.

Consolidating Balance Sheet

December 31, 2010

(in thousands)

 

 

 

MXenergy

Holdings Inc.

 

Non-guarantor

Subsidiary

 

Guarantor

Subsidiaries

 

Eliminations

 

Consolidated

 

 

 

 

 

 

 

 

 

 

 

 

 

Assets

 

 

 

 

 

 

 

 

 

 

 

Current assets:

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

52

 

$

247

 

$

3,989

 

$

 

$

4,288

 

Restricted cash

 

 

 

1,683

 

 

1,683

 

Fixed Rate Notes Escrow Account

 

8,977

 

 

 

 

8,977

 

Accounts receivable, net

 

 

40

 

115,216

 

 

115,256

 

Natural gas inventories

 

 

 

16,918

 

 

16,918

 

Current portion of unrealized gains from risk management activities

 

 

 

1,830

 

 

1,830

 

Income taxes receivable

 

 

 

6,959

 

 

6,959

 

Deferred income taxes

 

 

 

994

 

 

994

 

Intercompany accounts receivable

 

123,317

 

331

 

 

(123,648

)

 

Other current assets

 

32

 

57

 

12,817

 

 

12,906

 

Total current assets

 

132,378

 

675

 

160,406

 

(123,648

)

169,811

 

Goodwill

 

 

 

3,810

 

 

3,810

 

Customer acquisition costs, net

 

 

 

33,708

 

 

33,708

 

Fixed assets, net

 

 

1

 

3,755

 

 

3,756

 

Deferred income taxes

 

 

 

7,644

 

 

7,644

 

Deferred debt issue costs

 

 

 

10,190

 

 

10,190

 

Intercompany notes receivable

 

73,687

 

 

 

(73,687

)

 

Investment in subsidiaries

 

(55,748

)

 

 

55,748

 

 

Other assets

 

 

53

 

476

 

 

529

 

Total assets

 

$

150,317

 

$

729

 

$

219,989

 

$

(141,587

)

$

229,448

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities and stockholders’ equity

 

 

 

 

 

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

 

 

 

 

 

Accounts payable and accrued liabilities

 

$

6

 

$

161

 

$

29,654

 

$

 

$

29,821

 

Accounts payable to RBS Sempra, net

 

 

 

31,027

 

 

31,027

 

Current portion of unrealized losses from risk management activities, net

 

 

 

4,257

 

 

4,257

 

Deferred revenue

 

 

 

10,276

 

 

10,276

 

Current portion of long-term debt

 

6,394

 

 

 

 

6,394

 

Intercompany accounts payable

 

 

1,926

 

121,722

 

(123,648

)

 

Total current liabilities

 

6,400

 

2,087

 

196,936

 

(123,648

)

81,775

 

Unrealized losses from risk management activities, net

 

 

 

 

 

 

Long-term debt

 

54,174

 

 

 

 

54,174

 

Other long-term liabilities

 

 

 

3,756

 

 

 

3,756

 

Intercompany notes payable

 

 

 

73,687

 

(73,687

)

 

Total liabilities

 

60,574

 

2,087

 

274,379

 

(197,335

)

139,705

 

 

 

 

 

 

 

 

 

 

 

 

 

Commitments and contingencies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Stockholders’ equity (deficit):

 

 

 

 

 

 

 

 

 

 

 

Common stock:

 

 

 

 

 

 

 

 

 

 

 

Class A Common Stock

 

339

 

 

 

 

339

 

Class B Common Stock

 

40

 

 

 

 

40

 

Class C Common Stock

 

170

 

 

 

 

170

 

Common Stock

 

 

1

 

 

(1

)

 

Total common stock

 

549

 

1

 

 

(1

)

549

 

Additional paid-in-capital

 

140,316

 

 

 

 

140,316

 

Class A treasury stock

 

(99

)

 

 

 

(99

)

Accumulated other comprehensive loss

 

(255

)

(255

)

 

255

 

(255

)

Accumulated deficit

 

(50,768

)

(1,104

)

(54,390

)

55,494

 

(50,768

)

Total stockholders’ equity

 

89,743

 

(1,358

)

(54,390

)

55,748

 

89,743

 

Total liabilities and stockholders’ equity

 

$

150,317

 

$

729

 

$

219,989

 

$

(141,587

)

$

229,448

 

 

27



Table of Contents

 

MXENERGY HOLDINGS INC.

Consolidating Balance Sheet

June 30, 2010

(in thousands)

 

 

 

MXenergy

Holdings Inc.

 

Non-guarantor
Subsidiary

 

Guarantor

Subsidiaries

 

Eliminations

 

Consolidated

 

 

 

 

 

 

 

 

 

 

 

 

 

Assets

 

 

 

 

 

 

 

 

 

 

 

Current assets:

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

22

 

$

384

 

$

5,814

 

$

 

$

6,220

 

Restricted cash

 

 

 

1,574

 

 

1,574

 

Fixed Rate Notes Escrow Account

 

8,977

 

 

 

 

8,977

 

Accounts receivable, net

 

 

44

 

48,881

 

 

48,925

 

Accounts receivable from RBS Sempra, net

 

 

 

43,054

 

 

43,054

 

Natural gas inventories

 

 

 

15,861

 

 

15,861

 

Income taxes receivable

 

 

 

6,063

 

 

6,063

 

Deferred income taxes

 

 

 

1,378

 

 

1,378

 

Intercompany accounts receivable

 

111,769

 

 

 

(111,769

)

 

Other current assets

 

29

 

11

 

16,232

 

 

16,272

 

Total current assets

 

120,797

 

439

 

138,857

 

(111,769

)

148,324

 

Goodwill

 

 

 

3,810

 

 

3,810

 

Customer acquisition costs, net

 

 

 

30,425

 

 

30,425

 

Fixed assets, net

 

 

1

 

2,738

 

 

2,739

 

Deferred income taxes

 

 

 

3,629

 

 

3,629

 

Deferred debt issue costs

 

 

 

12,552

 

 

12,552

 

Intercompany notes receivable

 

73,706

 

 

 

(73,706

)

 

Investment in subsidiaries

 

(48,826

)

 

 

48,826

 

 

Other assets

 

 

50

 

491

 

 

541

 

Total assets

 

$

145,677

 

$

490

 

$

192,502

 

$

(136,649

)

$

202,020

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities and stockholders’ equity

 

 

 

 

 

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

 

 

 

 

 

Accounts payable and accrued liabilities

 

$

4

 

$

125

 

$

30,173

 

$

 

$

30,302

 

Current portion of unrealized losses from risk management activities, net

 

 

 

16,731

 

 

16,731

 

Deferred revenue

 

 

 

7,457

 

 

7,457

 

Intercompany accounts payable

 

 

1,799

 

109,970

 

(111,769

)

 

Total current liabilities

 

4

 

1,924

 

164,331

 

(111,769

)

54,490

 

Unrealized losses from risk management activities, net

 

 

 

1,857

 

 

1,857

 

Long-term debt

 

58,722

 

 

 

 

58,722

 

Intercompany notes payable

 

 

 

73,706

 

(73,706

)

 

Total liabilities

 

58,726

 

1,924

 

239,894

 

(185,475

)

115,069

 

 

 

 

 

 

 

 

 

 

 

 

 

Commitments and contingencies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Stockholders’ equity (deficit):

 

 

 

 

 

 

 

 

 

 

 

Common stock:

 

 

 

 

 

 

 

 

 

 

 

Class A Common Stock

 

339

 

 

 

 

339

 

Class B Common Stock

 

40

 

 

 

 

40

 

Class C Common Stock

 

164

 

 

 

 

164

 

Common stock

 

 

1

 

 

(1

)

 

Total common stock

 

543

 

1

 

 

(1

)

543

 

Additional paid-in-capital

 

139,702

 

 

 

 

139,702

 

Class A treasury stock

 

(99

)

 

 

 

(99

)

Accumulated other comprehensive loss

 

(156

)

(156

)

 

156

 

(156

)

Accumulated deficit

 

(53,039

)

(1,279

)

(47,392

)

48,671

 

(53,039

)

Total stockholders’ equity

 

86,951

 

(1,434

)

(47,392

)

48,826

 

86,951

 

Total liabilities and stockholders’ equity

 

$

145,677

 

$

490

 

$

192,502

 

$

(136,649

)

$

202,020

 

 

28



Table of Contents

 

MXENERGY HOLDINGS INC.

Consolidating Statement of Operations

Three Months Ended December 31, 2010

(in thousands)

 

 

 

MXenergy
Holdings Inc.

 

Non-guarantor 
Subsidiary

 

Guarantor 
Subsidiaries

 

Eliminations

 

Consolidated

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales of natural gas and electricity

 

$

 

$

109

 

$

183,707

 

$

 

$

183,816

 

Cost of goods sold (excluding depreciation and amortization):

 

 

 

 

 

 

 

 

 

 

 

 Cost of natural gas and electricity sold

 

 

51

 

131,442

 

 

131,493

 

 Realized losses from risk management activities

 

 

 

11,512

 

 

11,512

 

 Unrealized losses from risk management activities

 

 

 

(17,153

)

 

(17,153

)

 

 

 

51

 

125,801

 

 

125,852

 

Gross profit

 

 

58

 

57,906

 

 

57,964

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating expenses:

 

 

 

 

 

 

 

 

 

 

 

 General and administrative expenses

 

510

 

23

 

14,416

 

 

14,949

 

 Management service fees

 

 

(79

)

79

 

 

 

 Advertising and marketing expenses

 

 

 

1,698

 

 

1,698

 

 Reserves and discounts

 

 

 

2,660

 

 

2,660

 

 Depreciation and amortization

 

 

 

6,551

 

 

6,551

 

 Equity in operations of consolidated subsidiaries

 

(26,212

)

 

 

26,212

 

 

Total operating expenses

 

(25,702

)

(56

)

25,404

 

26,212

 

25,858

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating (loss) profit

 

25,702

 

114

 

32,502

 

(26,212

)

32,106

 

Interest expense, net

 

 

6

 

7,244

 

 

7,250

 

(Loss) income before income tax benefit (expense)

 

25,702

 

108

 

25,258

 

(26,212

)

24,856

 

Income tax benefit

 

 

 

846

 

 

846

 

Net (loss) income

 

$

25,702

 

$

108

 

$

26,104

 

$

(26,212

)

$

25,702

 

 

MXENERGY HOLDINGS INC.

Consolidating Statement of Operations

Three Months Ended December 31, 2009     

(in thousands)     

 

 

 

MXenergy
 Holdings Inc.

 

Non-guarantor 
Subsidiary

 

Guarantor 
Subsidiaries

 

Eliminations

 

Consolidated

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales of natural gas and electricity

 

$

 

$

125

 

$

152,644

 

$

 

$

152,769

 

Cost of goods sold (excluding depreciation and amortization):

 

 

 

 

 

 

 

 

 

 

 

Cost of natural gas and electricity sold

 

 

72

 

97,783

 

 

97,855

 

Realized losses from risk management activities

 

 

 

19,328

 

 

19,328

 

Unrealized losses from risk management activities

 

 

 

(16,713

)

 

 

(16,713

)

 

 

 

72

 

100,398

 

 

100,470

 

Gross profit

 

 

53

 

52,246

 

 

52,299

 

Operating expenses:

 

 

 

 

 

 

 

 

 

 

 

General and administrative expenses

 

56

 

29

 

12,330

 

 

12,415

 

Management service fees

 

 

(93

)

93

 

 

 

Advertising and marketing expenses

 

 

 

390

 

 

390

 

Reserves and discounts

 

 

 

1,972

 

 

1,972

 

Depreciation and amortization

 

 

9

 

5,266

 

 

5,275

 

Equity in operations of consolidated subsidiaries

 

(18,281

)

 

 

18,281

 

 

Total operating expenses

 

(18,225

)

(55

)

20,051

 

18,281

 

20,052

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating (loss) profit

 

18,225

 

108

 

32,195

 

(18,281

)

32,247

 

Interest expense, net

 

 

 

8,248

 

 

8,248

 

(Loss) income before income tax benefit (expense)

 

18,225

 

108

 

23,947

 

(18,281

)

23,999

 

Income tax benefit

 

 

 

(5,774

)

 

(5,774

)

Net (loss) income

 

$

18,225

 

$

108

 

$

18,173

 

$

(18,281

)

$

18,225

 

 

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Table of Contents

 

MXENERGY HOLDINGS INC.

Consolidating Statement of Operations

Six Months Ended December 31, 2010

(in thousands)

 

 

 

MXenergy
 Holdings Inc.

