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EXCEL - IDEA: XBRL DOCUMENT - Spark Energy, Inc.Financial_Report.xls
EX-31.2 - CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO RULE 13A-14(A) - Spark Energy, Inc.a312-certificationofchieff.htm
EX-31.1 - CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO RULE 13A-14(A) - Spark Energy, Inc.a311-certificationofchiefe.htm
EX-32 - CERTIFICATIONS PURSUANT TO 18 U.S.C. SECTION 1350. - Spark Energy, Inc.exhibit32-certificationspu.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
FORM 10-Q
 
 
 
ý      QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
For the quarterly period ended June 30, 2014,
 
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: 001-36559
Spark Energy, Inc.
(Exact name of registrant as specified in its charter)
 
 
 
 
 
Delaware
 
 
 
46-5453215
(State or other jurisdiction of
incorporation or organization)
 
 
 
(I.R.S. Employer
Identification No.)
2105 CityWest Blvd., Suite 100
Houston, Texas 77042

(Address of principal executive offices)
 
(713) 600-2600
(Registrant's telephone number, including area code)
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes o    No x
The registrant became subject to such requirements on July 28, 2014 and has filed all reports required since that date.
 

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 x    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 the 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 (Do not check if a smaller reporting company)          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

There were 3,000,000 shares of Class A common stock and 10,750,000 shares of Class B common stock outstanding as of September 10, 2014.




PART I. FINANCIAL INFORMATION
 
 
Item 1. FINANCIAL STATEMENTS
 
 
 
 
 
CONDENSED COMBINED BALANCE SHEETS AS OF JUNE 30, 2014 AND DECEMBER 31, 2013 (unaudited)

 
 
 
 
CONDENSED COMBINED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2014 AND 2013 (unaudited)
 
 
 
 
CONDENSED COMBINED STATEMENTS OF CASH FLOWS FOR THE SIX MONTHS ENDED JUNE 30, 2014 AND 2013 (unaudited)
 
 
 
 
CONDENSED COMBINED STATEMENT OF MEMBER’S EQUITY FOR THE SIX MONTHS ENDED JUNE 30, 2014 (unaudited)

 
 
 
 
NOTES TO THE CONDENSED COMBINED FINANCIAL STATEMENTS (unaudited)
 
 
 
 
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
Item 4. CONTROLS AND PROCEDURES
 
PART II. OTHER INFORMATION
 
Item 1. LEGAL PROCEEDINGS
 
Item 1A. RISK FACTORS
 
Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
 
Item 3. DEFAULTS UPON SENIOR SECURITIES
 
Item 4. MINE SAFETY DISCLOSURES
 
Item 5. OTHER INFORMATION
 
Item 6. EXHIBITS
 
APPENDIX A
 
SIGNATURES
 
EXHIBIT INDEX
 


1


PART 1. — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

SPARK ENERGY, INC.
CONDENSED COMBINED BALANCE SHEETS
AS OF JUNE 30, 2014 AND DECEMBER 31, 2013
(in thousands)
(unaudited)

June 30, 2014

December 31, 2013
 


 
Assets



Current assets:



Cash and cash equivalents
$
1,487


$
7,189

Accounts receivable, net of allowance for doubtful accounts
48,385


62,678

Accounts receivable-affiliates
40


6,794

Inventory
4,011


4,322

Fair value of derivative assets
980


8,071

Customer acquisition costs
10,959


4,775

Prepaid assets
1,578


1,032

Other current assets
10,549


6,430

Total current assets
77,989


101,291

Property and equipment, net
4,310


4,817

Fair value of derivative assets
74


6

Customer acquisition costs
4,085


2,901

Other assets


58

Total Assets
$
86,458


$
109,073

Liabilities and Member’s Equity



Current liabilities:



Accounts payable
$
35,025


$
36,971

Accounts payable-affiliates
261



Accrued liabilities
4,889


6,838

Fair value of derivative liabilities
3,281


1,833

Note payable
41,050


27,500

Other current liabilities
2,833



Total current liabilities
87,339


73,142

Long-term liabilities:





Fair value of derivative liabilities
3


18

Total liabilities
87,342


73,160

Member's equity:





Member’s equity
(884
)

35,913

Total Member’s equity
(884
)

35,913

Total Liabilities and Member’s Equity
$
86,458


$
109,073


The accompanying notes are an integral part of the condensed combined financial statements.

2


SPARK ENERGY, INC.
CONDENSED COMBINED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2014 AND 2013
(in thousands)
(unaudited)

Three Months Ended June 30,

Six Months Ended June 30,

2014

2013

2014

2013
Revenues:







Retail revenues (including retail revenues—affiliates of $681 and $311 for the three months ended June 30, 2014 and 2013, respectively, and retail revenues—affiliates of $2,170 and $510 for the six months ended June 30, 2014 and 2013, respectively)
$
65,743


$
67,263


$
170,095


$
167,716

Net asset optimization revenues (including asset optimization revenues-affiliates of $4,634 and $1,313 for the three months ended June 30, 2014 and 2013, respectively, and $7,134 and $2,765 for the six months ended June 30, 2014 and 2013, respectively, and asset optimization revenues affiliates cost of revenues of $10,654 and $540 for the three months ended June 30, 2014 and 2013, respectively, and $18,554 and $503 for the six months ended June 30, 2014 and 2013, respectively)
197


(1,782
)

1,821


(2,939
)
Total Revenues
65,940


65,481


171,916


164,777

Operating Expenses:







Retail cost of revenues (including retail cost of revenues-affiliates of less than $0.1 million and less than $0.1 million for both the three and six months ended June 30, 2014 and 2013)
52,387


52,406


140,508


122,399

General and administrative
9,747


9,437


17,860


18,712

Depreciation and amortization
3,252


4,284


6,211


9,314

Total Operating Expenses
65,386


66,127


164,579


150,425

Operating income (loss)
554


(646
)

7,337


14,352

Other (expense)/income:







Interest expense
(222
)

(286
)

(535
)

(670
)
Interest and other income
1


1


71


12

Total other expenses
(221
)

(285
)

(464
)

(658
)
Income (loss) before income tax expense
333


(931
)

6,873


13,694

Income tax expense
132


14


164


28

Net income (loss)
$
201


$
(945
)

$
6,709


$
13,666

Other comprehensive income (loss):







Deferred gain (loss) from cash flow hedges


(591
)



2,620

Reclassification of deferred gain (loss) from cash flow hedges into net income (Note 6)


198




(84
)
Comprehensive income (loss)
$
201


$
(1,338
)

$
6,709


$
16,202


The accompanying notes are an integral part of the condensed combined financial statements.


3


SPARK ENERGY, INC.
CONDENSED COMBINED STATEMENTS OF CASH FLOWS
FOR THE SIX MONTHS ENDED JUNE 30, 2014 AND 2013
(in thousands)
(unaudited) 
  
Six Months Ended June 30,
  
2014
 
2013
 
 
 
 
Cash flows from operating activities:
 
 
 
Net income
$
6,709

 
$
13,666

Adjustments to reconcile net income to net cash flows provided by operating activities:
 
 
 
Depreciation and amortization expense
6,211

 
9,314

Amortization and write off of deferred financing costs
225

 
231

Allowance for doubtful accounts and bad debt expense
2,027

 
1,086

(Gain) loss on derivatives, net
(1,440
)
 
641

Current period cash settlements on derivatives, net
10,256

 
810

Changes in assets and liabilities:
 
 
 
Decrease in accounts receivable
12,266

 
10,877

Decrease in accounts receivable—affiliates
6,754

 
6,119

Decrease in inventory
311

 
803

Increase in customer acquisition costs
(11,668
)
 
(866
)
Increase in prepaid and other current assets
(5,250
)
 
(2,024
)
Decrease in other assets
58

 
92

Decrease in accounts payable
(1,946
)
 
(133
)
Increase in accounts payable- affiliates
261

 

Decrease in accrued liabilities
(1,949
)
 
(2,529
)
Increase (decrease) in other liabilities
2,833

 
(518
)
Net cash provided by operating activities
25,658

 
37,569

Cash flows from investing activities:
 
 
 
Purchases of property and equipment
(1,404
)
 
(353
)
Net cash used in investing activities
(1,404
)
 
(353
)
Cash flows from financing activities:
 
 
 
Borrowings on notes payable
48,550

 
14,000

Payments on notes payable
(35,000
)
 
(21,000
)
Member distributions, net
(43,506
)
 
(32,333
)
Net cash used in financing activities
(29,956
)
 
(39,333
)
Decreases in cash and cash equivalents
(5,702
)
 
(2,117
)
Cash and cash equivalents—beginning of period
7,189

 
6,559

Cash and cash equivalents—end of period
$
1,487

 
$
4,442

Cash paid during the period for:
 
 
 
Interest
$
395

 
$
395

Taxes
$
150

 
$
195

The accompanying notes are an integral part of the condensed combined financial statements.


4


SPARK ENERGY, INC.
CONDENSED COMBINED STATEMENT OF MEMBER’S EQUITY
FOR THE SIX MONTHS ENDED JUNE 30, 2014
(in thousands)
(unaudited)
  
Member’s
equity
Balance at December 31, 2013
$35,913
Capital contributions from member
19,701
Distributions to member
(63,207)
Net income
6,709
Balance at June 30, 2014
$(884)
The accompanying notes are an integral part of the condensed combined financial statements.