 

Non-guarantor 
Subsidiary

 

Guarantor 
Subsidiaries

 

Eliminations

 

Consolidated

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales of natural gas and electricity

 

$

 

$

194

 

$

277,986

 

$

 

$

278,180

 

Cost of goods sold (excluding depreciation and amortization):

 

 

 

 

 

 

 

 

 

 

 

Cost of natural gas and electricity sold

 

 

85

 

211,268

 

 

211,353

 

Realized losses from risk management activities

 

 

 

15,076

 

 

15,076

 

Unrealized losses from risk management activities

 

 

 

(14,274

)

 

(14,274

)

 

 

 

85

 

212,070

 

 

212,155

 

Gross profit

 

 

109

 

65,916

 

 

66,025

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating expenses:

 

 

 

 

 

 

 

 

 

 

 

General and administrative expenses

 

1,781

 

217

 

28,628

 

 

30,626

 

Management service fees

 

 

(145

)

145

 

 

 

Advertising and marketing expenses

 

 

 

3,123

 

 

3,123

 

Reserves and discounts

 

 

 

4,714

 

 

4,714

 

Depreciation and amortization

 

 

 

12,180

 

 

12,180

 

Equity in operations of consolidated subsidiaries

 

(4,052

)

 

 

4,052

 

 

Total operating expenses

 

(2,271

)

72

 

48,790

 

4,052

 

50,643

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating (loss) profit

 

2,271

 

36

 

17,127

 

(4,052

)

15,382

 

Interest expense, net

 

 

6

 

13,951

 

 

13,957

 

(Loss) income before income tax benefit (expense)

 

2,271

 

30

 

3,176

 

(4,052

)

1,425

 

Income tax benefit

 

 

 

846

 

 

846

 

Net (loss) income

 

$

2,271

 

$

30

 

$

4,022

 

$

(4,052

)

$

2,271

 

 

MXENERGY HOLDINGS INC.

Consolidating Statement of Operations

Six Months Ended December 31, 2009

(in thousands)

 

 

 

MXenergy

Holdings Inc.

 

Non-guarantor
Subsidiary

 

Guarantor

Subsidiaries

 

Eliminations

 

Consolidated

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales of natural gas and electricity

 

$

 

$

276

 

$

228,466

 

$

 

$

228,742

 

Cost of goods sold (excluding depreciation and amortization):

 

 

 

 

 

 

 

 

 

 

 

 Cost of natural gas and electricity sold

 

 

132

 

146,534

 

 

146,666

 

 Realized losses from risk management activities

 

 

 

33,235

 

 

33,235

 

 Unrealized losses from risk management activities

 

 

 

(28,452

)

 

 

(28,452

)

 

 

 

132

 

151,317

 

 

151,449

 

Gross profit

 

 

144

 

77,149

 

 

77,293

 

Operating expenses:

 

 

 

 

 

 

 

 

 

 

 

 General and administrative expenses

 

56

 

42

 

26,814

 

 

26,912

 

 Management service fees

 

 

(193

)

193

 

 

 

 Advertising and marketing expenses

 

 

 

742

 

 

742

 

 Reserves and discounts

 

 

 

3,815

 

 

3,815

 

 Depreciation and amortization

 

 

17

 

10,879

 

 

10,896

 

 Equity in operations of consolidated subsidiaries

 

(8,045

)

 

 

8,045

 

 

Total operating expenses

 

(7,989

)

(134

)

42,443

 

8,045

 

42,365

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating (loss) profit

 

7,989

 

278

 

34,706

 

(8,045

)

34,928

 

Interest expense, net

 

 

1

 

21,164

 

 

21,165

 

(Loss) income before income tax benefit (expense)

 

7,989

 

277

 

13,542

 

(8,045

)

13,763

 

Income tax benefit

 

 

 

(5,774

)

 

(5,774

)

Net (loss) income

 

$

7,989

 

$

277

 

$

7,768

 

$

(8,045

)

$

7,989

 

 

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Table of Contents

 

MXENERGY HOLDINGS INC.

Consolidating Statement of Cash Flows

Six Months Ended December 31, 2010

(in thousands)

 

 

 

MXenergy

Holdings Inc.

 

Non-guarantor

Subsidiary

 

Guarantor

Subsidiaries

 

Eliminations

 

Consolidated

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating activities:

 

 

 

 

 

 

 

 

 

 

 

Net cash provided by operating activities

 

$

 

$

22

 

$

1,323

 

$

 

$

1,345

 

 

 

 

 

 

 

 

 

 

 

 

 

Investing activities:

 

 

 

 

 

 

 

 

 

 

 

Asset acquisitions and business combinations

 

 

 

(117

)

 

(117

)

Purchases of fixed assets

 

 

 

(1,928

)

 

(1,928

)

Net cash used in investing activities

 

 

 

(2,045

)

 

(2,045

)

 

 

 

 

 

 

 

 

 

 

 

 

Financing activities:

 

 

 

 

 

 

 

 

 

 

 

Debt issuance costs

 

 

 

(71

)

 

(71

)

Payroll taxes paid for issuance of common stock from RSUs

 

(1,161

)

 

 

 

(1,161

)

Net intercompany transfers

 

1,191

 

(159

)

(1,032

)

 

 

Net cash provided by (used in) financing activities

 

30

 

(159

)

(1,103

)

 

(1,232

)

 

 

 

 

 

 

 

 

 

 

 

 

Net increase in cash and cash equivalents

 

30

 

(137

)

(1,825

)

 

(1,932

)

Cash and cash equivalents at beginning of period

 

22

 

384

 

5,814

 

 

6,220

 

Cash and cash equivalents at end of period

 

$

52

 

$

247

 

$

3,989

 

$

 

$

4,288

 

 

MXENERGY HOLDINGS INC.

Consolidating Statement of Cash Flows

Six Months Ended December 31, 2009

(in thousands)

 

 

 

MXenergy

Holdings Inc.

 

Non-guarantor

Subsidiary

 

Guarantor

Subsidiaries

 

 

Eliminations

 

 

Consolidated

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating activities

 

 

 

 

 

 

 

 

 

 

 

Net cash provided by operating activities

 

$

(56

)

$

118

 

$

32,502

 

$

 

$

32,564

 

 

 

 

 

 

 

 

 

 

 

 

 

Investing activities

 

 

 

 

 

 

 

 

 

 

 

Asset acquisitions and business combinations

 

 

 

(207

)

 

(207

)

Purchases of fixed assets

 

 

 

(445

)

 

(445

)

Net cash used in investing activities

 

 

 

(652

)

 

(652

)

 

 

 

 

 

 

 

 

 

 

 

 

Financing activities

 

 

 

 

 

 

 

 

 

 

 

Repayment of Floating Rate Notes due 2011

 

(26,700

)

 

 

 

(26,700

)

Repayment of Denham Credit Facility

 

 

 

(12,000

)

 

(12,000

)

Repayment of Bridge Financing under the Revolving Credit Facility

 

 

 

(5,400

)

 

(5,400

)

Deferred debt issuance costs

 

 

 

(6,220

)

 

(6,220

)

Stock issuance costs

 

(329

)

 

 

 

(329

)

Purchase of treasury stock

 

(99

)

 

 

 

(99

)

Net intercompany transfers

 

27,184

 

(42

)

(27,142

)

 

 

Net cash used in financing activities

 

56

 

(42

)

(50,762

)

 

(50,748

)

 

 

 

 

 

 

 

 

 

 

 

 

Net increase (decrease) in cash and cash equivalents

 

 

76

 

(18,912

)

 

(18,836

)

Cash and cash equivalents at beginning of period

 

 

262

 

23,004

 

 

23,266

 

Cash and cash equivalents at end of period

 

$

 

$

338

 

$

4,092

 

$

 

$

4,430

 

 

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Table of Contents

 

Note 20.  Subsequent Events

 

The Company has evaluated subsequent events for the period from January 1, 2011 through the date on which these condensed consolidated financial statements were issued.  Based upon this evaluation, there were no material events or transactions during this period that required recognition or disclosure in these consolidated financial statements.

 

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

 

Definitions

 

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

 

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

 

References to “MWhr” refer to megawatt hours, each representing 1 million watt hours or a thousand kilowatt hours, which is the amount of electric energy produced or consumed in a period of time.

 

References to “RCEs” refer to residential customer equivalents, each of which represents a natural gas customer with a standard consumption of 100 MMBtus per year or an electricity customer with a standard consumption of 10 MWhrs per year.  These quantities, which are used for convenience, represent estimates of the annual amount of natural gas or electricity used by a typical household in some parts of the country.  Such estimates are primarily based on profiles of historical consumption by our customers.

 

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

 

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

 

The impact of weather on operating results for our natural gas and electricity business segments is measured using heating degree day and cooling degree day data.  “Degree days” are the number of Fahrenheit degrees by which the average daily temperature differs from 65 degrees Fahrenheit.  “Heating degree days,” or “HDDs,” refer to the total number of degree days during a reporting period for which the average daily temperature was less than 65 degrees Fahrenheit in each of our markets, weighted by the actual number of natural gas RCEs within each market.  “Cooling degree days,” or “CDDs,” refer to the total number of degree days during a reporting period for which the average daily temperature was greater than 65 degrees Fahrenheit in each of our markets, weighted by the actual number of natural gas RCEs within each market.

 

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EXECUTIVE OVERVIEW

 

Our income before income tax expense was $24.9 million for the three months ended December 31, 2010, which represented a 4% increase from our income before income tax expense of $24.0 million for the same period in the prior fiscal year.  Higher electricity gross profit for fiscal year 2011 was partially offset by lower natural gas gross profit and higher operating expenses.

 

For the six months ended December 31, 2010, our income before income tax expense of $1.4 million was 90% lower than income before income tax expense of $13.8 million for same period in the prior fiscal year.  Higher electricity gross profit for fiscal year 2011 was more than offset by lower natural gas gross profit and higher operating expenses.

 

We utilize a measure referred to as Adjusted EBITDA (as defined below) to evaluate our operating performance and liquidity position.  Significant activity affecting Adjusted EBITDA for the three months and six months ended December 31, 2010, as compared with the same periods in the prior fiscal year, is summarized in the following table.  Refer to “RESULTS OF OPERATIONS,” located elsewhere in Item 2 of this Quarterly Report, for additional commentary regarding the activity in the table.

 

 

 

Three Months
Ended
December 31,
2010

 

Six Months
Ended
December 31,
2010

 

 

 

(in thousands)

 

 

 

 

 

 

 

Adjusted EBITDA for period ended December 31, 2009

 

$

20,809

 

$

17,255

 

Increases (decreases) in Adjusted EBITDA due to:

 

 

 

 

 

Higher (Lower) gross profit (excluding unrealized gains from risk management activities, net):

 

 

 

 

 

Natural gas

 

(64

)

(6,547

)

Electricity

 

5,289

 

9,457

 

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

 

(4,020

)

(5,096

)

Adjusted EBITDA for period ended December 31, 2010

 

$

22,014

 

$

15,069

 

 

In April 2010, we began delivering natural gas to an LDC in Ohio as part of a Standard Service Offer program (the “SSO Program”).  Under the SSO Program, for the 12-month period from April 1, 2010 through March 31, 2011, we will receive a New York Mercantile Exchange (“NYMEX) referenced price plus a price adjustment for natural gas delivered by the LDC to its customers who are eligible to participate in the SSO Program.  We expect that our gross profit per MMBtu sold to the LDC will be lower under the SSO Program than the gross profit that we normally experience from our direct retail energy customers.  Based upon estimates received directly from the LDC, we expect that the customers assigned to us in connection with the SSO Program will consume approximately 9.9 million MMBtus of natural gas during the one-year term of the agreement, the majority of which will occur during the winter heating season.  We will no longer participate in the SSO Program effective April 1, 2011.

 

During the six months ended December 31, 2010, we recorded revenue related to approximately 3.5 million MMBtus of natural gas in connection with the SSO Program.  The SSO Program had a negative impact on our natural gas gross profit for the six month period due to a mismatch in the timing of fixed transportation and capacity costs in relation to revenues which will not be recorded until the commodity is delivered to customers.  We expect to continue to recover these costs during the remaining winter months when the commodity is delivered to our customers in the SSO Program.