5


SPARK ENERGY, INC.
NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS
(UNAUDITED)
1. Formation and Organization
Organization

Spark Energy, Inc. (the “Company”) is an independent retail energy services company that provides residential and commercial customers in competitive markets across the United States with an alternative choice for the natural gas and electricity. The Company is a holding company whose sole material asset consists of units in Spark HoldCo, LLC (“Spark HoldCo”). Spark HoldCo owns all of the outstanding membership interests in each of Spark Energy, LLC (“SE”) and Spark Energy Gas, LLC (“SEG”), the operating subsidiaries through which the Company operates. The Company is the sole managing member of Spark HoldCo, is responsible for all operational, management and administrative decisions relating to Spark HoldCo’s business and consolidates the financial results of Spark HoldCo and its subsidiaries.
The Company is a Delaware corporation formed on April 22, 2014 by Spark Energy Ventures, LLC (“Spark Energy Ventures”) for the purpose of succeeding to Spark Energy Ventures’ ownership in SE and SEG. Spark Energy Ventures, a single member limited liability company formed on October 8, 2007 under the Texas Limited Liability Company Act (“TLLCA”) is an affiliate of NuDevco Retail Holdings, LLC (“NuDevco Retail Holdings”), a single member Texas limited liability company formed by Spark Energy Ventures on May 19, 2014 under the Texas Business Organizations Code (“TBOC”). NuDevco Retail Holdings was formed by Spark Energy Ventures to hold its investment in Spark HoldCo, LLC, our subsidiary and the direct parent of SEG and SE. Spark Energy Ventures distributed its 100% interest in NuDevco Retail Holdings to NuDevco Partners Holdings ("NuDevco Partner Holdings"). The distribution resulted in NuDevco Retail Holdings being a direct wholly owned subsidiary of NuDevco Partners Holdings, which is wholly owned by NuDevco Partners, LLC ("NuDevco Partners"), which is wholly owned by W. Keith Maxwell III. NuDevco Retail Holdings formed NuDevco Retail, LLC ("NuDevco Retail" and, together with NuDevco Retail Holdings, "NuDevco"), a single member limited liability company, on May 29, 2014 and it holds a 1% interest in Spark HoldCo formerly held by NuDevco Retail Holdings.
Prior to the closing of the Company’s initial public offering of 3,000,000 shares of Class A common stock, par value $0.01 per share (the "Class A common stock"), representing a 21.82% interest in the Company on August 1, 2014 (the "Offering") Spark Energy Ventures contributed all of its interest in each of SE and SEG to NuDevco Retail Holdings. NuDevco Retail Holdings in turn contributed all of its interest in each of SE and SEG to Spark HoldCo. The contribution of the interests in SE and SEG to Spark HoldCo is not considered a business combination accounted for under the purchase method, as it was a transfer of assets and operations under common control and, accordingly, balances were transferred at their historical cost. The Company’s historical condensed combined financial statements prior to the Offering are prepared using SE’s and SEG’s historical basis in the assets and liabilities, and include all revenues, costs, assets and liabilities attributed to the retail natural gas and asset optimization and retail electricity businesses of SE and SEG for the periods presented.
SE is a licensed retail electric provider in multiple states. SE provides retail electricity services to end-use retail customers, ranging from residential and small commercial customers to large commercial and industrial users. SE was formed on February 5, 2002 under the Texas Revised Limited Partnership Act (as recodified by the TBOC) and was converted to a Texas limited liability company on May 21, 2014.

SEG is a retail natural gas provider and asset optimization business competitively serving residential, commercial and industrial customers in multiple states. SEG was formed on January 17, 2001 under the Texas Revised Limited Partnership Act (as recodified by the TBOC) and was converted to a Texas limited liability company on May 21, 2014.


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As a company with less than $1.0 billion in revenues during its last fiscal year, the Company qualifies as an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012, or the JOBS Act. An emerging growth company may take advantage of specified reduced reporting and other regulatory requirements.

The Company will remain an “emerging growth company” for up to five years, or until the earliest of (i) the last day of the fiscal year in which the Company has $1.0 billion or more in annual revenues; (ii) the date on which the Company becomes a “large accelerated filer” (the fiscal year-end on which the total market value of the Company’s common equity securities held by non-affiliates is $700 million or more as of June 30); (iii) the date on which the Company issues more than $1.0 billion of non-convertible debt over a three year period; or (iv) the last day of the fiscal year following the fifth anniversary of the Offering.
As a result of the Company's election to avail itself of certain provisions of the JOBS Act, the information that the Company provides may be different than what you may receive from other public companies in which you hold an equity interest.
Initial Public Offering of Spark Energy, Inc.

On August 1, 2014, the Company completed the Offering of 3,000,000 shares of its Class A common stock for $18.00 per share, representing a 21.82% voting interest in the Company.

Net proceeds from the Offering were $46.7 million, after underwriting discounts and commissions, structuring fees and offering expenses. The net proceeds from the Offering were used to acquire units of Spark HoldCo (the "Spark HoldCo units") representing approximately 21.82% of the outstanding Spark HoldCo units after the Offering from NuDevco Retail Holdings and to repay a promissory note from the Company in the principal amount of $50,000 (the "NuDevco Note"). The Company did not retain any of the net proceeds from the Offering. As of June 30, 2014, the Company recorded $2.3 million of deferred incremental costs directly attributable to the Offering in other current assets.

At the consummation of the Offering, the amount of common stock is summarized in the table below:


Shares of


common stock







Number

Percent
Publicly held Class A common stock

3,000,000


21.82
%
Class B common stock held by NuDevco Retail Holdings, LLC and NuDevco Retail, LLC

10,750,000


78.18
%
Total

13,750,000


100.00
%
Credit Facility
Concurrently with the closing of the Offering, the Company entered into a new $70.0 million senior secured revolving credit facility ("Senior Credit Facility"), which matures on August 1, 2016. If no event of default has occurred, the Company has the right, subject to approval by the administrative agent and each issuing bank, to increase the commitments under the Senior Credit Facility up to $120.0 million. At the closing of the Offering, the Company borrowed $10.0 million under the Senior Credit Facility to repay in full the portion of outstanding indebtedness under its pre-existing Senior Credit Facility. The new Senior Credit Facility is available to fund expansions, acquisitions and working capital requirements for operations and general corporate purposes.
At our election, interest will be generally determined by reference to:
the Eurodollar-based rate plus a margin ranging from 2.75% to 3.00%, depending on the overall utilization of the working capital facility;

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a base rate loan plus a margin ranging from 1.75% to 2.00%, depending on the overall utilization of the working capital facility; or
a cost of funds rate loan plus a margin ranging from 2.25% to 2.50%, depending on the overall utilization of the working capital facility.

Each working capital loan made as a result of a drawing under a letter of credit or a reducing letter of credit borrowing shall bear interest on the outstanding principal amount thereof from the date funded at a floating rate per annum equal to the base rate plus the applicable margin until such loan has been outstanding for more than two business days and, thereafter, shall bear interest on the outstanding principal amount thereof at a floating rate per annum equal to the base rate plus the applicable margin, plus two percent (2.0%) per annum.

Additionally, the Company will be charged a letter of credit fee for letters of credit outstanding. Our fee will be from 2.00% to 2.50% per annum, depending on the overall utilization of the working capital facility and what type of transaction it supports.
We pay an annual commitment fee of 0.375% or 0.5% on the unused portion of the Senior Credit Facility depending upon the unused capacity. The lending syndicate under the Senior Credit Facility is entitled to several additional fees including an upfront fee, annual agency fee, and fronting fees based on a percentage of the face amount of letters of credit payable to any syndicate member that issues a letter a credit.
The Senior Credit Facility is secured by the capital stock of SE, SEG and Spark HoldCo (the "Co-Borrowers") present and future subsidiaries, all of the Co-Borrowers’ and their subsidiaries’ present and future property and assets, including accounts receivable, inventory and liquid investments, and control agreements relating to bank accounts.
The Senior Credit Facility contains covenants which, among other things, require the Company to maintain certain financial ratios or conditions. At all times, the Company must maintain net working capital, tangible net worth and a leverage ratio to a certain threshold. The Senior Credit Facility also contains negative covenants that limit our ability to, among other things, make certain payments, distributions, investments, acquisitions or loans.
In addition, the Senior Credit Facility contains affirmative covenants that are customary for credit facilities of this type. The covenants include delivery of financial statements (including any filings made with the Securities and Exchange Commission (the "SEC")), maintenance of property and insurance, payment of taxes and obligations, material compliance with laws, inspection of property, books and records and audits, use of proceeds, payments to bank blocked accounts, notice of defaults and certain other customary matters. See Note 4.
Exchange and Registration Rights
NuDevco has the right to exchange (the “Exchange Right”) all or a portion of its Spark HoldCo units (together with a corresponding number of shares of Class B common stock) for Class A common stock (or cash at Spark Energy, Inc.’s or Spark HoldCo’s election (the “Cash Option”)) at an exchange ratio of one share of Class A common stock for each Spark HoldCo unit (and corresponding share of Class B common stock) exchanged. In addition, NuDevco has the right, under certain circumstances, to cause the Company to register the offer and resale of NuDevco's shares of Class A common stock obtained pursuant to the Exchange Right.

Tax Receivable Agreement

Concurrently with the closing of the Offering, the Company entered into a Tax Receivable Agreement with Spark HoldCo, NuDevco Retail Holdings and NuDevco Retail. This agreement generally provides for the payment by the Company to NuDevco of 85% of the net cash savings, if any, in U.S. federal, state and local income tax or franchise tax that the Company actually realizes (or is deemed to realize in certain circumstances) in future periods as a result of (i) any tax basis increases resulting from the purchase by the Company of Spark HoldCo units from NuDevco Retail Holdings in connection with the Offering, (ii) any tax basis increases resulting from the exchange of Spark HoldCo units for shares of Class A common stock pursuant to the Exchange Right (or resulting from an exchange of

8


Spark HoldCo units for cash pursuant to the Cash Option) and (iii) any imputed interest deemed to be paid by the Company as a result of, and additional tax basis arising from, any payments the Company makes under the Tax Receivable Agreement. The Company will retain the benefit of the remaining 15% of these tax savings.

In certain circumstances, the Company may defer or partially defer any payment due (a “TRA Payment”) to the holders of rights under the Tax Receivable Agreement, which are initially NuDevco Retail Holdings and NuDevco Retail. No TRA Payment will be made during 2014, and any future TRA Payments due with respect to a given taxable year are expected to be paid in December of the subsequent calendar year.

During the five-year period commencing October 1, 2014, the Company will defer all or a portion of any TRA Payment owed pursuant to the Tax Receivable Agreement to the extent that Spark HoldCo does not generate sufficient Cash Available for Distribution (as defined below) during the four-quarter period ending September 30th of the applicable year in which the TRA Payment is to be made in an amount that equals or exceeds 130% (the “TRA Coverage Ratio”) of the Total Distributions (as defined below) paid in such four-quarter period by Spark HoldCo. For purposes of computing the TRA Coverage Ratio:
 
"Cash Available for Distribution” is generally defined as the Adjusted EBITDA of Spark HoldCo for the applicable period, less (i) cash interest paid by Spark HoldCo, (ii) capital expenditures of Spark HoldCo (exclusive of customer acquisition costs) and (iii) any taxes payable by Spark HoldCo; and
"Total Distributions” are defined as the aggregate distributions necessary to cause the Company to receive distributions of cash equal to (i) the targeted quarterly distribution the Company intends to pay to holders of its Class A common stock payable during the applicable four-quarter period, plus (ii) the estimated taxes payable by the Company during such four-quarter period, plus (iii) the expected TRA Payment payable during the calendar year for which the TRA Coverage Ratio is being tested.

In the event that the TRA Coverage Ratio is not satisfied in any calendar year, the Company will defer all or a portion of the TRA Payment to NuDevco under the Tax Receivable Agreement to the extent necessary to permit Spark HoldCo to satisfy the TRA Coverage Ratio (and Spark HoldCo is not required to make and will not make the pro rata distributions to its members with respect to the deferred portion of the TRA Payment). If the TRA Coverage Ratio is satisfied in any calendar year, the Company will pay NuDevco the full amount of the TRA Payment.

Following the five-year deferral period, the Company will be obligated to pay any outstanding deferred TRA Payments to the extent such deferred TRA Payments do not exceed (i) the lesser of the Company's proportionate share of aggregate Cash Available for Distribution of Spark HoldCo during the five-year deferral period or the cash distributions actually received by the Company during the five-year deferral period, reduced by (ii) the sum of (a) the aggregate target quarterly dividends (which, for the purposes of the Tax Receivable Agreement, will be $0.3625 per share per quarter) during the five-year deferral period, (b) the Company's estimated taxes during the five-year deferral period, and (c) all prior TRA Payments and (y) if with respect to the quarterly period during which the deferred TRA Payment is otherwise paid or payable, Spark HoldCo has or reasonably determines it will have amounts necessary to cause the Company to receive distributions of cash equal to the target quarterly distribution payable during that quarterly period. Any portion of the deferred TRA Payments not payable due to these limitations will no longer be payable.

Other Transactions in Connection with the Consummation of the Offering
In connection with the Offering the following restructuring transactions occurred:

SEG and SE were converted from limited partnerships into limited liability companies;
SEG, SE and an affiliate entered into an interborrower agreement, pursuant to which such affiliate agreed to be solely responsible for $29.0 million of the outstanding indebtedness. SE and SEG repaid their outstanding indebtedness of $10.0 million and borrowed $10 million under the Company's Senior Credit Facility,

9


NuDevco Retail Holdings contributed all of its interests in SEG and SE to Spark HoldCo in exchange for all of the outstanding units of Spark HoldCo and transferred 1% of those Spark HoldCo units to NuDevco Retail;
NuDevco Retail Holdings transferred Spark HoldCo units to the Company for the $50,000 NuDevco Note and the limited liability company agreement of Spark HoldCo was amended and restated to admit the Company as its sole managing member; and
The Company issued 10,750,000 shares of Class B common stock, par value $0.01 per share (the "Class B common stock") to Spark HoldCo, 10,612,500 of which Spark HoldCo distributed to NuDevco Retail Holdings, and 137,500 of which Spark HoldCo distribute to NuDevco Retail.

Following the Offering, the Company purchased 2,997,222 Spark HoldCo units from NuDevco Retail Holdings and repaid the NuDevco Note. The 2,997,222 Spark Holdco units we purchased with the proceeds from the Offering, together with the 2,778 Spark HoldCo units we purchased in exchange for the NuDevco Note prior to the Offering, represent a 21.82% ownership interest in Spark HoldCo. After giving effect to these transactions and the Offering, the Company owns an approximate 21.82% interest in Spark HoldCo, NuDevco Retail Holdings owns an approximate 77.18% interest in Spark HoldCo and 10,612,500 shares of Class B common stock and NuDevco Retail owns a 1% interest in Spark HoldCo and 137,500 shares of Class B common stock.

Each share of Class B common stock, all of which is held by NuDevco, has no economic rights but entitles its holder to one vote on all matters to be voted on by shareholders generally. Holders of Class A common stock and Class B common stock vote together as a single class on all matters presented to our shareholders for their vote or approval, except as otherwise required by applicable law or by our certificate of incorporation.
2. Basis of Presentation
The accompanying interim unaudited condensed combined financial statements (“interim statements”) of the Company have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) and pursuant to the rules and regulations of the SEC.
The preparation of the financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities at the date of the interim financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Effects on the business, financial condition and results of operations resulting from revisions to estimates are recognized when the facts that give rise to the revision become known. The information furnished herein reflects all normal recurring adjustments which are, in the opinion of management, necessary for a fair presentation of the condensed combined financial statements. Operating results for the three and six months ended June 30, 2014 are not necessarily indicative of the results which may be expected for the full year or for any interim period. 
The accompanying interim unaudited condensed combined financial statements have been prepared in accordance with Regulation S-X, Article 3, General Instructions as to Financial Statements and Staff Accounting Bulletin (“SAB”) Topic 1-B, Allocations of Expenses and Related Disclosures in Financial Statements of Subsidiaries, Divisions or Lesser Business Components of Another Entity on a stand-alone basis and are derived from SE’s and SEG’s historical basis in the assets and liabilities, and include all revenues, costs, assets and liabilities attributable to the retail natural gas and asset optimization and retail electricity businesses of SE and SEG for the periods presented that are specifically identifiable or have been allocated to the Company. Management has made certain assumptions and estimates in order to allocate a reasonable share of expenses to the Company, such that the Company’s combined financial statements reflect substantially all of its costs of doing business. The Company also enters into transactions with and pays certain costs on behalf of affiliates under common control in order to reduce risk, create strategic alliances and supply goods and services to these related parties. The Company direct bills certain expenses incurred on behalf of affiliates or allocates certain overhead expenses to affiliates associated with general and administrative services based on services provided, departmental usage, or headcount, which are considered reasonable by management. The allocations and related estimates and assumptions are described more fully in Note 8 “Transactions with Affiliates”. These costs are not necessarily indicative of the cost that the

10


Company would have incurred had it operated as an independent stand-alone entity. Affiliates have also relied upon Spark Energy Ventures as a participant in the credit facility for the periods presented as described more fully in Note 4 “Long-Term Debt”. As such, the Company’s interim unaudited condensed combined financial statements do not fully reflect what the Company’s financial position, results of operations and cash flows would have been had the Company operated as an independent stand-alone company during the periods presented. As a result, historical financial information is not necessarily indicative of what the Company’s results of operations, financial position and cash flows will be in the future.

Net Income per Share
The Company has omitted earnings per share because the Company operated under a sole member equity structure for the periods presented, which is different than the capital structure resulting from the consummation of the Offering and, as a result, the per share data would not be meaningful to investors.

Transactions with Affiliates

The Company enters into transactions with and incurs certain costs on behalf of affiliates that are commonly controlled by NuDevco Retail Holdings in order to reduce administrative expense, create economies of scale and supply goods and services to these related parties. These transactions include, but are not limited to, certain services to the affiliated companies associated with the Company’s debt facility, employee benefits provided through the Company’s benefit plans, insurance plans, leased office space, and administrative salaries for accounting, tax, legal, or technology services. As such, the accompanying combined financial statements include costs that have been incurred by the Company and then directly billed or allocated to affiliates and are recorded net in general and administrative expense on the combined statements of operations with a corresponding accounts receivable—affiliates recorded in the combined balance sheets. Additionally, the Company enters into transactions with certain affiliates for sales or purchases of natural gas and electricity, which are recorded in retail revenues, retail cost of revenues, and net asset optimization revenues in the combined statements of operations with a corresponding accounts receivable—affiliate or accounts payable—affiliate in the combined balance sheets. Please read Note 8 “Transactions with Affiliates” for further discussion.

Subsequent Events

Subsequent events have been evaluated through the date these financial statements are issued. Any material subsequent events that occurred prior to such date have been properly recognized or disclosed in the condensed combined financial statements.

Recent Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2014-09, Revenue from Contracts with Customers, which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. ASU 2014-09 will replace most existing revenue recognition guidance in GAAP when it becomes effective on January 1, 2017. Early application is not permitted. The standard permits the use of either the retrospective or cumulative effect transition method. The Company is evaluating the effect that ASU 2014-09 will have on its financial statements and related disclosures. The Company has not yet selected a transition method nor has it determined the effect of the standard on its ongoing financial reporting.

3. Property and Equipment
Property and equipment consist of the following as of (in thousands):

11



Estimated 
useful
lives (years)

June 30, 2014

December 31, 2013
Information technology
2 – 5

$
23,933


$
22,529

Leasehold improvements
2 – 5

4,568


4,568

Furniture and Fixtures
2 – 5

998


998

Total


29,499


28,095

Accumulated depreciation


(25,189
)

(23,278
)
Property and equipment—net


$
4,310


$
4,817

Information technology assets include software and consultant time used in the application, development and implementation of various systems including customer billing and resource management systems. As of June 30, 2014 and December 31, 2013, information technology includes $2.7 million and $1.3 million, respectively, of costs associated with assets not yet placed into service.
Depreciation expense recorded in the condensed combined statements of operations was $1.0 million and $1.5 million for the three months ended June 30, 2014 and 2013, respectively, and $1.9 million and $3.1 million for the six months ended June 30, 2014 and 2013, respectively.
4. Long-Term Debt
In October 2007, Spark Energy Ventures and all of its subsidiaries (collectively, the “Borrowers”), entered into a credit agreement, consisting of a working capital facility, a term loan and a revolving credit facility (the “Credit Agreement”), with SE and SEG as co-borrowers under which they were jointly and severally liable for amounts Borrowers borrowed under the Credit Agreement. The Credit Agreement was secured by substantially all of the assets of Spark Energy Ventures and its subsidiaries.
The Credit Agreement was amended on May 30, 2008 to provide for a $177.5 million working capital facility, a $100 million term loan, and a $35 million revolving credit facility. On January 24, 2011, the Borrowers amended and restated the Credit Agreement (the “Fifth Amended Credit Agreement”) to decrease the working capital facility to $150 million, to increase the term loan to $130 million and to eliminate the revolving credit facility.
On December 17, 2012, the Borrowers amended and restated the Fifth Amended Credit Agreement to decrease the working capital facility to $70 million, to decrease the term loan to $125 million and to reinstate the revolving credit facility in the amount of $30 million (the “Sixth Amended Credit Agreement”). The Sixth Amended Credit Agreement was scheduled to mature on December 17, 2014.
On July 31, 2013 and in conjunction with the initial public offering of Marlin Midstream Partners, LP (“Marlin”), which was formerly wholly owned by Spark Energy Ventures, the Sixth Amended Credit Agreement was amended and restated to increase the working capital facility to $80 million and eliminated the term loan and revolving credit facility (the “Seventh Amended Credit Agreement”) and to remove Marlin as a party to the Credit Agreement. The Seventh Amended Credit Agreement was scheduled to mature on July 31, 2015. The Credit Agreement continued to be secured by the assets of Spark Energy Ventures and its subsidiaries through completion of the Offering.