 

In September 2009, we completed a debt and equity restructuring (the “Restructuring”), which included a number of transactions and amendments to corporate documents.  Material impacts of the Restructuring on our financial position, results of operations and cash flows were disclosed in the consolidated financial statements included in our Annual Report on Form 10-K for the fiscal year ended June 30, 2010 (the “2010 Form 10-K”).  We believe that the Restructuring improved our financial and liquidity position, while eliminating operating constraints previously imposed on us under our former supply and commodity hedging facilities.

 

After completion of the Restructuring in September 2009, we expanded our marketing activities to support planned growth in our customer base using our traditional marketing channels.  During fiscal year 2011, we have continued with our strategic growth initiatives to build brand awareness using our traditional marketing channels as well as using new approaches.  Higher electricity gross profit and higher marketing expenses during the first six months of fiscal year 2011 were a direct result of expansion of our business that resulted from these growth initiatives.  For the remainder of the current fiscal year,

 

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Table of Contents

 

we intend to continue with these growth initiatives, in addition to evaluating opportunities to enter new markets and to acquire new customer portfolios that are consistent with our overall growth strategy, our operating and information systems environments, our risk management policy, and our supply, hedging and financing capabilities.

 

During fiscal year 2010 and during the first six months of fiscal year 2011, we focused on growth in our electricity customer portfolio in order to improve the seasonal cash flow associated with the electricity business segment and reduce risks associated with commodity and geographic concentrations.  Most of this growth was in electricity markets where LDCs guarantee customer accounts receivable, which contributed to a higher portion of sales in guaranteed markets during the first six months of fiscal year 2011, as compared with the prior year.

 

We continuously monitor the cost of acquiring customers to ensure that customer portfolio growth is accomplished in the most cost efficient manner.  Capitalized customer acquisition costs increased $8.4 million, or 140%, and advertising and marketing expenses increased $2.4 million, or 321%, during the first six months of fiscal year 2011, as compared with the same period in the prior fiscal year.  When considering the number of customers acquired, our cost to acquire customers approximated $100 per RCE for the three months and six months ended December 31, 2010, which was consistent with the cost to acquire customers during the same periods in the prior fiscal year.

 

General and administrative operating expenses also increased significantly during the first six months of fiscal year 2011, as compared with the prior year.  We have increased our staff count in customer operations, information systems and other areas to support actual and planned customer growth, as well as to enhance the effectiveness of our internal controls environment.

 

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.  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, which is not determinable until delivery of natural gas and electricity under the customer contracts and the associated gain (loss) on risk management activity is realized.

 

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, restricted stock units, stock options and warrants), and assessing compensation incentives for our employees.  Management also provides financial performance measures to our senior executive team and significant stockholders with an emphasis on Adjusted EBITDA, on a consolidated basis, as the appropriate basis with which to measure the performance and liquidity of our business.  Furthermore, certain financial ratios and covenants in the agreements governing our Commodity Supply Facility are based on Adjusted EBITDA, as well as other items.  Accordingly, management and our significant stockholders 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.  These limitations include the following:

 

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

 

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Table of Contents

 

·      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 has not been adjusted to reflect the impact of earnings or charges resulting from matters we consider not to be indicative of our ongoing operations; and

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

 

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

 

The financial data included in the following table was derived from our consolidated financial statements, which are included elsewhere in this Quarterly 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.

 

 

 

Three Months Ended
December 31,

 

Six Months ended
December 31,

 

 

 

2010

 

2009

 

2010

 

2009

 

 

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

Sales of natural gas and electricity

 

$

183,816

 

$

152,769

 

$

278,180

 

$

228,742

 

Cost of goods sold

 

125,852

 

100,470

 

212,155

 

151,449

 

Gross profit

 

57,964

 

52,299

 

66,025

 

77,293

 

Operating expenses

 

25,858

 

20,052

 

50,643

 

42,365

 

Operating profit

 

32,106

 

32,247

 

15,382

 

34,928

 

Interest expense, net of interest income

 

7,250

 

8,248

 

13,957

 

21,165

 

Income before income tax benefit (expense)

 

24,856

 

23,999

 

1,425

 

13,763

 

Income tax benefit (expense)

 

846

 

(5,774

)

846

 

(5,774

)

Net income

 

25,702

 

18,225

 

2,271

 

7,989

 

 

 

 

 

 

 

 

 

 

 

Items to reconcile net income to EBITDA :

 

 

 

 

 

 

 

 

 

Add (less):

Interest expense, net of interest income

 

7,250

 

8,248

 

13,957

 

21,165

 

 

Depreciation and amortization

 

6,551

 

5,275

 

12,180

 

10,896

 

 

Income tax (benefit) expense

 

(846

)

5,774

 

(846

)

5,774

 

EBITDA

 

38,657

 

37,522

 

27,562

 

45,824

 

 

 

 

 

 

 

 

 

 

 

Items to reconcile EBITDA to Adjusted EBITDA:

 

 

 

 

 

 

 

 

 

Add (less):

Stock compensation expense

 

510

 

 

1,781

 

(117

)

 

Unrealized gains from risk management activities, net

 

(17,153

)

(16,713

)

(14,274

)

(28,452

)

Adjusted EBITDA

 

$

22,014

 

$

20,809

 

$

15,069

 

$

17,255

 

 

Selected Operating Data

 

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

 

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Table of Contents

 

 

 

Three Months Ended
December 31,

 

Six Months Ended
December 31,

 

 

 

2010

 

2009

 

2010

 

2009

 

 

 

 

 

 

 

 

 

 

 

Natural Gas:

 

 

 

 

 

 

 

 

 

Actual RCEs at end of period (1)

 

427,000

 

446,000

 

427,000

 

446,000

 

Average RCEs during the period (1)

 

431,000

 

458,000

 

436,000

 

467,000

 

MMBtus sold during the period

 

16,562,000

 

13,808,000

 

20,588,000

 

18,153,000

 

Sales per MMBtu sold during the period

 

$

8.36

 

$

9.71

 

$

8.83

 

$

10.22

 

Gross profit per MMBtu sold during the period (2)

 

$

1.84

 

$

2.22

 

$

1.54

 

$

2.11

 

Heating degree days

 

1,774

 

1,606

 

1,807

 

1,645

 

 

 

 

 

 

 

 

 

 

 

Electricity:

 

 

 

 

 

 

 

 

 

Actual RCEs at end of period

 

191,000

 

81,000

 

191,000

 

81,000

 

Average RCEs during the period

 

190,000

 

78,000

 

186,000

 

77,000

 

MWhrs sold during the period

 

458,000

 

166,000

 

954,000

 

381,000

 

Sales per MWhr sold during the period

 

$

99.01

 

$

112.65

 

$

101.12

 

$

113.33

 

Gross profit per MWhr sold during the period

 

$

22.41

 

$

29.96

 

$

20.94

 

$

27.61

 

Cooling degree days

 

68

 

68

 

940

 

858

 

 


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

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

 

Quarterly trends for natural gas and electricity RCEs and for renewal and in-contract attrition percentages are summarized in the following table.

 

 

 

 

Customer Activity for the Quarter Ended

 

 

 

December 31,
2010

 

September 30,
2010

 

June 30,
2010

 

March 31,
2010

 

December 31,
2009

 

 

 

 

 

 

 

 

 

 

 

 

 

RCEs at end of quarter:

 

 

 

 

 

 

 

 

 

 

 

Natural gas (1)

 

427,000

 

445,000

 

433,000

 

438,000

 

446,000

 

Electricity

 

191,000

 

189,000

 

173,000

 

130,000

 

81,000

 

Total

 

618,000

 

634,000

 

606,000

 

568,000

 

527,000

 

 

 

 

 

 

 

 

 

 

 

 

 

Average RCEs during the quarter:

 

 

 

 

 

 

 

 

 

 

 

Natural gas (1)

 

431,000

 

441,000

 

432,000

 

439,000

 

458,000

 

Electricity

 

190,000

 

182,000

 

159,000

 

106,000

 

78,000

 

Total

 

621,000

 

623,000

 

591,000

 

545,000

 

536,000

 

 

 

 

 

 

 

 

 

 

 

 

 

Customer renewals and attrition for the 12-month period ending on the quarter-end date:

 

 

 

 

 

 

 

 

 

 

 

Customer renewal percentage (2)

 

92

%

92

%

93

%

93

%

92

%

In-contract attrition percentage (3)

 

31

%

27

%

26

%

25

%

29

%

 


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

(2)   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 and ultimately continued their relationship with us.  The percentage is calculated for the twelve months preceding the period-end date.

(3)   In-contract customer attrition percentage is defined as: (1) the percentage of loss of fixed rate customers before their contract term officially expires; and (2) the percentage of loss of any variable rate customers, whose contracts generally do not have expiration dates.  The percentage is calculated for the twelve months preceding the period-end date. Attrition data is calculated based upon actual customer level data.  For analytical purposes, we assume that one RCE represents a natural gas customer with a standard consumption of 100 MMBtus per year, or an electricity customer with a standard consumption of 10 MWhr per year.  However, each customer does not actually consume 100 MMBtu of natural gas or 10 MWhr of electricity.  For example, one of our mid-market or large commercial customers may consume the equivalent of several hundred or even thousands of RCEs.  Therefore, any reduction or increase in RCEs in any of our markets does not necessarily correlate directly with net customer attrition.

 

Historically, we have experienced a seasonal trend of lower customer additions during the months of December through February due to lack of customer response to our marketing efforts during this period.  We experienced a continuation of this annual trend during the month of December 2010, which contributed to comparatively lower additions of customers during

 

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Table of Contents

 

the quarter ended December 31, 2010 compared with the previous quarter.

 

Average natural gas RCEs for the quarter ended December 31, 2010 declined 2% from the prior quarter and declined 6% from the same period in the prior fiscal year.  During the quarter ended December 31, 2010, we experienced decreases in our commercial and small business customer counts, while our residential customer counts remained relatively constant.  During the six months ended December 31, 2010, higher residential customer counts were more than offset by lower small business and commercial customer counts, including several large commercial accounts, each of which represents the loss of several hundred RCEs.

 

Average electricity RCEs for the quarter ended December 31, 2010 increased 4% from the prior quarter and increased 144% from the same period in the prior fiscal year.  During the final six months of fiscal year 2010 and the first six months of fiscal year 2011, we focused on growth in many of our traditional electricity markets in order to improve the seasonal cash flow associated with the electricity business segment and to reduce risks associated with commodity and geographic concentrations.  In addition, actual electricity RCEs as of December 31, 2010 include over 77,000 net customers added as a result of our expansion into new electricity markets in Pennsylvania and Maryland during the twelve months ended December 31, 2010.  In December 2010, we acquired customers in two new electricity markets that are not included in our RCE count.  These customers will be added to our customer counts once the flow of related customer data between us and the respective LDCs has been established and adequately tested.  As a result, approximately 5,000 electricity RCEs acquired in December 2010 were not added to our RCE counts until the quarter ended March 31, 2011.

 

Higher in-contract attrition for the twelve months ended December 31, 2010 was primarily driven by competitive pressure in electricity markets, particularly our markets in Pennsylvania and Connecticut.  Over the past twelve months, the number of competitors has increased significantly in these markets, which has resulted in a growing number of available rate plan options from which customers can choose.

 

Seasonality of Operations

 

Natural gas and electricity sales accounted for approximately 65% and 35%, respectively, of our total sales for the six months ended December 31, 2010, and 82% and 18%, respectively, of our total sales for the fiscal year ended June 30, 2010.  The mix of natural gas and electricity sales varies significantly during the reporting quarters within our fiscal year due to the seasonality of our business.  The majority of natural gas customer consumption occurs during the months of November through March.  By contrast, electricity customer consumption peaks during the months of June through September.  Because the natural gas business segment comprises such a large component of our overall business operations for our entire fiscal year, the second and third fiscal quarters represent the seasonal peak of operating results for our full fiscal year.

 

Cash collections from our natural gas customers peak in the spring of each calendar year, while cash collections from electricity customers peak in late summer and early fall.  We utilize a considerable amount of cash from operations to meet working capital requirements during the months of November through March of each fiscal year.  In addition, we utilize considerable cash to purchase natural gas inventories during the months of April through October.

 

Weather conditions have a significant impact on customer demand and market prices for natural gas and electricity.  Customer demand exposes us to a high degree of seasonality in sales, cost of sales, billing and collection of customer accounts receivable, inventory requirements and cash flows.  In addition, budget billing programs and payment terms of LDCs can cause timing differences between the billing and collection of accounts receivable and the recording of revenues.

 

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

 

New Accounting Pronouncements

 

New accounting pronouncements are summarized in Note 2 to the condensed consolidated financial statements included in Item 1 of this Quarterly Report.  Such disclosure is incorporated herein by reference.