Although SE and SEG, as wholly owned subsidiaries of Spark Energy Ventures, were jointly and severally liable for Marlin’s borrowing under the Credit Agreement prior to the Marlin initial public offering, SE and SEG did not historically have access to or use the term loan and the revolving credit facility utilized by Marlin. SE and SEG were the primary recipients of the proceeds from the working capital facility.
The Company adopted Accounting Standards Update (“ASU”) 2013-04, which prescribes the accounting for joint and several liability arrangements early and applied the accounting guidance retrospectively to its 2013 condensed combined financial statements as required by the standard. This guidance requires an entity to measure its obligation resulting from joint and several liability arrangements for which the total amount under the arrangement

12


is fixed at the reporting date, as the sum of the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and any additional amount the reporting entity expects to pay on behalf of its co-obligors. Based on the Sixth Amended Credit Agreement prior to the Marlin initial public offering and understanding among the Borrowers, the term loan and the revolving credit facility were assigned specifically to Marlin. The Company has recognized the proceeds from the working capital facility in its combined balance sheets, which represented the amounts the Company with the other Borrowers agreed to pay, and the amounts the Company expected to pay.
Working Capital Facility
The working capital facility was $150 million in 2012 under the Fifth Amended Credit Agreement and was later amended to $70 million on December 17, 2012 under the Sixth Amended Credit Agreement. On July 31, 2013 and in conjunction with the Seventh Amended Credit Agreement the working capital facility was increased to $80 million and was scheduled to mature on July 31, 2015.
The working capital facility was available for use by Spark Energy Ventures and its affiliates to finance the working capital requirements related to the purchase and sale of natural gas, electricity, and other commodity products not related to the retail natural gas and asset optimization and retail electricity businesses of the Company. The Company’s combined financial statements include the total amounts outstanding under the working capital facility of $41.0 million and $27.5 million as of June 30, 2014 and December 31, 2013, respectively, and are classified as current in the combined balances sheets as the working capital facility is drawn on and repaid on a monthly basis to fund working capital needs. The total amounts outstanding under the facility as of June 30, 2014 and December 31, 2013 include amounts used to fund equity distributions to the sole member of the Company to fund unrelated operations of an affiliate under the common control of the sole member, which was a co-borrower under the facility.
Further, through the issuance of letters of credit, the Company was able to secure payment to suppliers. No obligation is recorded for such outstanding letters of credit unless they are drawn upon by the suppliers and in the event a supplier draws on a letter of credit, repayment is due by the earlier of demand by the bank or at the expiration of the Credit Agreement. Letters of credit issued and outstanding as of June 30, 2014 and December 31, 2013 were $9.7 million and $10.0 million, respectively.
Under the working capital facility, the Company paid a fee with respect to each letter of credit issued and outstanding. The Company incurred fees on letters of credit issued and outstanding totaling $0.1 million and $0.2 million for the three months ended June 30, 2014 and 2013, respectively, and $0.2 million and $0.3 million, for the six months ended June 30, 2014 and 2013, respectively, which is recorded in interest expense in the condensed combined statements of operations.
Under the Sixth Amended Credit Agreement, the Company may elect to have loans under the credit facility bear interest either (i) at a Eurodollar-based rate plus a margin ranging from 3.00% to 3.75% depending on the Company’s consolidated funded indebtedness ratio then in effect, or (ii) at a base rate loan plus a margin ranging from 2.00% to 2.75% depending on the Company’s consolidated funded indebtedness ratio then in effect. The Company also pays a nonutilization fee equal to 0.50% per annum.
Under the Seventh Amended Credit Agreement, the Company may elect to have loans under the working capital facility bear interest (i) at a Eurodollar-based rate plus a margin ranging from 3.00% to 3.25%, depending on the Spark Energy Ventures’ aggregate amount outstanding then in effect, (ii) at a base rate loan plus a margin ranging from 2.00% to 2.25%, depending on Spark Energy Ventures’ aggregate amount outstanding then in effect or (iii) a cost of funds rate loan plus a margin ranging from 2.50% to 2.75%, depending on Spark Energy Ventures’ aggregate amount outstanding then in effect. Each working capital loan made as a result of a drawing under a letter of credit bears interest on the outstanding principal amount thereof from the date funded at a floating rate per annum equal to the cost of funds rate plus the applicable margin until such loan has been outstanding for more than two business days and, thereafter, bears interest on the outstanding principal amount thereof at a floating rate per annum equal to the base rate plus the applicable margin, plus two percent 2.00% per annum. The Company incurred interest

13


expense of less than $0.1 million for each of the three and six months ended June 30, 2014 and 2013, which is recorded in interest expense in the condensed combined statements of operations.
The Company also pays a commitment fee equal to 0.50% per annum. The Company incurred commitment fees totaling less than $0.1 million for each of the three and six months ended June 30, 2014 and 2013, which is recorded in interest expense in the condensed combined statements of operations.
Deferred Financing Costs
Deferred financing costs were $0.4 million and $0.5 million as of June 30, 2014 and December 31, 2013, respectively. Of these amounts, $0.4 million and $0.4 million is recorded in other current assets in the combined balance sheet as of June 30, 2014 and December 31, 2013, respectively, and $0.1 million is recorded in other assets in the combined balance sheet as of December 31, 2013, respectively, based on the term of the working capital facility.
Amortization of deferred financing costs was $0.1 million for both the three months ended June 30, 2014 and 2013, respectively, and $0.2 million for each of the six months ended June 30, 2014 and 2013, which is recorded in interest expense in the condensed combined statements of operations.
NuDevco Note
NuDevco Retail Holdings transferred Spark HoldCo units to the Company for the $50,000 NuDevco Note and the limited liability company agreement of Spark HoldCo, was amended and restated to admit Spark Energy, Inc. as its sole managing member. This promissory note was repaid in connection with proceeds from the Offering.
New Credit Facility

Concurrently with the closing of the Offering, the Company entered into a new $70.0 million Senior Credit Facility. The Company borrowed approximately $10.0 million under the Senior Credit Facility at the closing of the Offering to repay in full the portion of outstanding indebtedness under the Seventh Amended Credit Agreement that SEG and SE agreed to be responsible for pursuant to an interborrower agreement between SEG, SE and an affiliate. The remainder of indebtedness outstanding under the Seventh Amended Credit Agreement was paid down by our affiliate with its own funds concurrently at the closing of the Offering pursuant to the terms of the interborrower agreement. Following this repayment, the Seventh Amended Credit Agreement was terminated. The Company had $15 million in letters of credit issued under the Senior Credit Facility at inception. See Note 1.
5. Fair Value Measurements
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. Fair values are based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. This includes not only the credit standing of counterparties involved and the impact of credit enhancements but also the impact of the Company’s own nonperformance risk on its liabilities.

The Company applies fair value measurements to its commodity derivative instruments based on the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:

Level 1—Quoted prices in active markets for identical assets and liabilities. Instruments
categorized in Level 1 primarily consist of financial instruments such as exchange-traded derivative
instruments.
Level 2—Inputs other than quoted prices recorded in Level 1 that are either directly or indirectly

14


observable for the asset or liability, including quoted prices for similar assets or liabilities in active
markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other
than quoted prices that are observable for the asset or liability, and inputs that are derived from
observable market data by correlation or other means. Instruments categorized in Level 2 primarily
include non-exchange traded derivatives such as over-the-counter commodity forwards and swaps
and options.
Level 3—Unobservable inputs for the asset or liability, including situations where there is little, if
any, observable market activity for the asset or liability.

As the fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3), the Company maximizes the use of observable inputs and minimizes the use of unobservable inputs when measuring fair value. In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. In these cases, the lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy.
Non-Derivative Financial Instruments
The carrying amount of cash and cash equivalents, accounts receivable, accounts receivable-affiliates, accounts payable, accounts payable-affiliates, and accrued liabilities recorded in the combined balance sheets approximate fair value due to the short-term nature of these items. The carrying amount of long-term debt recorded in the condensed combined balance sheets approximates fair value because of the variable rate nature of the Company’s long-term debt.
Derivative Instruments
The following table presents assets and liabilities measured and recorded at fair value in the Company’s condensed combined balance sheets on a recurring basis by and their level within the fair value hierarchy as of (in thousands): 

Level 1

Level 2

Level 3

Total
June 30, 2014
 

 

 

 
Non-trading commodity derivative assets
$
172


$
228


$


$
400

Trading commodity derivative assets
(31
)

685




654

Total commodity derivative assets
$
141


$
913


$


$
1,054

Non-trading commodity derivative liabilities
$


$
(2,775
)

$


$
(2,775
)
Trading commodity derivative liabilities


(509
)



(509
)
Total commodity derivative liabilities
$


$
(3,284
)

$


$
(3,284
)

Level 1

Level 2

Level 3

Total
December 31, 2013







Non-trading commodity derivative assets
$


$
4,672


$


$
4,672

Trading commodity derivative assets


3,405




3,405

Total commodity derivative assets
$


$
8,077


$


$
8,077

Non-trading commodity derivative liabilities
$
(563
)

$
(854
)

$


$
(1,417
)
Trading commodity derivative liabilities
147


(581
)



(434
)
Total commodity derivative liabilities
$
(416
)

$
(1,435
)

$


$
(1,851
)
The Company had no financial instruments measured using level 3 at June 30, 2014 and December 31, 2013. The Company had no transfers of assets or liabilities between any of the above levels during the six months ended June 30, 2014 and the year ended December 31, 2013.
The Company’s derivative contracts include exchange-traded contracts fair valued utilizing readily available quoted market prices and non-exchange-traded contracts fair valued using market price quotations available through

15


brokers or over-the-counter and on-line exchanges. In addition, in determining the fair value of the Company’s derivative contracts, the Company applies a credit risk valuation adjustment to reflect credit risk which is calculated based on the Company’s or the counterparty’s historical credit risks. As of June 30, 2014 and December 31, 2013, the credit risk valuation adjustment was not material.
6. Accounting for Derivative Instruments
The Company is exposed to the impact of market fluctuations in the price of electricity and natural gas and basis costs, storage and ancillary capacity charges from independent system operators. The Company uses derivative instruments to manage exposure to these risks, and historically designated certain derivative instruments as cash flow hedges for accounting purposes. For derivatives designated in a qualifying cash flow hedging relationship, the effective portion of the change in fair value is recognized in accumulated OCI and reclassified to earnings in the period in which the hedged item affects earnings. Any ineffective portion of the derivative’s change in fair value is recognized currently in earnings.
The Company also holds certain derivative instruments that are not held for trading purposes but are also not designated as hedges for accounting purposes. These derivative instruments represent economic hedges that mitigate the Company’s exposure to fluctuations in commodity prices. For these derivative instruments, changes in the fair value are recognized currently in earnings in retail revenues or retail cost of revenues.
As part of the Company’s strategy to optimize its assets and manage related risks, it also manages a portfolio of commodity derivative instruments held for trading purposes. The Company’s commodity trading activities are subject to limits within the Company’s Risk Management Policy. For these derivative instruments, changes in the fair value are recognized currently in earnings in net asset optimization revenues.
Derivative assets and liabilities are presented net in the Company’s condensed combined balance sheets when the derivative instruments are executed with the same counterparty under a master netting arrangement. The Company’s derivative contracts include transactions that are executed both on an exchange and centrally cleared as well as over-the-counter, bilateral contracts that are transacted directly with a third party. To the extent the Company has paid or received collateral related to the derivative assets or liabilities, such amounts would be presented net against the related derivative asset or liability’s fair value. As of June 30, 2014 the Company had paid $0.4 million related to derivative liabilities fair value. As of December 31, 2013, the Company had not paid or received any collateral amounts. The specific types of derivative instruments the Company may execute to manage the commodity price risk include the following:

Forward contracts, which commit the Company to purchase or sell energy commodities in the
future;
Futures contracts, which are exchange-traded standardized commitments to purchase or sell a
commodity or financial instrument;
Swap agreements, which require payments to or from counterparties based upon the differential
between two prices for a predetermined notional quantity; and
Option contracts, which convey to the option holder the right but not the obligation to purchase or
sell a commodity.
The Company has entered into other energy-related contracts that do not meet the definition of a derivative instrument or qualify for the normal purchase or normal sale exception and are therefore not accounted for at fair value including the following:

Forward electricity and natural gas purchase contracts for retail customer load, and
Natural gas transportation contracts and storage agreements. 
Volumetric Underlying Derivative Transactions

16


The following table summarizes the net notional volume buy/(sell) of the Company’s open derivative financial instruments accounted for at fair value, broken out, by commodity as of:
Non-trading 
Commodity
Notional

June 30, 2014

December 31, 2013
Natural Gas
MMBtu

6,841


3,513

Natural Gas Basis
MMBtu

3,108


373

Electricity
MWh

722


465

Trading
Commodity
Notional

June 30, 2014

December 31, 2013
Natural Gas
MMBtu

389


2,259

Natural Gas Basis
MMBtu

615


1,443


Gains (Losses) on Derivative Instruments
Gains (losses) on derivative instruments, net and current period settlements on derivative instruments were as follows for the periods indicated (in thousands):
 
  
Three Months Ended June 30,
  
2014

2013
Loss on non-trading derivatives—cash flow hedges, net (including ineffectiveness gain of $560 for the three months ended June 30, 2013)
$


$
351

Loss on non-trading derivatives, net (including gain (loss) on non-trading derivatives—affiliates, net of ($157) and $76 for the three months ended June 30, 2014 and 2013, respectively)
(4,438
)

(3,112
)
Gain (loss) on trading derivatives, net (including gain (loss) on trading derivatives—affiliates, net of ($866) and $449 for the three months ended June 30, 2014 and 2013, respectively)
419


(123
)
Loss on derivatives, net
$
(4,019
)

$
(2,884
)
Current period settlements on non-trading derivatives—cash flow hedges
$


$
209

Current period settlements on non-trading derivatives
(97
)

393

Current period settlements on trading derivatives (including current period settlements on trading derivatives—affiliates, net of $866 and $540 for the three months ended June 30, 2014 and 2013, respectively)
38


59

Total current period settlements on derivatives
$
(59
)

$
661


17


  
Six Months Ended June 30,
  
2014

2013
Gain on non-trading derivatives—cash flow hedges, net (including ineffectiveness loss of $288 for the six months ended June 30, 2013)
$


$
(204
)
Gain (Loss) on non-trading derivatives, net (including gain on non-trading derivatives—affiliates, net of $76 for the six months ended June 30, 2013)
7,010


(1,983
)
Gain (loss) on trading derivatives, net (including loss on trading derivatives—affiliates, net of $1,792 and $271 for the six months ended June 30, 2014 and 2013, respectively)
(5,570
)

1,546

Gain (Loss) on derivatives, net
$
1,440


$
(641
)
Current period settlements on non-trading derivatives—cash flow hedges
$


$
(1,180
)
Current period settlements on non-trading derivatives
(12,998
)

(124
)
Current period settlements on trading derivatives (including current period settlements on trading derivatives—affiliates, net of $1,693 and $540 for the six months ended June 30, 2014 and 2013, respectively)
2,742


494

Total current period settlements on derivatives
$
(10,256
)

$
(810
)
Gains (losses) on trading derivative instruments are recorded in net asset optimization revenues and gains (losses) on non-trading derivative instruments are recorded in retail revenues or retail cost of revenues on the condensed combined statements of operations.
Fair Value of Derivative Instruments
The following tables summarize the fair value and offsetting amounts of the Company’s derivative instruments by counterparty and collateral received or paid as of (in thousands):
 
  
June 30, 2014
Description
Gross Assets
 
Gross
Amounts
Offset
 
Net Assets
 
Cash
Collateral
Offset
 
Net Amount
Presented
Non-trading commodity derivatives
$
3,740

 
$
(3,414
)
 
$
326

 
$

 
$
326

Trading commodity derivatives
1,235

 
(581
)
 
654

 

 
654

Total Current Derivative Assets
$
4,975

 
$
(3,995
)
 
$
980

 
$

 
$
980

Non-trading commodity derivatives
$
128

 
$
(54
)
 
$
74

 
$

 
$
74

Total Non-current Derivative Assets
$
128

 
$
(54
)
 
$
74

 
$

 
$
74

Total Derivative Assets
$
5,103

 
$
(4,049
)
 
$
1,054

 
$

 
$
1,054

  
June 30, 2014
Description
Gross 
Liabilities
 
Gross
Amounts
Offset
 
Net
Liabilities
 
Cash
Collateral
Offset
 
Net Amount
Presented
Non-trading commodity derivatives
$
(6,545
)
 
$
3,414

 
$
(3,131
)
 
$
360

 
$
(2,771
)
Trading commodity derivatives
(1,091
)
 
581

 
(510
)
 

 
(510
)
Total Current Derivative Liabilities
$
(7,636
)
 
$
3,995

 
$
(3,641
)
 
$
360

 
$
(3,281
)
Non-trading commodity derivatives
$
(57
)
 
$
54

 
$
(3
)
 
$

 
$
(3
)
Total Non-current Derivative Liabilities
$
(57
)
 
$
54

 
$
(3
)
 
$

 
$
(3
)
Total Derivative Liabilities
$
(7,693
)
 
$
4,049

 
$
(3,644
)
 
$
360

 
$
(3,284
)
 

18


  
December 31, 2013
Description
Gross Assets
 
Gross
Amounts
Offset
 
Net Assets
 
Cash
Collateral
Offset
 
Net Amount
Presented
Non-trading commodity derivatives
$
11,564

 
$
(6,898
)
 
$
4,666

 
$

 
$
4,666

Trading commodity derivatives
3,949

 
(544
)
 
3,405

 

 
3,405

Total Current Derivative Assets
$
15,513

 
$
(7,442
)
 
$
8,071

 
$

 
$
8,071

Non-trading commodity derivatives
$
100

 
$
(94
)
 
$
6

 
$

 
$
6

Trading commodity derivatives
14

 
(14
)
 

 

 

Total Non-current Derivative Assets
$
114

 
$
(108
)
 
$
6

 
$

 
$
6

Total Derivative Assets
$
15,627

 
$
(7,550
)
 
$
8,077

 
$

 
$
8,077

 
  
December 31, 2013
Description
Gross 
Liabilities
 
Gross
Amounts
Offset
 
Net
Liabilities
 
Cash
Collateral
Offset
 
Net Amount
Presented
Non-trading commodity derivatives
$
(8,289
)
 
$
6,898

 
$
(1,391
)
 
$

 
$
(1,391
)
Trading commodity derivatives
(986
)
 
544

 
(442
)
 

 
(442
)
Total Current Derivative Liabilities
$
(9,275
)
 
$
7,442

 
$
(1,833
)
 
$

 
$
(1,833
)
Non-trading commodity derivatives
$
(120
)
 
$
94

 
$
(26
)
 
$

 
$
(26
)
Trading commodity derivatives
(6
)
 
14

 
8

 

 
8

Total Non-current Derivative Liabilities
$
(126
)
 
$
108

 
$
(18
)
 
$

 
$
(18
)
Total Derivative Liabilities
$
(9,401
)
 
$
7,550

 
$
(1,851
)
 
$

 
$
(1,851
)

Accumulated Other Comprehensive Income
The following table summarizes the effects on the Company’s accumulated OCI balance attributable to cash flow hedge derivative instruments for the periods indicated (in thousands): 
  
Three Months Ended June 30,

Six Months Ended June 30,
  
2014

2013

2014

2013
Accumulated OCI balance, beginning of period
$


$
393


$


$
(2,536
)
Deferred gain (loss) on cash flow hedge derivative instruments


(591
)



2,620

Reclassification of accumulated OCI net to income


198




(84
)
Accumulated OCI balance, end of period
$


$


$


$

The amounts reclassified from accumulated OCI into income and any amounts recognized in income from the ineffective portion of cash flow hedges are recorded in retail cost of revenues. In June 2013, the Company elected to discontinue cash flow hedge accounting.
7. Commitments and Contingencies
From time to time, the Company may be involved in legal, tax, regulatory and other proceedings in the ordinary course of business. Management does not believe that we are a party to any litigation that will have a material impact on the Company’s combined financial condition or results of operations.