 

Related Party Transactions

 

Transactions with related parties are summarized in Note 16 to the condensed consolidated financial statements included in Item 1 of this Quarterly Report.  Such disclosure is incorporated herein by reference.

 

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Table of Contents

 

BALANCE SHEET OVERVIEW

 

Guaranteed and Non-Guaranteed Customer Accounts Receivable

 

Accounts receivable, net is summarized in the following table.

 

 

 

Balances at

 

 

 

December 31,
2010

 

June 30,
2010

 

 

 

(in thousands)

 

Billed customer accounts receivable:

 

 

 

 

 

Guaranteed by LDCs

 

$

34,605

 

$

11,736

 

Non-guaranteed by LDCs

 

25,860

 

21,543

 

 

 

60,465

 

33,279

 

Unbilled customer accounts receivable (1):

 

 

 

 

 

Guaranteed by LDCs

 

32,805

 

10,206

 

Non-guaranteed by LDCs

 

23,143

 

7,211

 

 

 

55,948

 

17,417

 

Total customer accounts receivable

 

116,413

 

50,696

 

Less: Allowance for doubtful accounts

 

(4,860

)

(5,074

)

Customer accounts receivable, net

 

111,553

 

45,622

 

Cash imbalance settlements and other receivables, net (2)

 

3,703

 

3,303

 

Accounts receivable, net

 

$

115,256

 

$

48,925

 

 


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

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

 

We operate in 41 market areas located in 14 U.S. states and two Canadian provinces.  Our diversified geographic coverage mitigates the credit exposure that 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.

 

Certain LDCs guarantee billed and unbilled customer accounts receivable or amounts due for delivered gas and electricity, for which they charge an average discount fee of approximately 1%.  These LDC guarantees mitigate our direct credit risk since the Company is exposed only to the credit risk of the LDC, rather than that of its customers.  As of December 31, 2010 and June 30, 2010, all of our billed and unbilled customer accounts receivable in guaranteed markets were from 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.

 

Imbalance settlements represent differences between the natural gas or electricity delivered to LDCs or independent system operators (“ISOs”) for consumption by our customers and actual usage by our customers.  We expect that such imbalances will be settled with cash within twelve months 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 and ISOs.  These receivables are generally due from counterparties with investment grade credit ratings.

 

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 general economic conditions in the markets that we serve.  Based upon this review as of December 31, 2010, we believe that our allowance for doubtful accounts is adequate to cover potential credit losses related to customer accounts receivable.  Additional commentary regarding credit risk management, our allowance for doubtful accounts and our provision for doubtful accounts is provided in Item 3 of this Quarterly Report.

 

We have limited exposure to risk associated with high concentrations of sales volumes with individual customers.  As a result of our participation in the SSO Program, the LDC in Ohio became our largest single customer, accounting for approximately 17% of our natural gas sales volume for the six months ended December 31, 2010.  Our largest electricity customer accounted for less than 1% of our electricity sales volume.  The Company will no longer participate in the SSO Program effective April 1, 2011.

 

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Table of Contents

 

Natural Gas Inventories

 

Natural gas inventories are summarized in the following table.

 

 

 

Balances at

 

 

 

December 31,
2010

 

June 30,
2010

 

 

 

(in thousands)

 

 

 

 

 

 

 

Storage inventory for delivery to customers

 

$

11,097

 

$

9,956

 

Imbalance settlements in-kind (1)

 

5,821

 

5,905

 

Total

 

$

16,918

 

$

15,861

 

 


(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.   The Company expects these inventories to be transferred to the Company or its customers within the upcoming 12-month period.

 

The Company reports the volume of natural gas held in storage in million British thermal units (“MMBtus”), which is a standard unit of heating equivalent measure for natural gas.  The increase in storage inventory for delivery to customers from June 30, 2010 to December 31, 2010 was primarily due to normal seasonal accumulation of natural gas held in storage for the Company to serve its natural gas customers during the winter season.  The volume of natural gas held in storage increased 28% from 1.8 million MMBtus at June 30, 2010 to 2.3 million MMBtus at December 31, 2010.

 

Natural gas inventories are valued on a weighted-average cost basis, which includes related transportation and storage costs, and which does not exceed net realizable value.  The weighted-average cost per MMBtu of natural gas held in storage decreased 10% from June 30, 2010 to December 31, 2010.

 

Accounts Receivable from RBS Sempra, Net and Accounts Payable to RBS Sempra, Net

 

The ISDA Master Agreements include provisions that allow for net settlement of various amounts due from or due to RBS Sempra resulting from activity under the Commodity Supply Facility.  Amounts due from or due to RBS Sempra are summarized in the following table.

 

 

 

Balances at

 

Amount receivable from (payable to) RBS Sempra for:

 

December 31,
2010

 

June 30,
2010

 

 

 

(in thousands)

 

 

 

 

 

 

 

Cash received and held by RBS Sempra (1)

 

$

24,621

 

$

64,819

 

Commodity purchases from RBS Sempra

 

(54,070

)

(19,030

)

Transportation costs, derivative settlements, interest and fees charged by RBS Sempra

 

(1,578

)

(2,735

)

Accounts (payable to) receivable from RBS Sempra, net on the consolidated balance sheet

 

$

(31,027

)

$

43,054

 

 


(1)   In connection with the Commodity Supply Facility, certain banking relationships that previously belonged to us are now under RBS Sempra’s name and control.  RBS Sempra releases cash to us as required to meet our ongoing operating cash requirements.

 

RESULTS OF OPERATIONS

 

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

 

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

 

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Table of Contents

 

Reconciliations of gross profit by business segment to net income (loss) before income tax (expense) benefit are disclosed in Note 18 to the condensed consolidated financial statements included elsewhere in this Quarterly Report.

 

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

 

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

 

 

 

Three Months Ended
December 31,

 

2010 versus 2009
Increase (Decrease)

 

Business Segment

 

2010

 

2009

 

Amount

 

%

 

 

 

($ in thousands)

 

 

 

 

 

 

 

 

 

 

 

Natural gas

 

$

30,549

 

$

30,613

 

$

(64

)

 

Electricity

 

10,262

 

4,973

 

5,289

 

106

 

Total gross profit (before unrealized gains from risk management activities, net)

 

$

40,811

 

$

35,586

 

$

5,225

 

15

 

 

 

 

Six Months Ended
December 31,

 

2010 versus 2009
Increase (Decrease)

 

Business Segment

 

2010

 

2009

 

Amount

 

%

 

 

 

($ in thousands)

 

 

 

 

 

 

 

 

 

 

 

Natural gas

 

$

31,775

 

$

38,322

 

$

(6,547

)

(17

)

Electricity

 

19,976

 

10,519

 

9,457

 

90

 

Total gross profit (before unrealized gains from risk management activities, net)

 

$

51,751

 

$

48,841

 

$

2,910

 

6

 

 

Natural Gas Gross Profit

 

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

 

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

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

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

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

·      The impact of the SSO Program and any similar programs that can have a significant comparative impact on volumes sold to customers, sales, cost of goods sold, gross profit and gross profit per MMBtu sold.

 

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

 

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Table of Contents

 

 

 

Three Months Ended December 31,

 

 

 

2010

 

2009

 

 

 

Amount

 

Amount per
MMBtu Sold

 

Amount

 

Amount per
MMBtu Sold

 

 

 

($ in thousands)

 

 

 

 

 

 

 

 

 

 

 

Gross profit (before unrealized gains from risk management activities, net)

 

$

30,549

 

$

1.84

 

$

30,613

 

$

2.22

 

Add (less) the relative cost (benefit) during the period associated with commodity price volatility and economic hedging activity:

 

 

 

 

 

 

 

 

 

Weighted-average cost of gas methodology

 

1,054

 

0.06

 

(320

)

(0.02

)

Realized gains from risk management activities associated with natural gas inventory at end of period

 

(115

)

(0.01

)

(1,293

)

(0.09

)

 

 

31,488

 

1.89

 

29,000

 

2.11

 

Fee income

 

(3,358

)

(0.20

)

(4,114

)

(0.30

)

Amount attributable to natural gas delivered to customers

 

$

28,130

 

$

1.69

 

$

24,886

 

$

1.81

 

 

 

 

Six Months Ended December 31,

 

 

 

2010

 

2009

 

 

 

Amount

 

Amount per
MMBtu Sold

 

Amount

 

Amount per
MMBtu Sold

 

 

 

($ in thousands)

 

 

 

 

 

 

 

 

 

 

 

Gross profit (before unrealized gains from risk management activities, net)

 

$

31,775

 

$

1.54

 

$

38,322

 

$

2.11

 

Add (less) the relative cost (benefit) during the period associated with commodity price volatility and economic hedging activity:

 

 

 

 

 

 

 

 

 

Weighted-average cost of gas methodology

 

1,341

 

0.07

 

(1,282

)

(0.07

)

Realized losses (gains) from risk management activities, net, associated with natural gas inventory at end of period

 

1,465

 

0.07

 

(75

)

 

 

 

34,581

 

1.68

 

36,965

 

2.04

 

Fee income

 

(6,880

)

(0.33

)

(8,408

)

(0.46

)

Amount attributable to natural gas delivered to customers

 

$

27,701

 

$

1.35

 

$

28,557

 

$

1.58

 

 

Selected operating data for the natural gas business segment is summarized in the following table.

 

 

 

 

 

 

 

2010 versus 2009
Increase (Decrease)

 

 

 

2010

 

2009

 

Amount

 

%

 

 

 

 

 

 

 

 

 

 

 

Three months ended December 31:

 

 

 

 

 

 

 

 

 

Average RCEs during the period (1)

 

431,000

 

458,000

 

(27,000

)

(6

)

MMBtus sold during the period

 

16,562,000

 

13,808,000

 

2,638,000

 

19

 

Heating degree days

 

1,774

 

1,606

 

168

 

10

 

 

 

 

 

 

 

 

 

 

 

Six months ended December 31:

 

 

 

 

 

 

 

 

 

Average RCEs during the period (1)

 

436,000

 

467,000

 

(31,000

)

(7

)

MMBtus sold during the period

 

20,588,000

 

18,153,000

 

2,320,000

 

13

 

Heating degree days

 

1,807

 

1,645

 

162

 

10

 

 


(1)   Average RCEs exclude RCEs to be served in connection with the SSO Program pursuant to a one-year contract that expires March 31, 2011.  All historical revenue, cost of goods sold and volumes sold include activity from the SSO Program.

 

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

 

Our weighted average cost of gas (“WACOG”) methodology for 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 WACOG 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 reporting period is less than the WACOG at the beginning of the period, the WACOG will be

 

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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 reporting periods during which natural gas prices per MMBtu are greater during the period than the WACOG at the beginning of that period, the WACOG 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 WACOG are more pronounced in periods where we inject storage gas and have an increase in storage volume from the beginning to the end of the period.  Offsetting net increases or decreases in gross profit are generally realized in future periods as these inventories are sold.

 

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

 

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

 

Fee Income

 

Lower fee income was due primarily to a reduction in the number of customers served in markets where we are responsible for billing, and lower credit-related fees due to improved credit quality of the overall customer portfolio.

 

Gross Profit Attributable to Natural Gas Delivered to Customers

 

In April 2010, we began delivering natural gas to an LDC in Ohio as part of a Standard Service Offer program (the “SSO Program”).  Under the SSO Program, for the 12-month period from April 1, 2010 through March 31, 2011, we will receive a New York Mercantile Exchange (“NYMEX) referenced price plus a price adjustment for natural gas delivered by the LDC to its customers who are eligible to participate in the SSO Program.  We expect that our gross profit per MMBtu sold to the LDC will be lower under the SSO Program than the gross profit that we normally experience from our direct retail energy customers.  During the six months ended December 31, 2010, we recorded revenue associated with approximately 3.5 million MMBtus of natural gas consumed by customers in connection with the SSO Program.  The SSO Program had a negative impact on our natural gas gross profit, primarily due to a mismatch in the timing of fixed transportation and capacity costs in relation to revenues which will not be recorded until the commodity is delivered to customers.  We have begun to and expect to continue to recover these costs during the winter months when the commodity is delivered to our customers in the SSO Program.  Excluding the impact of the SSO Program, our gross profit attributable to natural gas delivered to customers increased during the three months and six months ended December 31, 2010 compared to the same periods in the prior fiscal year.

 

During the six months ended December 31, 2010, excluding the impact of the SSO Program, higher gross profit attributable to natural gas delivered to customers was due to the combined impact of a 6% increase in gross profit per MMBtu sold to customers and a 10% increase in HDDs, which were partially offset by a 7% decrease in the volume of natural gas sold to customers.

 

During the three months ended December 31, 2010, excluding the impact of the SSO Program, higher gross profit attributable to natural gas delivered to customers was due to the combined impact of a 13% increase in gross profit per MMBtu sold to customers and a 10% increase in HDDs, which were partially offset by a 3% decrease in the volume of natural gas sold to customers.

 

Lower volumes of natural gas sold to customers during the three months and six months ended December 31, 2010, excluding the impact of the SSO program, were primarily driven by the loss of certain commercial customers, each of which represented multiple RCEs of consumption.

 

In connection with the Commodity Supply Facility, during the quarter ended December 31, 2009, we assigned certain storage inventory and capacity rights to RBS Sempra that we previously owned.  As a result, our volume of natural gas inventory as of September 30, 2010 was significantly lower than that recorded at September 30, 2009.  However, we continued to incur fixed transportation costs associated with the volumes assigned to RBS Sempra.  Such costs, which were included in the cost

 

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of inventory for the quarter ended September 30, 2009, were expensed directly to cost of goods sold during the quarter ended September 30, 2010, resulting in comparatively lower natural gas gross profit per MMBtu sold for that period.

 

We have begun, and expect to continue, to recover these costs by recording revenue during the winter months as we deliver higher volumes of natural gas to our customers.  The fixed transportation cost portion of the total cost associated with the volumes sold during the winter months in fiscal year 2011 will be lower than that recorded for the prior fiscal year, which will effectively reduce cost per MMBtu sold, thereby increasing gross profit per MMBtu sold.  During the quarter ended December 31, 2010, and particularly during the month of December 2010, we began to recover these fixed transportation costs, which contributed to higher gross profit per MMBtu sold during the period.

 

Electricity Gross Profit

 

Significant activity affecting electricity gross profit (before unrealized gains from risk management activities, net) for the three months and six months ended December 31, 2010 and 2009 is summarized in the following tables.

 

 

 

Three Months Ended December 31,

 

 

 

2010

 

2009

 

 

 

Amount

 

Amount per
MWhr Sold

 

Amount

 

Amount per
MWhr Sold

 

 

 

($ in thousands)

 

 

 

 

 

 

 

 

 

 

 

Gross profit (before unrealized gains from risk management activities, net)

 

$

10,262

 

$

22.41

 

$

4,973

 

$

29.96

 

Fee income

 

(391

)

(0.85

)

(379

)

(2.29

)

Amount attributable to electricity delivered to customers

 

$

9,871

 

$

21.56

 

$

4,594

 

$

27.67

 

 

 

 

Six Months Ended December 31,

 

 

 

2010

 

2009

 

 

 

Amount

 

Amount per
MWhr Sold

 

Amount

 

Amount per
MWhr Sold

 

 

 

($ in thousands)

 

 

 

 

 

 

 

 

 

 

 

Gross profit (before unrealized gains from risk management activities, net)

 

$

19,976

 

$

20.94

 

$

10,519

 

$

27.61

 

Fee income

 

(898

)

(0.94

)

(817

)

(2.14

)

Amount attributable to electricity delivered to customers

 

$

19,078

 

$

20.00

 

$

9,702

 

$

25.47

 

 

Selected operating data for the electricity business segment is summarized in the following table.

 

 

 

 

 

 

 

2010 versus 2009
Increase (Decrease)

 

 

 

2010

 

2009

 

Amount

 

%

 

 

 

 

 

 

 

 

 

 

 

Three months ended December 31:

 

 

 

 

 

 

 

 

 

Average RCEs during the period

 

190,000

 

78,000

 

112,000

 

144

 

MWhrs sold during the period

 

458,000

 

166,000

 

292,000

 

176

 

Cooling degree days

 

68

 

68

 

 

 

 

 

 

 

 

 

 

 

 

 

Six months ended December 31:

 

 

 

 

 

 

 

 

 

Average RCEs during the period

 

186,000

 

77,000

 

109,000

 

142

 

MWhrs sold during the period

 

954,000

 

381,000

 

573,000

 

150

 

Cooling degree days

 

940

 

858

 

82

 

10

 

 

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Table of Contents

 

Higher electricity gross profit for the three months and six months ended December 31, 2010 were driven by significant increases in the volume of MWhrs sold, which primarily resulted from higher average electricity RCEs served.

 

Competitive pricing environments in many of our electricity markets resulted in lower gross profit per unit sold, which decreased 21% for both the three months and six months ended December 31, 2010, and which partially offset the positive impact of higher electricity volumes sold.

 

Gains and Losses from Risk Management Activities, Net

 

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

 

 

 

Three Months Ended
December 31,

 

2010 versus 2009
Increase (Decrease)

 

 

 

2010

 

2009

 

Amount

 

%

 

 

 

($ in thousands)

 

 

 

 

 

 

 

 

 

 

 

Realized losses from risk management activities, net

 

$

11,512

 

$

19,328

 

$

(7,816

)

(40

)

Unrealized gains from risk management activities, net

 

(17,153

)

(16,713

)

(440

)

(3

)

Total realized and unrealized (gains) losses from risk management activities, net

 

$

(5,641

)

$

2,615

 

$

(8,256

)

NM

 

 

 

 

Six Months Ended
December 31,

 

2010 versus 2009
Increase (Decrease)

 

 

 

2010

 

2009

 

Amount

 

%

 

 

 

($ in thousands)

 

 

 

 

 

 

 

 

 

 

 

Realized losses from risk management activities, net

 

$

15,076

 

$

33,235

 

$

(18,159

)

(55

)

Unrealized gains from risk management activities, net

 

(14,274

)

(28,452

)

14,178

 

50

 

Total realized and unrealized (gains) losses from risk management activities, net

 

$

802

 

$

4,783

 

$

(3,981

)

(83

)

 


NM — Not meaningful

 

Unrealized gains and losses from risk management activities recorded on the consolidated balance sheets primarily reflect the current market values, which represent the relationship between average forward commodity prices and the weighted average price of the related economic hedge, 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 values 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.

 

Operating Expenses

 

Operating expenses are summarized in the following tables.

 

 

 

Three Months Ended
December 31,

 

2010 versus 2009
Increase (Decrease)

 

 

 

2010

 

2009

 

Amount

 

%

 

 

 

($ in thousands)

 

 

 

 

 

 

 

 

 

 

 

General and administrative expenses

 

$

14,949

 

$

12,415

 

$

2,534

 

20

 

Advertising and marketing expenses

 

1,698

 

390

 

1,308

 

335

 

Reserves and discounts

 

2,660

 

1,972

 

688

 

35

 

Depreciation and amortization

 

6,551

 

5,275

 

1,276

 

24

 

Total operating expenses

 

$

25,858

 

$

20,052

 

$

5,806

 

29

 

 

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Table of Contents

 

 

 

Six Months Ended
December 31,

 

2010 versus 2009
Increase (Decrease)

 

 

 

2010

 

2009

 

Amount

 

%

 

 

 

($ in thousands)

 

 

 

 

 

 

 

 

 

 

 

General and administrative expenses

 

$

30,626

 

$

26,912

 

$

3,714

 

14

 

Advertising and marketing expenses

 

3,123

 

742

 

2,381

 

321

 

Reserves and discounts

 

4,714

 

3,815

 

899

 

24

 

Depreciation and amortization

 

12,180

 

10,896

 

1,284

 

12

 

Total operating expenses

 

$

50,643

 

$

42,365

 

$

8,278

 

20

 

 

Higher operating expenses during fiscal year 2011 are generally due to expanded operating activities in connection with actual growth in the electricity customer portfolio, planned growth initiatives for our natural gas and electricity businesses and enhancements to improve the effectiveness of our internal controls environment.  Higher stock compensation and employee benefits expenses also contributed significantly to overall increases in operating expenses.  Additional commentary regarding specific operating expense categories follows.

 

General and Administrative Expenses

 

General and administrative expenses are summarized in the following tables.

 

 

 

Three Months Ended
December 31,

 

2010 versus 2009
Increase (Decrease)

 

 

 

2010

 

2009

 

Amount

 

%

 

 

 

($ in thousands)

 

 

 

 

 

 

 

 

 

 

 

Salaries and employee benefits

 

$

9,167

 

$

7,653

 

$

1,514

 

20

 

Professional fees

 

1,467

 

1,068

 

399

 

37

 

Other general and administrative expenses

 

4,315

 

3,694

 

621

 

17

 

Total general and administrative expenses

 

$

14,949

 

$

12,415

 

$

2,534

 

20

 

 

 

 

Six Months Ended
December 31,

 

2010 versus 2009
Increase (Decrease)

 

 

 

2010

 

2009

 

Amount

 

%

 

 

 

($ in thousands)

 

 

 

 

 

 

 

 

 

 

 

Salaries and employee benefits

 

$

19,557

 

$

16,222

 

$

3,335

 

21

 

Professional fees

 

2,681

 

3,232

 

(551

)

(17

)

Other general and administrative expenses

 

8,388

 

7,458

 

930

 

12

 

Total general and administrative expenses

 

$

30,626

 

$

26,912

 

$

3,714

 

14

 

 

In connection with the Restructuring, we recorded approximately $2.2 million of non-recurring general and administrative expenses during the six months ended December 31, 2009, including $0.8 million of transaction-related bonuses, $0.2 million of employee severance costs and $1.2 million of professional fees incurred in connection with various potential liquidity events considered prior to completion of the Restructuring.

 

Excluding the non-recurring bonuses and severance costs noted above, salaries and employee benefits expenses were approximately $2.5 million higher during the second quarter of fiscal year 2011 and $4.3 million during the first six months of fiscal year 2011, as compared with the same periods in the prior fiscal year, primarily due to the following factors:

 

·      Stock-based compensation expense associated with restricted stock units granted in January 2010 was $0.5 million and $1.8 million during the second quarter and the first six months of fiscal year 2011.  Stock-based compensation expense was minimal during the first six months of fiscal year 2010 due to termination of our then existing incentive compensation plans in connection with the Restructuring;

·      The average number of employees was higher for the first six months of fiscal year 2011, particularly for the quarter ended December 31, 2010, as compared with the same period in the prior fiscal year, as a result of expanded operations to support actual and planned growth in our customer base and enhancements to improve the effectiveness of our internal controls environment; and

 

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·      The employer portions of health insurance and various other employee welfare benefits were generally higher for the first six months of fiscal year 2011, primarily as a result of significant increases in the total premiums associated with these benefits.

 

Excluding the non-recurring Restructuring-related professional fees incurred during the quarter ended September 30, 2009, professional fees increased $0.4 million during the second quarter of fiscal year 2011 and increased $0.7 million during the first six months of fiscal year 2011, as compared with the same periods in the prior fiscal year.  During the second half of fiscal year 2010 and the first half of fiscal year 2011, we began various initiatives to improve our current operating systems and process flows and to expand our operating infrastructure in anticipation of planned business growth.  For certain of these initiatives, we have utilized contracted professional services in addition to or in lieu of our employees.

 

Higher other general and administrative expenses during the quarter and six months ended December 31, 2010 were primarily due to expanded customer care, billing and information technology activities to support actual and planned growth in our customer base, and to support information systems upgrades and enhancements.

 

Advertising and Marketing Expenses

 

As part of an overall corporate strategy to manage our liquidity position, and in response to constraints that our former supply and hedging facilities placed on our marketing activities, we curtailed our sales and marketing expenditures for several months prior to the Restructuring.  This resulted in significantly lower advertising and marketing expenses during the quarter and six months ended December 31, 2009, as compared with our historical levels.

 

Subsequent to the Restructuring, we implemented various elements of a growth and marketing plan, which included strategic marketing initiatives in our current markets as well as incremental marketing expenses related to new markets, particularly new electricity markets in Pennsylvania and Maryland.  As a result, during the quarter and six months ended December 31, 2010, we incurred marketing expenditures that reflected a return to historical levels prior to the Restructuring.

 

Reserves and Discounts

 

Reserves and discounts in the consolidated statements of operations include the provision for doubtful accounts related to customer accounts receivable within markets where such receivables are not guaranteed by LDCs as well as discounts related to customer accounts receivable that are guaranteed by LDCs. Reserves and discounts are summarized in the following tables.