19


8. Transactions with Affiliates
The Company enters into transactions with and pays certain costs on behalf of affiliates that are commonly controlled in order to reduce administrative expense, create economies of scale and supply goods and services to these related parties. The Company also sells and purchases natural gas and electricity with affiliates. The Company presents receivables and payables with the same affiliate on a net basis on the combined balance sheets as all affiliate activity is with parties under common control.
Accounts Receivable and Payable-Affiliates
The Company recorded current accounts receivable—affiliates of less than $0.1 million and $6.8 million as of June 30, 2014 and December 31, 2013, respectively, and current accounts payable-affiliates of $0.3 million as of June 30, 2014 for certain direct billings and cost allocations for services the Company provided to affiliates and sales or purchases of natural gas and electricity with affiliates.
Revenues and Cost of Revenues-Affiliates
Prior to Marlin’s initial public offering on July 31, 2013, the Company provided natural gas to Marlin, who is a processing service provider, whereby Marlin gathered natural gas from the Company and other third parties, extracted NGLs, and redelivered the processed natural gas to the Company and other third parties. Marlin replaced energy used in processing due to the extraction of liquids, compression and transportation of natural gas, and fuel by making a payment to the Company at market prices. Revenues-affiliates, recorded in net asset optimization revenues in the condensed combined statements of operations, related to Marlin’s payments to the Company for replaced energy for the three and six months ended June 30, 2013 was $1.3 million and $2.8 million, respectively.
Beginning on August 1, 2013, the Marlin processing agreement was terminated and the Company and another affiliate entered into an agreement whereby the Company purchased natural gas from the affiliate at the tailgate of the Marlin plant. Cost of revenues-affiliates, recorded in net asset optimization revenues in the condensed combined statements of operations for the three and six months ended June 30, 2014 related to this agreement were $9.8 million and $17.9 million, respectively. The Company also purchased natural gas at a nearby third party plant inlet which was then sold to the affiliate. Revenues-affiliates, recorded in net asset optimization revenues in the condensed combined statements of operations for the three and six months ended June 30, 2014 were related to these sales were $4.6 million and $7.1 million, respectively.
Additionally, the Company entered into a natural gas transportation agreement with Marlin, at Marlin’s pipeline, whereby the Company transports retail natural gas and pays the higher of (i) a minimum monthly payment or (ii) a transportation fee per MMBtu times actual volumes transported. The current transportation agreement was set to expire on February 28, 2013, but was extended for three additional years at a fixed rate per MMBtu without a minimum monthly payment. Included in the Company’s results are cost of revenues-affiliates, recorded in retail cost of revenues in the condensed combined statements of operations related to this activity is less than $0.1 million for both the three months ended June 30, 2014 and 2013 and less than $0.1 million for both the six months ended for June 30, 2014 and 2013.
The Company also purchases electricity for an affiliate and sells the electricity to the affiliate at the same market price that the Company paid to purchase the electricity. Sales of electricity to the affiliate were $0.7 million and $0.3 million for the three months ended June 30, 2014 and 2013, respectively, and $2.2 million and $0.5 million for the six months ended June 30, 2014 and 2013, respectively, which is recorded in retail revenues-affiliate in the condensed combined statements of operations.
Also included in the Company’s results are cost of revenues-affiliates related to derivative instruments, recorded in net asset optimization revenues in the condensed combined statements of operations, is a loss of $0.9 million and a gain of $0.5 million for the three months ended June 30, 2014 and 2013, respectively, and a loss of $0.7 million and a gain of $0.5 million for the six months ended June 30, 2014 and 2013, respectively.

20


Cost allocations
The Company paid certain expenses on behalf of affiliates, which are reimbursed by the affiliates to the Company, including costs that can be specifically identified and certain allocated overhead costs associated with general and administrative services, including executive management, facilities, banking arrangements, professional fees, insurance, information services, human resources and other support departments to the affiliates. Where costs incurred on behalf of the affiliate could not be determined by specific identification for direct billing, the costs were primarily allocated to the affiliated entities based on percentage of departmental usage, wages or headcount. The total amount direct billed and allocated to affiliates was $1.3 million and $1.9 million for the three months ended June 30, 2014 and 2013, respectively, and $3.3 million and $3.6 million for the six months ended June 30, 2014 and 2013, respectively, and is recorded as a reduction in general and administrative expenses in the condensed combined statements of operations.
The Company pays residual commissions to an affiliate for all customers enrolled by the affiliate who pay their monthly retail gas or retail electricity bill. Commission paid to the affiliate was less than $0.1 million for both the three months ended June 30, 2014 and 2013, and $0.1 million for both the six months ended June 30, 2014 and 2013, which is recorded in general and administrative expense in the condensed combined statements of operations. This agreement between SE, SEG and the affiliate was terminated in May 2014.
Member Distributions and Contributions
During the six months ended June 30, 2014 and 2013, the Company made net capital distributions to W. Keith Maxwell III of $43.5 million and $32.3 million, respectively. In contemplation of the Company’s initial public offering, the Company entered into an agreement with an affiliate in April 2014 to permanently forgive all net outstanding accounts receivable balances from the affiliate. As such, the accounts receivable balances from the affiliate have been eliminated and presented as a distribution to W. Keith Maxwell III for 2014 and 2013.

9. Segment Reporting
The Company’s determination of reportable business segments considers the strategic operating units under which the Company makes financial decisions, allocates resources and assesses performance of its retail and asset optimization businesses.
The Company’s reportable business segments are retail natural gas and retail electricity. The retail natural gas segment consists of natural gas sales to, and natural gas transportation and distribution for, residential and commercial customers. Asset optimization activities, considered an integral part of securing the lowest price natural gas to serve retail gas load, are part of the retail natural gas segment. The Company recorded asset optimization revenues of $46.7 million and $179.6 million and asset optimization cost of revenues of $46.5 million and $177.8 million for the three and six months ended June 30, 2014, respectively, and recorded asset optimization revenues of $69.2 million and $160.5 million and asset optimization cost of revenues of $71.0 million and $163.4 million for the three and six months ended June 30, 2013, respectively, which are presented on a net basis in asset optimization revenues. The retail electricity segment consists of electricity sales and transmission to residential and commercial customers. Corporate and other consists of expenses and assets of the retail natural gas and retail electricity segments that are managed at a consolidated level such as general and administrative expenses.
To assess the performance of the Company’s operating segments, the chief operating decision maker analyzes retail gross margin. The Company defines retail gross margin as operating income plus (i) depreciation and amortization expenses and (ii) general and administrative expenses, less (i) net asset optimization revenues, (ii) net gains (losses) on derivative instruments, and (iii) net current period cash settlements on derivative instruments. The Company deducts net gains (losses) on derivative instruments, excluding current period cash settlements, from the retail gross margin calculation in order to remove the non-cash impact of net gains and losses on derivative instruments.
Retail gross margin is a primary performance measure used by our management to determine the performance of our retail natural gas and electricity business by removing the impacts of our asset optimization activities and net

21


non-cash income (loss) impact of our economic hedging activities. As an indicator of our retail energy business’ operating performance, retail gross margin should not be considered an alternative to, or more meaningful than, operating income, as determined in accordance with GAAP. Below is a reconciliation of retail gross margin to income before income tax expense. 
  
Three Months Ended June 30,

Six Months Ended June 30,
  
2014

2013

2014

2013
Reconciliation of Retail Gross Margin to Income before taxes







Income before income tax expense
$
333


$
(931
)

$
6,873


$
13,694

Interest and other income
(1
)

(1
)

(71
)

(12
)
Interest expense
222


286


535


670

Operating Income
554


(646
)

7,337


14,352

Depreciation and amortization
3,252


4,284


6,211


9,314

General and administrative
9,747


9,437


17,860


18,712

Less:







Net asset optimization revenue
197


(1,782
)

1,821


(2,939
)
Net, Gains (losses) on derivative instruments
(4,438
)

(2,761
)

7,010


(2,187
)
Net, Cash settlements on derivative instruments
(97
)

602


(12,998
)

(1,304
)
Retail Gross Margin
$
17,891


$
17,016


$
35,575


$
48,808


The Company uses gross margin and net asset optimization revenues as the measure of profit or loss for its business segments. This measure represents the lowest level of information that is provided to the chief operating decision maker for our reportable segments.

Financial data for business segments are as follows (in thousands): 
Three Months Ended June 30, 2014
Retail
Electricity
 
Retail
Natural Gas
 
Corporate
and Other
 
Eliminations
 
Spark Retail
Total Revenues
$
42,771

 
$
23,169

 
$

 
$

 
$
65,940

Retail cost of revenues
35,753

 
16,634

 

 

 
52,387

Less:
 
 
 
 
 
 
 
 
 
Net asset optimization revenues

 
197

 

 

 
197

Gains (losses) on retail derivative instruments
(4,297
)
 
(141
)
 

 

 
(4,438
)
Current period settlements on non-trading derivatives
542

 
(639
)
 

 

 
(97
)
Retail gross margin
$
10,773

 
$
7,118

 
$

 
$

 
$
17,891

Total Assets
$
38,606

 
$
79,570

 
$
1,623

 
$
(33,341
)
 
$
86,458

 

22


Three Months Ended June 30, 2013
Retail
Electricity

Retail
Natural Gas

Corporate
and Other

Eliminations

Spark Retail
Total revenues
$
46,913


$
18,568


$


$


$
65,481

Retail cost of revenues
37,516


14,890






52,406

Less:









Net asset optimization revenues


(1,782
)





(1,782
)
Gains (losses) on retail derivative instruments
(2,270
)

(491
)





(2,761
)
Current period settlements on non-trading derivatives
823


(221
)





602

Retail gross margin
$
10,844


$
6,172


$


$


$
17,016

Total Assets
$
42,408


$
83,182


$
1,094


$
(25,733
)

$
100,951

Six Months Ended June 30, 2014
Retail
Electricity

Retail
Natural Gas

Corporate
and Other

Eliminations

Spark Retail
Total Revenues
$
86,219


$
85,697


$


$


$
171,916

Retail cost of revenues
73,370


67,138






140,508

Less:









Net asset optimization revenues


1,821






1,821

Gains (losses) on retail derivative instruments
5,596


1,414






7,010

Current period settlements on non-trading derivatives
(10,496
)

(2,502
)





(12,998
)
Retail gross margin
$
17,749


$
17,826


$


$


$
35,575

Total Assets
$
38,606


$
79,570


$
1,623


$
(33,341
)

$
86,458

Six Months Ended June 30, 2013
Retail
Electricity

Retail
Natural Gas

Corporate
and Other

Eliminations

Spark Retail
Total Revenues
$
94,352


$
70,425


$


$


$
164,777

Retail cost of revenues
71,973


50,426






122,399

Less:









Net asset optimization revenues


(2,939
)





(2,939
)
Gains (losses) on retail derivative instruments
766


(2,953
)





(2,187
)
Current period settlements on non-trading derivatives
(1,130
)

(174
)





(1,304
)
Retail gross margin
$
22,743


$
26,065


$


$


$
48,808

Total Assets
$
42,408


$
83,182


$
1,094


$
(25,733
)

$
100,951

Significant Customers
For the three months ended June 30, 2014, we had four significant customers that individually accounted for more than 10% of the Company’s combined net asset optimization revenues. For the six months ended June 30, 2014, we had one significant customer that individually accounted for more than 10% of the Company’s combined net asset optimization revenues.
Significant Suppliers
For the three months ended June 30, 2014, we had three significant suppliers that individually accounted for more than 10% of the Company’s combined net asset optimization revenues cost of revenues. For the six months ended June 30, 2014, we had two significant suppliers that individually accounted for more than 10% of the Company’s combined net asset optimization revenues cost of revenues.