 

 

 

Three Months Ended
December 31,

 

2010 versus 2009
Increase (Decrease)

 

 

 

2010

 

2009

 

Amount

 

%

 

 

 

($ in thousands)

 

 

 

 

 

 

 

 

 

 

 

Provision for doubtful accounts

 

$

1,808

 

$

1,503

 

$

305

 

20

 

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

 

852

 

469

 

383

 

82

 

Total reserves and discounts

 

$

2,660

 

$

1,972

 

$

688

 

35

 

 

 

 

Six Months Ended
December 31,

 

2010 versus 2009
Increase (Decrease)

 

 

 

2010

 

2009

 

Amount

 

%

 

 

 

($ in thousands)

 

 

 

 

 

 

 

 

 

 

 

Provision for doubtful accounts

 

$

3,200

 

$

3,096

 

$

104

 

3

 

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

 

1,514

 

719

 

795

 

111

 

Total reserves and discounts

 

$

4,714

 

$

3,815

 

$

899

 

24

 

 


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

 

During the quarter ended December 31, 2010, we recorded a $0.6 million provision related to delays in our internal budget billing true-up process.  During the six months ended December 31, 2010, as part of the remediation plan to address and

 

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resolve the material weakness identified at June 30, 2010, we continued to implement certain controls and procedures to address delays in the budget billing true-up process.  Excluding this special provision, the provision for doubtful accounts decreased during the quarter and six months ended December 31, 2010, as compared with the same periods in the prior fiscal year, primarily due to the following factors:

 

·      Sales of natural gas and electricity in markets where customer accounts receivable are not guaranteed by LDCs decreased 15% during the first six months of fiscal year 2011;

·      Credit environments generally stabilized in many of our markets during the final nine months of fiscal year 2010 and the first half of fiscal year 2011.  By comparison, during fiscal year 2009 and the first quarter of fiscal year 2010, we experienced deterioration in the aging of our customer accounts receivable in certain of our larger markets in Georgia, Texas and the northeastern U.S., which resulted in charge-offs of customer accounts receivable and provisions for doubtful accounts that were higher than our historical levels; and

·      Purchase acquisitions usually result in incremental reserves associated with the customer portfolios purchased.  We did not complete any purchase acquisitions during fiscal year 2010 or the first quarter of fiscal year 2011.  By comparison, our acquisition of Catalyst Natural Gas, LLC during fiscal year 2009 contributed to higher allowance and provision for doubtful accounts in our Georgia natural gas market during the quarter ended September 30, 2009.

 

We continuously monitor economic conditions and collections experience in our markets in order to assess appropriate levels of our allowance for doubtful accounts.  Refer to Item 3 of this Quarterly Report for additional commentary regarding our management of credit risk.

 

Certain LDCs guarantee billed and unbilled customer accounts receivable or amounts due for delivered gas and electricity, for which they charge an average discount fee of approximately 1%.  Higher contractual discounts for LDC guarantees of customer accounts receivable during the quarter ended December 31, 2010 were due to significantly higher sales of natural gas and electricity within our LDC-guaranteed markets.  The weighted-average contractual discount rates for the current quarter were comparable to the rates for the same period in the prior fiscal year.

 

Depreciation and Amortization

 

Depreciation and amortization are summarized in the following tables.

 

 

 

Three Months Ended
December 31,

 

2010 versus 2009
Increase (Decrease)

 

 

 

2010

 

2009

 

Amount

 

%

 

 

 

($ in thousands)

 

 

 

 

 

 

 

 

 

 

 

Depreciation of fixed assets

 

$

457

 

$

495

 

$

(38

)

(8

)

Amortization of customer acquisition costs

 

6,094

 

4,780

 

1,314

 

27

 

Total depreciation and amortization

 

$

6,551

 

$

5,275

 

$

1,276

 

24

 

 

 

 

Six Months Ended
December 31,

 

2010 versus 2009
Increase (Decrease)

 

 

 

2010

 

2009

 

Amount

 

%

 

 

 

($ in thousands)

 

 

 

 

 

 

 

 

 

 

 

Depreciation of fixed assets

 

$

911

 

$

1,443

 

$

(532

)

(37

)

Amortization of customer acquisition costs

 

11,269

 

9,452

 

1,817

 

19

 

Other amortization expense

 

 

1

 

(1

)

NM

 

Total depreciation and amortization

 

$

12,180

 

$

10,896

 

$

1,284

 

12

 

 


NM — Not meaningful.

 

Higher amortization of customer acquisition costs during the quarter and six months ended December 31, 2010 resulted from higher additions to capitalized customer acquisition costs during fiscal year 2010 and the first six months of fiscal year 2011, as compared with the comparable prior year periods.  Such higher amortization expense was partially offset by lower depreciation and amortization expense associated with software, fixed assets and customers acquired in connection with a 2006 purchase acquisition, which were fully depreciated or amortized as of August 2009.

 

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Interest Expense, net

 

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

 

 

 

Three Months Ended
December 31,

 

2010 versus 2009
Increase (Decrease)

 

 

 

2010

 

2009

 

Amount

 

%

 

 

 

($ in thousands)

 

Interest related to debt instruments:

 

 

 

 

 

 

 

 

 

Fixed Rate Notes due 2014 (1)

 

$

2,274

 

2,294

 

$

(20

)

(1

)

Floating Rate Notes due 2011 (1)

 

131

 

138

 

(7

)

(5

)

 

 

 

 

 

 

 

 

 

 

Interest and fees related to commodity supply and hedging facilities (2):

 

 

 

 

 

 

 

 

 

Commodity Supply Facility

 

2,636

 

3,093

 

(457

)

(15

)

Former supply and hedging facilities

 

 

111

 

(111

)

(100

)

 

 

 

 

 

 

 

 

 

 

Change in value of interest rate swaps (3)

 

11

 

419

 

(408

)

(97

)

Amortization of deferred debt issuance costs and discount on issuance of long-term debt

 

2,149

 

2,109

 

40

 

2

 

Other interest expense

 

60

 

92

 

(32

)

(35

)

 

 

 

 

 

 

 

 

 

 

Total interest expense

 

7,261

 

8,256

 

(995

)

(12

)

Less: Interest income

 

(11

)

(8

)

(3

)

(38

)

Interest expense, net

 

$

7,250

 

$

8,248

 

$

(998

)

(12

)

 

 

 

Six Months Ended
December 31,

 

2010 versus 2009
Increase (Decrease)

 

 

 

2010

 

2009

 

Amount

 

%

 

 

 

($ in thousands)

 

Interest related to debt instruments:

 

 

 

 

 

 

 

 

 

Fixed Rate Notes due 2014 (1)

 

$

4,503

 

2,493

 

$

2,010

 

81

 

Floating Rate Notes due 2011 (1)

 

262

 

3,421

 

(3,159

)

(92

)

Denham Credit Facility (4)

 

 

246

 

(246

)

(100

)

 

 

 

 

 

 

 

 

 

 

Interest and fees related to commodity supply and hedging facilities (3):

 

 

 

 

 

 

 

 

 

Commodity Supply Facility

 

4,618

 

3,156

 

1,462

 

46

 

Former supply and hedging facilities

 

 

2,962

 

(2,962

)

(100

)

 

 

 

 

 

 

 

 

 

 

Change in value of interest rate swaps (4)

 

271

 

1,391

 

(1,120

)

(81

)

Amortization of deferred debt issuance costs and discount on issuance of long-term debt

 

4,280

 

7,399

 

(3,119

)

(42

)

Other interest expense

 

70

 

154

 

(84

)

(54

)

 

 

 

 

 

 

 

 

 

 

Total interest expense

 

14,004

 

21,222

 

(7,218

)

(34

)

Less: Interest income

 

(47

)

(57

)

10

 

18

 

Interest expense, net

 

$

13,957

 

$

21,165

 

$

(7,208

)

(34

)

 


(1)   On September 22, 2009, we exchanged $158.8 million aggregate principal amount of outstanding Floating Rate Notes due 2011 (the “Floating Rate Notes due 2011”) for $26.7 million of cash, $67.8 million aggregate principal amount of 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.

(2)   Effective September 22, 2009, in connection with the Restructuring, our former supply and hedging facilities were replaced by the Commodity Supply Facility with RBS Sempra.

(3)   We utilize interest rate swap agreements to manage exposure to interest rate fluctuations associated with the Floating Rate Senior Notes due 2011 and letters of credit issued under the Commodity Supply Facility.  Mark-to-market adjustments and interest expense associated with these swap arrangements are recorded as adjustments to interest expense, net.

(4)   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 were repaid and the Denham Credit Facility was terminated.

 

Interest expense, net includes approximately $2.2 million and $2.5 million of non-cash interest expense for the quarter ended December 31, 2010 and 2009, respectively, and $4.6 million and $8.8 million for the six months ended December 31, 2010 and 2009, respectively, which is associated with changes in the value of interest rate swaps, amortization of deferred debt issuance costs and amortization of discount on issuance of long-term debt.  The remaining interest expense for both periods

 

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primarily includes interest and fees paid or to be paid in connection with our long-term debt and our supply and hedging facilities.

 

Interest Related to Debt Instruments

 

Lower total interest expense associated with debt instruments for fiscal year 2011 is primarily due to decreased total debt balances resulting from the Restructuring.  The total aggregate principal balance outstanding under debt instruments decreased from approximately $177.2 million prior to the Restructuring to $74.2 million after the Restructuring.

 

The $67.8 million aggregate principal amount of Fixed Rate Notes due 2014 issued in connection with the Restructuring bears interest at 13.25%, which is higher than the average interest rates on outstanding debt instruments prior to the Restructuring.  The higher interest rate on the Fixed Rate Notes due 2014 partially offset the impact of lower average debt balances for fiscal year 2011.

 

Lower interest expense associated with the Floating Rate Notes due 2011 for the first six months of fiscal year 2011 was due to a combination of lower debt balances and lower interest rates.  As a result of the Restructuring, the average aggregate outstanding principal balance of Floating Rate Notes due 2011 decreased to approximately $6.4 million for the first six months of fiscal year 2011 from $78.0 million for the same period in the prior fiscal year.  The weighted-average interest rate was 8.13% and 8.55% for the six months ended December 31, 2010 and 2009, respectively.

 

Interest and Fees Related to Commodity Supply and Hedging Facilities

 

During the six months ended December 31, 2009, we incurred significant fees related to extension and winding down of our supply and hedging facilities that existed prior to the Restructuring.  Excluding these incremental fees, the fees associated with our supply and hedging activities are generally lower under the Commodity Supply Facility than those incurred under our former supply and hedging facilities.

 

Amortization of Deferred Debt Issuance Costs and Discount on Issuance of Long-Term Debt

 

Amortization of deferred debt issuance costs and original issue discount for the quarter ended December 31, 2009 included the following activity, which did not re-occur during the quarter ended December 31, 2010:

 

·      In connection with the Restructuring, approximately $158.8 million aggregate principal amount of Floating Rate Notes due 2011 was exchanged for cash, Fixed Rate Notes due 2014 and Class A Common Stock.   As a result, we recorded incremental interest expense of $3.1 million during the six months ended December 31, 2009, which represents accelerated amortization equivalent to a pro rata portion of the original issue discount and deferred debt issuance costs associated with the Floating Rate Notes due 2011 that were exchanged in connection with the Restructuring.

 

·      During fiscal year 2009 and the first three months of fiscal year 2010, we negotiated several amendments to our former supply and hedging facilities.  Approximately $9.1 million of total fees associated with these amendments were deferred during fiscal year 2009 and the first three months of fiscal year 2010, which were amortized through the September 21, 2009 maturity date of our former supply and hedging facilities.  Incremental interest expense associated with amortization of these costs was approximately $1.6 million for the six months ended December 31, 2009.

 

In connection with the Restructuring, we deferred approximately $16.0 million of costs related to the Commodity Supply Facility and the Fixed Rate Notes due 2014, including cash expenditures of approximately $7.0 million and the aggregate $9.0 million fair value of Class B Common Stock issued to RBS Sempra in a non-cash transaction as a condition of its entry into the ISDA Master Agreements.  We also recorded $17.8 million of original issue discount related to the Fixed Rate Notes dated 2014.  Amortization of deferred costs and original issue discount related to these facilities resulted in approximately $2.1 million of interest expense during the three months ended December 31, 2010 and 2009 and $4.2 million and $2.3 million of interest expense during the six months ended December 31, 2010 and 2009, respectively.

 

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Income Taxes

 

Our effective income tax rate was a benefit of 3.4% and expense of 24.1% for the three months ended December 31, 2010 and 2009, respectively.  Our effective income tax rate was a benefit of 59.4% and expense of 42.0% for the six months ended December 31, 2010 and 2009, respectively.

 

The effective income tax rate for the three months and six months ended December 31, 2010 included adjustments necessary to conform our tax provision to our tax return to be filed for the fiscal year ended June 30, 2010.  These adjustments resulted in a net tax benefit of $1.4 million and a significant reduction in the effective income tax rate for the three months and six months ended December 31, 2010.

 

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.  Such valuation allowance is deducted from deferred income tax assets on the consolidated balance sheets.  As of December 31, 2010 and June 30, 2010, 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, our valuation allowances of $23.3 million and $28.1 million at December 31, 2010 and June 30, 2010, respectively, related to non-recovery of deferred tax assets.  The change during the period related to the provision to return adjustments for prior years.

 

During the three months ended December 31, 2010, we recorded an unrecognized tax benefit of approximately $3.8 million, which is included in other long-term liabilities on the consolidated balance sheet at December 31, 2010.  This liability relates to the timing of expense recognition and does not impact the effective 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 available credit under our Commodity Supply Facility.   Our primary liquidity requirements arise primarily from our seasonal working capital needs, including purchases of natural gas inventories, collateral requirements related to supplier, LDC, transportation and storage arrangements, acquisition of customers and debt service obligations.  Because we sell natural gas and electricity, we are subject to material variations in short-term obligations under our Commodity Supply Facility on a seasonal basis, due to the timing and price of commodity purchases to meet customer demands.

 

As a result of the Restructuring completed in September 2009, we significantly decreased our outstanding debt obligations and debt service requirements for the final nine months of fiscal year 2010, the first quarter of fiscal year 2011 and for future years.  In addition, our supply and hedging facilities that existed prior to the Restructuring were replaced by the Commodity Supply Facility, which provides us with a stable source of liquidity through August 2012 with an investment grade counterparty.  Overall, the transactions consummated in the Restructuring improved our liquidity position, improved our financial and operational flexibility and allowed us to compete more effectively within the markets that we serve.

 

Under the Commodity Supply Facility, we have $58.5 million of liquidity available to us as of December 31, 2010, of which $45.0 million represents the maximum credit available for cash advances and $13.5 million represents excess liquidity that can be used for additional letters of credit, commodity purchases and other operating purposes.  In conjunction with cash expected to be generated from operations, we believe that the Commodity Supply Facility provides an adequate source of liquidity to meet our operating needs and debt service obligations for the foreseeable future, including the expected repayment of the Floating Rate Notes due 2011 in August 2011.

 

Cash Flow

 

Our cash flows are summarized in the following table.

 

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Six Months Ended
December 31,

 

2010 versus 2009
Increase (Decrease)

 

 

 

2010

 

2009

 

Amount

 

%

 

 

 

($ in thousands)

 

Net cash provided by operating activities

 

$

1,345

 

$

32,564

 

$

(31,219

)

(96

)

Net cash used in investing activities

 

(2,045

)

(652

)

(1,393

)

(214

)

Net cash used in financing activities

 

(1,232

)

(50,748

)

49,516

 

98

 

Net decrease in cash and cash equivalents

 

$

(1,932

)

$

(18,836

)

$

16,904

 

90

 

 

For the six months ended December 31, 2009, cash provided from operations included the release of $75.0 million of restricted cash upon maturity of our former supply and hedging facilities in September 2009, which was offset by a $9.0 million transfer of cash and cash equivalents to an escrow account (the “Fixed Rate Notes Escrow Account”).  Excluding these Restructuring-related transactions, cash provided by (used in) operating activities increased from $33.4 million used in operations during the six months ended December 31, 2009 to $1.3 million provided by operations during the six months ended December 31, 2010.  This increase in cash provided by operating activities was primarily due to the net result of cash receipts, commodity purchases and other activity associated with the Commodity Supply Facility, which are reported by the Company as net accounts receivable from or accounts payable to RBS Sempra.

 

Net cash used in investing activities primarily includes fixed asset additions for the six months ended December 31, 2010 and 2009.

 

Net cash used in financing activities during the six months ended December 31, 2009 represents the net impact of various Restructuring-related transactions, primarily repayment of debt balances and incurrence of debt and stock issuance costs.

 

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.  RBS Sempra will have the right to extend such maturity date by one year at its sole discretion, provided that RBS Sempra gives such notice no earlier than April 30, 2011 and no later than 180 days prior to the then current termination date.

 

RBS Sempra has indicated its intent to complete an orderly sale of its assets including, but not limited to, the entity which provides our Commodity Supply Facility.  Although we have received assurances from RBS Sempra that it will continue to fulfill its obligations under the Commodity Supply Facility, we are actively exploring alternatives for potential new supply, credit and hedging counterparties.

 

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 our required matched trading book.  In addition, the Commodity Supply Facility provides that we release natural gas transportation and storage capacity to RBS Sempra and for RBS Sempra to perform certain natural gas and electricity logistics. The Commodity Supply Facility also will provide for RBS Sempra to act on our behalf to satisfy the requirements of regional transmission operators for capacity rights and ancillary services.

 

Under the supply terms of the Commodity Supply Facility, we have the ability to: (1) seek commodity price quotes from third parties for certain physically or financially settled transactions with respect to gas and electricity; and (2) request that RBS Sempra enter into such transactions with such third parties at such prices and to concurrently enter into back-to-back off-setting transactions with us with respect to such third party transactions.  RBS Sempra is not obligated to enter into a transaction with any third party unless RBS Sempra is satisfied that the use of the third party is appropriate for the  transaction and the volume of those transactions does not exceed annual limits.  In addition to the actual purchase price paid by RBS Sempra and certain related costs and expenses, RBS Sempra will charge us a fee 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.

 

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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 us will be limited to $260.0 million, without adjustment for mark-to-market movements thereafter.  Fixed price hedges will be limited to a maximum contract 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 regard to our fixed price customer mix, we 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 Commodity Supply Facility provides for cash borrowings of up to $45.0 million that we may access to finance seasonal working capital requirements, provided that we are in compliance with the Collateral Coverage Ratio requirement, as described below.  These cash borrowings will accrue interest at the greater of: (1) RBS Sempra’s cost of funds plus 5%; or (2) two-month LIBOR plus 5%.  Outstanding credit support (e.g., letters of credit and/or guarantees) provided by RBS Sempra will accrue interest at LIBOR plus 3%, with a minimum rate of 4% except that, if the cash held in certain collateral accounts exceeds all outstanding settlement payments under the Commodity Supply Facility by $27.0 million, interest will accrue at a reduced rate of 1% on the amount of outstanding credit support in excess of $27.0 million.

 

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

 

As of December 31, 2010, we had a Collateral Coverage Ratio of approximately 2.12:1.00.  The calculation of the Collateral Coverage Ratio as of December 31, 2010 reflected available liquidity under the Commodity Supply Facility of approximately $58.5 million, of which $45.0 million represents the maximum credit available for cash advances and $13.5 million represents excess liquidity that can be used for additional letters of credit, commodity purchases and other operating purposes..  As of December 31, 2010, we had no outstanding cash advances and had $31.1 million of letters of credit outstanding under the Commodity Supply Facility.

 

We must maintain a consolidated tangible net worth, as defined in the ISDA Master Agreements, of at least $60.0 million.

 

With regard to our fixed price customer mix, we may not, without the written consent of RBS Sempra, enter into any fixed price contracts, excluding renewals of existing fixed price contracts, if:

 

·      During any 12-month period, more than 75% of all RCEs have been added under fixed price contracts;

·      During any 12-month period, more than 235,000 RCEs have been added under fixed price contracts; and

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

 

We received a limited waiver from RBS Sempra, which allowed us to add more than 235,000 RCEs under fixed price contracts during the first contract year of the Commodity Supply Facility.

 

Other key provisions of the ISDA Master Agreements are described in the consolidated financial statements included in our 2010 Form 10-K.  As of December 31, 2010, we were in compliance with all provisions of the ISDA Master Agreements.

 

In connection with the Commodity Supply Facility, certain banking relationships that previously belonged to us are now under RBS Sempra’s name and control.  RBS Sempra releases cash to us as required to meet our ongoing operating cash requirements.  As of December 31, 2010, RBS Sempra holds $24.6 million of cash, which will be available to us for working capital needs during future months, and which is included as a component of accounts payable to RBS Sempra, net on the consolidated balance sheet at December 31, 2010.

 

Fixed Rate Notes due 2014

 

Pursuant to the Restructuring completed in September 2009, we issued $67.8 million aggregate principal amount of Fixed Rate Notes due 2014.  Interest on the Fixed Rate Notes due 2014 accrues at the rate of 13.25% per annum and is payable semi-annually in cash on February 1 and August 1 of each year, commencing on February 1, 2010, to the holders of record of

 

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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 of $17.8 million, which was recorded as a reduction from the Fixed Rate Notes due 2014 on our consolidated balance sheets, and which is being 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 the Fixed Rate Notes Escrow Account and by a second-priority security interest in substantially all other existing and future assets of the Company.  The Fixed Rate Notes Escrow Account was funded with approximately $9.0 million in September 2009, which represents the approximate interest payable on the Fixed Rate Notes due 2014 for a 12-month period.

 

On December 15, 2010, we commenced an offer to exchange our outstanding original Fixed Rate Notes due 2014 (the “Original Fixed Rate Notes”), which were not registered under the Securities Act of 1933, as amended (the “Securities Act”), for an equal principal amount of new Fixed Rate Notes due 2014 (the “Registered Fixed Rate Notes”) which are registered under the Securities Act.  On January 18, 2011, we exchanged $66.6 million aggregate principal amount of Original Fixed Rate Notes for an equal principal amount of Registered Fixed Rate Notes.  Holders of approximately $1.2 million of Original Fixed Rate Notes did not exchange their notes for Registered Fixed Rate Notes.

 

Pursuant to the terms of the registration rights agreement relating to the Original Fixed Rate Notes, the interest rate applicable to the Original Fixed Rate Notes increased by 0.25% per annum effective as of September 30, 2010, and by an additional 0.25% effective as of December 29, 2010, because we did not complete an exchange offer for the Original Fixed Rate Notes within five business days following the one year anniversary of the issue date of the Original Fixed Rate Notes.  When the exchange offer was completed on January 18, 2011, we ceased accruing additional interest on the Original Fixed Rate Notes.  We recorded less than $0.1 million of incremental interest expense through the closing date of the exchange offer on January 18, 2011.

 

Floating Rate Notes due 2011

 

As a result of the Restructuring, 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.  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.

 

The weighted-average interest rate for the Floating Rate Notes due 2011 was 8.08% and 8.67% for the three months ended December 31, 2010 and 2009, 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 of this Quarterly Report for additional commentary regarding our management of interest rate risk and the interest rate swaps.

 

Contractual Obligations

 

Under the Commodity Supply Facility, we are obligated to purchase a minimum of 130,000,000 MMBtus of natural gas from RBS Sempra, for physical delivery in accordance with the following schedule:  (1) 39,000,000 MMBtus during the first contract year; (2) 44,000,000 MMBtus during the second contract year; and (3) 47,000,000 MMBtus during the third contract year.  In addition, we are obligated to purchase a minimum of 1,850,000 MWhrs of electricity from RBS Sempra, for physical delivery in accordance with the following schedule:  (1) 500,000 MWhrs during the first contract year; (2) 650,000 MWhrs during the second contract year; and (3) 700,000 MWhrs during the third contract year.  The estimated total value of these purchases will depend upon the market price of natural gas at the time of purchase.  We will be obligated to pay a volumetric fee for any unused balance of the minimum volume purchase requirement for any contract year, or if the agreement is terminated prior to the end of the contract.  During the six months ended December 31, 2010, our average price paid for natural gas ranged from a high of approximately $5.30 per MMBtu in August 2010 to a low of approximately $3.90 per MMBtu in September 2010, and our average price paid for electricity ranged from a high of approximately $88.70 per

 

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MWhr in July 2010 to a low of approximately $69.00 per MWhr in November 2010.

 

During the first contract year of the Commodity Supply Facility, our actual purchases of commodity from RBS Sempra exceeded the minimum purchase obligations for natural gas and electricity.  Under the terms of the ISDA Master Agreements, such excess of actual purchases over the minimum purchase obligations are deducted from the minimum purchases requirement for the second contract year of the Commodity Supply Facility.  As of December 31, 2010, the commodity to be purchased for delivery to our customers during the second contract year of the Commodity Supply Facility is expected to exceed the minimum purchase obligation for natural gas and electricity for that year.