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For the three and six months ended June 30, 2014 the Company had one significant supplier that individually accounted for more than 10% of the Company’s combined retail electricity retail cost of revenues.
10. Subsequent Events

On August 1, 2014, the Company closed the Offering of 3,000,000 shares of its Class A common stock. See Note 1.
Subsequent to June 30, 2014 and prior to the Offering, the Company made net capital distributions to W. Keith Maxwell III of $0.4 million.
In July 2014, prior to the Offering, we incurred short-term borrowings from one of the Company's affiliates in the amount of $5.5 million to fund certain of our operating expenses incurred in the ordinary course, which amounts have been permanently forgiven by the affiliate and recorded as a capital contribution in connection with the closing of the Offering.
The Borrowers repaid the Seventh Amended Credit Agreement in connection with the Offering. The Company and its subsidiaries have entered into a new $70.0 million Senior Credit Facility with an initial outstanding balance of $10 million in loans and $15 million in letters of credit. See further discussion in Note 1 and 4.
In connection with the Offering the Company adopted the Spark Energy, Inc. Long-Term Incentive Plan (the “LTIP”) for the employees, consultants and the directors of the Company and its affiliates who perform services for the Company. The purpose of the LTIP is to provide a means to attract and retain individuals to serve as directors, employees and consultants who provide services to the Company by affording such individuals a means to acquire and maintain ownership of awards, the value of which is tied to the performance of the Company's Class A common stock. In connection with the Offering, the Company granted restricted stock units to our non-employee directors and certain of our officers, employees and employees of certain of our affiliates who perform services for us. The initial restricted stock unit awards generally vest ratably over three or four years commencing on May 4, 2015 and will include tandem dividend equivalent rights which vest upon the same schedule as the underlying restricted stock unit.


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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the unaudited condensed combined financial statements and the related notes thereto included elsewhere in this report and the audited combined financial statements and notes thereto and management's discussion and analysis of financial condition and results of operations as of and for the year ended December 31, 2013 and 2012 included in the prospectus relating to our initial public offering (the "Prospectus") that was filed with the Securities and Exchange Commission ("SEC") on July 30, 2014. In this report, the terms “Spark Energy,” “Company,” “we,” “us” and “our” refer collectively to (i) the combined business and assets of the retail natural gas business and asset optimization activities of Spark Energy Gas, LLC and the retail electricity business of Spark Energy, LLC before the completion of our corporate reorganization in connection with the initial public offering of Spark Energy, Inc., which closed on August 1, 2014 (the “Offering”) and (ii) Spark Energy, Inc. and its subsidiaries as of the completion of our corporate reorganization and thereafter.
This report contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. These statements can be identified by the use of forward-looking terminology including “may,” “should,” “likely,” “will,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” “plan,” “intend,” “projects,” or other similar words. All statements, other than statements of historical fact included in this report, regarding strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. Forward-looking statements appear in a number of places in this report and may include statements about business strategy and prospects for growth, customer acquisition costs, ability to pay cash dividends, cash flow generation and liquidity, availability of terms of capital, competition and government regulation and general economic conditions. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we cannot give any assurance that such expectations will prove correct.
The forward-looking statements in this report are subject to risks and uncertainties. Important factors which could cause actual results to materially differ from those projected in the forward-looking statements include, but are not limited to:
changes in commodity prices,
extreme and unpredictable weather conditions,
the sufficiency of risk management and hedging policies,
customer concentration,
federal, state and local regulation,
key license retention,
increased regulatory scrutiny and compliance costs,
our ability to borrow funds and access credit markets,
restrictions in our debt agreements and collateral requirements,
credit risk with respect to suppliers and customers,
level of indebtedness,
changes in costs to acquire customers,
actual customer attrition rates,
accuracy of internal billing systems,
competition, and
other factors discussed below and in “Risk Factors” in our Prospectus.

You should review the risk factors and other factors noted throughout or incorporated by reference in this report which could cause our actual results to differ materially from those contained in any forward-looking statement.
All forward-looking statements speak only as of the date of this report. Unless required by law, we disclaim any obligation to publicly update or revise these statements whether as a result of new information, future events or otherwise. It is not possible for us to predict all risks, nor can we assess the impact of all factors on the business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements.

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Overview

We are a growing independent retail energy services company founded in 1999 that provides residential and commercial customers in competitive markets across the United States with an alternative choice for their natural gas and electricity. We purchase our natural gas and electricity supply from a variety of wholesale providers and bill our customers monthly for the delivery of natural gas and electricity based on their consumption at either a fixed or variable-price. Natural gas and electricity are then distributed to our customers by local regulated utility companies through their existing infrastructure.

As of June 30, 2014, we operated in 46 utility service territories across 16 states and had over 390,500 residential customer equivalents (“RCEs”). An RCE is an industry standard measure of natural gas or electricity usage with each RCE representing annual consumption of 100 MMbtu of natural gas or 10 MWh of electricity.

We operate these businesses in two operating segments:

Retail Natural Gas Segment. We purchase natural gas supply through physical and financial transactions with market counterparts and supply natural gas to residential and commercial consumers pursuant to fixed-price, variable-price and flat-rate contracts. For the six months ended June 30, 2014, approximately 50% of our retail revenues were derived from the sale of natural gas. We also identify wholesale natural gas arbitrage opportunities in conjunction with our retail procurement and hedging activities, which we refer to as asset optimization. These opportunities can include (i) optimizing the unused portion of storage and transportation assets that are allocated to us by the local regulated utility to support our retail load; (ii) capturing physical arbitrage opportunities using short or long-term transportation capacity; and (iii) maximizing our credit capacity by purchasing gas from affiliates and third parties and selling it at the same location to counterparties for whom we normally purchase retail supply.

Retail Electricity Segment. We purchase electricity supply through physical and financial transactions with market counterparts and ISOs and supply electricity to residential and commercial consumers pursuant to fixed-price and variable-price contracts. For the six months ended June 30, 2014, approximately 50% of our retail revenues were derived from the sale of electricity. 
Spark Energy, Inc.

Spark Energy, Inc. was formed in April 2014 and does not have any historical financial operating results for the quarterly periods covered by this report. The following discussion analyzes our historical combined financial condition and results of operations, which is the combined businesses and assets of the retail natural gas business and asset optimization activities of Spark Energy Gas, LLC ("SEG") and the retail electricity business of Spark Energy, LLC ("SE"). SE and SEG are the operating subsidiaries through which we have historically operated our retail energy business and were commonly controlled by NuDevco Partners, LLC prior to the Offering.

On August 1, 2014, we completed an initial public offering of 3,000,000 shares of our Class A common stock at a price of $18.00 per share less underwriting discounts and commissions and structuring fees of $1.26 per share for net proceeds, before expenses, of $50.2 million (the "Offering"). We used the net proceeds of the Offering to purchase 2,997,222 limited liability company units of Spark HoldCo, LLC (“Spark HoldCo”) and to repay a $50,000 note payable (the “NuDevco Note”) to NuDevco Retail Holdings, LLC (“Nudevco Retail Holdings”). The 2,997,222 Spark Holdco units we purchased with the proceeds from the Offering, together with the 2,778 Spark HoldCo units we purchased in exchange for the NuDevco Note prior to the Offering, represent a 21.82% ownership interest in Spark HoldCo. NuDevco Retail Holdings and its subsidiary, NuDevco Retail, LLC (“NuDevco Retail” and together with NuDevco Retail Holdings, “NuDevco”) hold the remaining 78.18% of the Spark HoldCo Units. For a more complete description of the transactions we and our affiliates undertook as part of the reorganization and the Offering, see “Corporate Reorganization” in our Prospectus.


26


Subsequent to the Offering, Spark Energy, Inc. is a holding company whose sole material assets consist of 3,000,000 Spark HoldCo units and the managing membership interest in Spark Holdco. Spark HoldCo, LLC owns 100% of SE and SEG, our operating subsidiaries. As the managing member of Spark HoldCo, Spark Energy, Inc. is responsible for all operational, management and administrative decisions relating to Spark HoldCo’s business and consolidates the financial results of Spark HoldCo and its subsidiaries.

Factors Affecting Our Results of Operations

Our Ability to Grow Our Business. Customer growth is a key driver of our operations. We attempt to grow our customer base by offering customers competitive pricing, price certainty or green product offerings. We manage growth on a market-by-market basis by developing price curves in each of the markets we serve and comparing the market prices to the price the local regulated utility is offering. We then determine if there is an opportunity in a particular market based on our ability to create a competitive product on economic terms that satisfies our profitability objectives. We develop marketing campaigns using a combination of sales channels, with an emphasis on door-to-door marketing and outbound telemarketing given their flexibility and historical effectiveness. We identify and acquire customers through a variety of additional sales channels, including our inbound customer care call center, online marketing, email, direct mail, affinity programs, direct sales, brokers and consultants. Our marketing team continuously evaluates the effectiveness of each customer acquisition channel and makes adjustments in order to achieve desired growth and profitability targets.

A key component in our ability to grow our business is management of customer acquisition costs. We attempt to maintain a disciplined approach to recovery of our customer acquisition costs within defined periods which we capitalize and amortize over a two year period. We factor in the recovery of customer acquisition costs in determining which markets we enter and the pricing of our products in those markets. While the time required to achieve payback relative to the costs we expend to acquire new customers varies based upon contract terms and prevailing market conditions, we generally recover the customer acquisition cost over a twelve month period. Accordingly, our results of operations are significantly influenced by our customer acquisition spending. For example, increased customer acquisition spending in 2011 was a factor that led to increased profitability in 2012. Our 2013 results were negatively impacted by our strategic initiative in 2012 to reduce customer acquisition spending and to optimize our customer base, following a determination by our owner to invest excess cash flows from our retail operations in other affiliated businesses. Since the third quarter of 2013, we have significantly increased our customer acquisition spending and we have continued these expenditure levels in 2014.