 

In September 2010, we entered into an amendment to an expiring operating lease agreement for our Maryland office, which extended the term of the lease to September 2016.  As of December 31, 2010, future annual minimum lease payments associated with the extended lease are expected to be $0.1 million for the remainder of fiscal year 2011, $0.2 million for fiscal years 2012 through 2014 and $0.6 million thereafter.

 

Off-Balance Sheet Arrangements

 

As of December 31, 2010 and June 30, 2010, we did not have any off-balance sheet arrangements.

 

Item 3.  Quantitative and Qualitative Disclosures About Market Risk

 

Commodity Price Risk

 

Commodity price risk is the risk of exposure to fluctuations in the price of natural gas and electricity.  Because our contracts require that we deliver full commodity requirements to 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 commodity hedges, physical basis hedges and congestion revenue rights in our Texas electricity market.

 

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 with respect to each delivery month against the final settlement price determined on the last trading day of the Henry Hub futures contract listed for such month on the NYMEX.  In the case of electricity swap instruments, settlement is based on ISO settlement prices during the month.  Natural gas 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 settlement price on the last trading day of the futures contract delivery month plus or minus an agreed-upon premium or discount.   All of the natural gas and electricity swaps have been executed “over-the-counter” on a bilateral basis under the Commodity Supply Facility.  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 December 31, 2010, we have the ability to enter into new derivative transactions through August 2012 under the Commodity Supply Facility, and the terms of such transactions may extend through October 2013.

 

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

 

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

 

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).

 

The potential losses in the fixed price natural gas portfolio using our actual net open position at the end of each month during the three months and six months ended December 31, 2010 and 2009 are summarized in the following table.  The table reflects higher potential losses in the fair value of our natural gas portfolio using this VAR model for the three months and six months ended December 31, 2009 due to higher commodity price volatility during that period, as compared with the same periods in fiscal year 2011.

 

 

 

Three Months ended
December 31,

 

Six Months ended
December 31,

 

Potential loss during the period:

 

2010

 

2009

 

2010

 

2009

 

 

 

($ in thousands)

 

 

 

 

 

 

 

 

 

 

 

Average

 

$

5

 

$

62

 

$

9

 

$

40

 

Maximum

 

8

 

71

 

14

 

71

 

Minimum

 

2

 

48

 

2

 

17

 

 

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

 

Weather Risk Management Activities

 

We are exposed to weather-related risk during our peak seasonal operating periods for natural gas and electricity.  Unusually warm temperatures during the winter months or unusually cool temperatures during the summer months can have a negative impact on our results of operations.  As of December 31, 2010, we entered into an HDD derivative agreement to mitigate the risk that actual temperatures experienced in our largest natural gas market during January 2011 may be warmer than normally experienced in that market based on historical weather data.  The contract will ultimately settle at an agreed-upon dollar amount for every actual HDD that exceeds an agreed-upon strike amount (resulting in a loss to us) or for every actual HDD less than the agreed-upon strike amount (resulting in a gain for us).  The Company did not pay any premium or other up-front fee in connection with the weather derivative contract.

 

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Credit Risk

 

We are exposed to credit risk in our risk management activities.  Credit risk is the risk of loss resulting from the nonperformance by a counterparty of its contractual obligations.  Our fixed price positions are executed under agreements that include master netting arrangements, which mitigate outstanding credit exposure.  Under the Commodity Supply Facility, our economic hedging activities are 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.  In markets where LDCs do not guarantee customer accounts receivable, we are exposed to the credit risk of our customers.  In certain of our markets where LDCs guarantee customer accounts receivable, we are exposed to the credit risk of the LDC rather than that of our customers.  The percentages of our sales in non-guaranteed and guaranteed markets are summarized in the following table.

 

 

 

Three Months ended
December 31,

 

Six Months ended
December 31,

 

Percentage of total sales of natural gas and electricity:

 

2010

 

2009

 

2010

 

2009

 

 

 

 

 

 

 

 

 

 

 

In markets where LDCs guarantee customer accounts receivable

 

63

%

48

%

61

%

44

%

In markets where LDCs do not guarantee customer accounts receivable

 

37

%

52

%

39

%

56

%

 


(1)   For fiscal year 2011, higher percentage of revenue in guaranteed markets primarily reflects incremental revenues related to the SSO Program, and revenue in new electricity markets where customer accounts receivable are guaranteed by the LDC.

 

In cases where the LDC guarantees customer accounts receivable, we monitor the credit ratings of LDCs and the parent companies of LDCs that guarantee our customer accounts receivable.  As of December 31, 2010, all of our customer accounts receivable in guaranteed markets was with LDCs with investment grade credit ratings.  We also periodically review payment history and financial information for LDCs to ensure that we identify and respond to any deteriorating trends.

 

The allowance for doubtful accounts represents our estimate of potential credit losses associated with customer accounts receivable in markets where such receivables are not guaranteed by LDCs.  We assess the adequacy of our allowance for doubtful accounts through review of the aging of customer accounts receivable and our assessment of the general economic conditions in the markets that we serve.  Based upon our review as of December 31, 2010, we believe that the allowance for doubtful accounts is adequate to cover potential credit losses related to customer accounts receivable.  An analysis of our allowance for doubtful accounts is provided in the following table.

 

 

 

Three Months ended
December 31,

 

Six Months ended
December 31,

 

 

 

2010

 

2009

 

2010

 

2009

 

 

 

(in thousands)

 

Allowance for doubtful accounts activity:

 

 

 

 

 

 

 

 

 

Balance at beginning of period

 

$

4,480

 

$

6,340

 

$

5,074

 

$

7,344

 

Add: Provision for doubtful accounts

 

1,808

 

1,503

 

3,200

 

3,096

 

Less: Net charge offs of customer accounts receivable

 

(1,428

)

(2,715

)

(3,414

)

(5,312

)

Balance at end of period

 

$

4,860

 

$

5,128

 

$

4,860

 

$

5,128

 

 

 

 

 

 

 

 

 

 

 

Credit quality statistics:

 

 

 

 

 

 

 

 

 

Allowance for doubtful accounts as a percentage of total customer accounts receivable in non-guaranteed markets at end of period

 

9.9

%

9.2

%

9.9

%

9.2

%

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

 

2.7

%

1.9

%

2.9

%

2.4

%

 

The allowance for doubtful accounts as a percentage of total customer accounts receivable in non-guaranteed markets fluctuates significantly during our fiscal year depending on seasonal sales activity.  The percentage is generally lower at December 31 and March 31, when our total customer accounts receivable is high and aged accounts receivable are a relatively small percentage of the total.  The percentage is generally higher at June 30 and September 30, when our total customer accounts receivable is low and aged accounts receivable are a relatively large percentage of the total.

 

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

 

Interest Rate Risk

 

We are exposed to risk from fluctuations in interest rates under the Commodity Supply Facility and the Floating Rate Notes due 2011.  We manage our exposure to interest rate fluctuations by utilizing fixed-for-floating interest rate swaps to effectively convert the interest rate exposure from a variable rate to a fixed rate of interest.  The fixed-for-floating swap effectively fixes the six-month LIBOR rate at 5.72% per annum.

 

We have not designated interest rate swaps as hedges and, accordingly, changes in the market value of the interest rate swaps are charged directly to interest expense.  As of December 31, 2010, the total unrealized loss from risk management activities on the consolidated balance sheets related to interest rate swaps was approximately $4.1 million.  As of December 31, 2010, we were required to post $4.1 million of cash as collateral for our mark-to-market exposure related to the outstanding interest rate swap agreement.

 

Under the Commodity Supply Facility, we are subject to variable interest rates in connection with cash borrowings and credit support, primarily in the form of letters of credit, provided by RBS Sempra.  As of December 31, 2010, approximately $31.1 million of letters of credit were outstanding under the Commodity Supply Facility, in addition to the $6.4 million aggregate principal of Floating Rate Notes due 2011.

 

Based on the net exposure as of December 31, 2010 resulting from the interest rate swap, the letters of credit outstanding under the Commodity Supply Facility and the outstanding balance of Floating Rate Notes due 2011 on the consolidated balance sheets as of December 31, 2010, the impact of a 1% change in interest rates on interest expense for a 12-month period is estimated to be approximately $0.4 million.

 

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

 

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Table of Contents

 

Item 4.  Controls and Procedures

 

Management is responsible for establishing and maintaining adequate control over financial reporting for the Company.  Our system of internal control over financial reporting and disclosure controls and procedures is designed to ensure that information required to be disclosed in reports filed or submitted to the Commission under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported within the time period specified in the Commission’s rules and forms, and accumulated and communicated to our management, including our principal executive and principal financial officer, to allow timely decisions regarding required disclosure.  In designing and evaluating our disclosure controls and procedures, our management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management necessarily is required to apply its judgment in designing and evaluating the controls and procedures. We regularly review our disclosure controls and procedures, and our internal controls over financial reporting, and may from time to time make appropriate changes aimed at enhancing their effectiveness and ensure that our systems evolve with our business.

 

An evaluation was conducted, with the participation of our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of December 31, 2010.  Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were not effective, as of December 31, 2010, due to the material weakness in our internal control over financial reporting described below.

 

In our 2010 Form 10-K, we reported our conclusion that certain prior year deficiencies continued to constitute a material weakness in our internal control over financial reporting.  As of June 30, 2010, we instituted enhanced processes and controls to remediate the outstanding deficiencies, which included controls designed to prevent errors from occurring as well as controls designed to detect errors that do occur.  However, the effectiveness of such new controls was not yet adequately tested for all of our markets as of June 30, 2010.   As of December 31, 2010, we have completed our testing of these controls and reached the conclusion that such controls are effective as designed for all our markets.  However, due to the significant manual effort required to execute such controls, we are currently unable to satisfactorily execute them for all of our markets within an acceptable timeframe.  As a result, we recently amended our remediation plan to include new controls that are more preventative and, where possible, automated in nature.  As of December 31, 2010 and the filing date of this Quarterly Report, we are in the planning and development stage for the creation of new preventative controls and for automation of certain existing manual controls.

 

Therefore, we concluded that the material weakness in the design and operation of our internal controls over financial reporting still exists as of December 31, 2010 such that there was a reasonable possibility that a material misstatement of our interim or annual financial statements would not have been prevented or detected on a timely basis.  There were no changes in internal controls during the three months ended December 31, 2010 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

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Table of Contents

 

Part II.  Other Information

 

Item 1.  Legal Proceedings

 

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

 

Item 1A.  Risk Factors

 

There are many risk factors that could materially affect our business, financial condition and results of operations.  Except as disclosed below, there have been no material changes to the risk factors disclosed in our 2010 Annual Report.

 

RBS Sempra intends to sell the entity which provides our Commodity Supply Facility, which could impact our ability to obtain commodity supply, credit and hedging instruments needed for our operations.

 

RBS Sempra has indicated its intent to complete an orderly sale of its assets including, but not limited to, the entity which provides our Commodity Supply Facility.  Although we have received assurances from RBS Sempra that it will continue to fulfill its obligations under the Commodity Supply Facility, we are actively exploring alternatives for potential new supply, credit and hedging counterparties.  If RBS Sempra or any potential new Commodity Supply Facility owner is unable to meet its commodity supply, credit and hedging obligations under the Commodity Supply Facility, our operating results and liquidity position would be adversely affected.  Additionally, in the event RBS Sempra or any potential new Commodity Supply Facility owner did not meet its obligations under the Commodity Supply Facility, we cannot ensure that we could procure satisfactory alternative arrangements to meet our needs that are on terms satisfactory to us or at all.

 

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

 

None.

 

Item 3.  Defaults Upon Senior Securities

 

None.

 

Item 4.  (Removed and Reserved)

 

Item 5.  Other Information

 

None.

 

Item 6.  Exhibits

 

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

 

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Table of Contents

 

Signatures

 

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

 

Date:

February 14, 2011

MXENERGY HOLDINGS INC.

 

(Registrant)

 

 

 

/s/ Jeffrey A. Mayer

 

Jeffrey A Mayer

 

President and Chief Executive Officer

 

(Principal executive officer)

 

 

 

 

Date:

February 14, 2011

/s/ Chaitu Parikh

 

Chaitu Parikh

 

Executive Vice President and Chief Financial Officer

 

(Principal financial officer)

 

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Table of Contents

 

Index to Exhibits

 

Exhibit
Number

 

Title

31.1

 

Certification as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 *

31.2

 

Certification as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 *

32

 

Certification required by 18 United States Code Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 *†

 


*

 

Filed herewith.

 

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

 

62