Our Ability to Manage Customer Attrition. Customer attrition is primarily due to: (i) customer initiated switches; (ii) residential moves and (iii) customer payment defaults. We evaluate our customers and offer products and pricing to manage our attrition rates and maximize customer lifetime value. Our rate of attrition in the first half of 2014 has increased primarily due to the high early tenure attrition in the Southwest Region (California, Texas, Nevada, Arizona and Colorado) gas market where, in California, we are offering flat and fixed rate gas products in a largely unpenetrated and non-competitive market. See " - Combined Results of Operations" for a more detailed discussion of our attrition rates for the periods covered by this report.

Market Regulation and Oversight. We operate in the highly regulated natural gas and electricity retail sales industry. Regulations may be revised or reinterpreted or new laws and regulations may be adopted or become applicable to us or our operations. Such changes may have a detrimental impact on our business either by making it more costly to operate in that state or by forcing us to shift our focus to other states.

Weather Conditions. Weather conditions directly influence the demand for natural gas and electricity and affect the prices of energy commodities. Our hedging strategy is based on forecasted customer energy usage, which can vary substantially as a result of weather patterns deviating from historical norms. We are particularly sensitive to this variability because of our current substantial concentration and focus on growth in the residential customer segment in which energy usage is highly sensitive to weather conditions that impact heating and cooling demand. The extreme weather patterns during the 2013 and 2014 winter season caused commodity demand and prices to rise significantly beyond industry forecasts. As a result, the retail energy industry generally charged higher prices to its

27


variable-price customers and was subject to decreased margins on fixed-price contracts due to unanticipated increases in volumetric demand that had to be purchased in the spot market at high prices.

Commodity Price Risk and Effectiveness of our Risk Management Program. We hedge and procure our energy requirements from various wholesale energy markets, including both physical and financial markets, through short-term and long-term contracts. Our financial results are largely dependent on the difference between prices at which we purchase and resell natural gas and electricity. We actively manage our commodity price risk. Our commodity risk management strategy is designed to hedge substantially all of our forecasted natural gas and electricity volumes on our fixed-price customer contracts as well as a portion of the near-term volumes on our variable-price customer contracts. We are required to deliver our wholesale energy at various utility load zones for electricity and various city gates for natural gas. We manage our exposure to short-term and long-term movements in wholesale energy prices by hedging using a variety of derivative instruments. Our hedging strategy is based on a number of variables and estimates, including weather patterns, changes in commodity prices, assumptions regarding attrition and changes in weather-related volumetric demand, which may result in losses or gains of unhedged volumes if our estimates and assumptions prove incorrect. If the market price of natural gas or electricity increases or decreases from the original hedge price, we may realize a corresponding loss or gain.

We are exposed to basis risk in our operations when the commodities we hedge are sold at different delivery points from the exposure we are seeking to hedge. For example, if we hedge our natural gas commodity price with Chicago basis but physical supply must be delivered to the individual delivery points of specific utility systems around the Chicago metropolitan area, we are exposed to basis risk between the Chicago basis and the individual utility system delivery points. These differences can be significant from time to time, particularly during extreme, unforecasted cold weather conditions. Similarly, in certain of our electricity markets, customers pay the load zone price for electricity, so if we purchase supply to be delivered at a hub, we may have basis risk between the hub and the load zone electricity prices due to local congestion that is not reflected in the hub price. We attempt to hedge basis risk where possible, but hedging instruments are sometimes not economically feasible or available in the smaller quantities that we require.

Because natural gas accounts for a significant portion of our retail revenues and is a key component of the wholesale price of electricity, our operating results are heavily impacted by price movements in natural gas. Price volatility in the natural gas market generally exceeds volatility in most energy and other commodity markets. Changes in market prices for natural gas and electricity may result from many factors that are outside of our control. Please see “Risk Factors—Risks Related to Our Business—We are subject to commodity price risk” in our Prospectus.

We incur monthly ancillary service charges and capacity costs in the electricity sector. We attempt to estimate such amounts but they are difficult to estimate because they are charged in arrears by the independent system operators ("ISOs") and are subject to fluctuations based on weather and other market conditions. Many of the utilities we serve also allocate natural gas transportation and storage assets to us as a part of their competitive choice program. We are required to fill our allocated storage capacity with natural gas, which creates commodity supply and price risk. Sometimes we cannot hedge the volumes associated with these assets because they are too small compared to the much larger bulk transaction volumes required for trades in the wholesale market or because it is not economically feasible to do so.

In addition to our supply costs, we incur costs such as renewable energy credits ("RECs"), ancillary services charges, ISO fees and, in some markets, transmission costs, which we estimate and incorporate into the pricing of our offered contracts. To the extent our estimates are incorrect, we may incur costs that we are unable to pass along to our customers.

Seasonality. Our overall operating results fluctuate substantially on a seasonal basis depending on: (i) the geographic mix of our customer base; (ii) the relative concentration of our commodity mix; (iii) weather conditions, which directly influence the demand for natural gas and electricity and affect the prices of energy commodities; and (iv) variability in market prices for natural gas and electricity. These factors can have material short-term impacts

28


on monthly and quarterly operating results, which may be misleading when considered outside of the context of our annual operating cycle.

Our accounts payable and accounts receivable are impacted by seasonality due to the timing differences between when we pay our suppliers for accounts payable versus when we collect from our customers on accounts receivable. We typically pay our suppliers for purchases on a monthly basis. However, it takes approximately two months from the time we deliver the natural gas or electricity to our customers to the time we collect from our customers on accounts receivable attributable to those supplies. This timing difference could affect our cash flows, especially during peak cycles in the winter and summer months.

Natural gas exposes us to a high degree of seasonality in our cash flows and income earned throughout the year as a result of the high concentration of heating load in the winter months. We utilize a considerable amount of cash from operations and borrowing capacity to fund working capital, which includes inventory purchases from April through October each year. We sell our natural gas inventory during the months of November through March of each year. We expect that the significant seasonality impacts to our cash flows and income will continue in future periods. For example, we generated approximately 39% and 28% of our annual Retail Gross Margin in the first and fourth quarter of the year ended December 31, 2013. As a result, we intend to reserve a portion of our excess cash available for distribution in the first and fourth quarters in order to fund our second and third quarter dividends.
Electricity consumption is typically highest during the summer months due to cooling demand, however this increase in volumes does not typically impact our overall profitability as the cost of electricity typically also increases in the summer months.

Asset Optimization and Certain Long-term Contracts. We contract for term transportation capacity in connection with our asset optimization activities which obligates us to pay demand charges to the relevant counterparty. For 2014, we are obligated to pay demand charges for certain transportation assets of approximately $2.6 million. Although these demand payments will decrease over time, the related capacity agreements extend through 2028. Prior to 2013, we entered into several hedging transactions associated with this capacity. As a result of weather-related pipeline transportation constraints, our hedging strategy for the winter of 2012 through 2013 on one of those transactions involving interruptible transportation resulted in losses that were recognized in late 2012 and 2013. We have since revised our risk policies such that this business is limited to back-to-back purchase and sale transactions, or open positions subject to our aggregate net open position limits, which are not held for a period longer than two months. Further, all additional capacity procured outside of a utility allocation of retail assets must be approved by our risk committee, hedges on our firm transportation obligations are limited to two years or less and hedging of interruptible capacity is prohibited.

Asset optimization opportunities primarily arise during the winter heating season when demand for natural gas is the highest. As such, we expect the majority of our asset optimization profits to be made in the winter. Given the opportunistic nature of these activities we will experience variability in our earnings from our asset optimization activities from year to year. As these activities are accounted for using mark-to-market accounting, the timing of our revenue recognition may differ from the actual cash settlement.

Retail Contract Types. We offer both fixed-price contracts and variable-price contracts, which we believe enables us to increase overall customer lifetime value. Fixed-price contracts provide consumers with price protection against increases in natural gas and electricity prices with terms of up to three years. Incorporated into the calculation of our fixed prices are also prevailing billing charges, switching fees, volumetric conversion rates and other charges. Though we are advised in advance of future changes in these items through tariff filings and notices by the local regulated utility, changes in these charges, fees, rates and other charges could occur before the termination date of our current fixed-price contracts. We cannot pass through those additional costs to customers on fixed-price contracts, which would negatively impact projected margins on those contracts. With respect to our variable-price contracts, we are generally able to pass through increased costs; however customers may terminate these contracts at any time if they are not satisfied with the current rate being charged. In addition, we may decide not to pass through the entire cost of significant commodity price increases in a given monthly period to avoid excessive customer complaints and attrition.

29



Timing of Hedge Settlements. In addition to the volatility described above, we could incur volatility from quarter-to-quarter associated with gains and losses on settled hedges relating to natural gas held in inventory if we choose to hedge the summer-winter spread on our retail allocated storage capacity. Inventory is typically purchased and stored from April to October and withdrawn from storage from November through March. Since a portion of the inventory is used to satisfy delivery obligations to our fixed-price customers over the winter months, we hedge the associated price risk using a combination of NYMEX and basis derivative contracts. Any gains or losses associated with settled derivative contracts are reflected in the statement of operations for the period in which the contract settles as a component of cost of revenues.

Customer Credit Risk. In many of the utility services territories where we conduct business, POR programs have been established, whereby the local regulated utility offers services for billing the customer, collecting payment from the customer and remitting payment to us. This service results in substantially all of our credit risk being linked to the applicable utility and not to our end-use customer in these territories. Approximately 45% and 47% of our retail revenues were derived from territories in which substantially all of our credit risk was directly linked to local regulated utility companies as of June 30, 2014 and December 31, 2013, respectively, all of which had investment grade ratings as of such date. During the same periods, we paid these local regulated utilities a weighted average discount of approximately 1.0% of total revenues for customer credit risk. In certain of the POR markets in which we operate, the utilities limit their collections exposure by retaining the ability to transfer a delinquent account back to us for collection when collections are past due for a specified period. If our collection efforts are unsuccessful, we return the account to the local regulated utility for termination of service. Under these service programs, we are exposed to credit risk related to payment for services rendered during the time between when the customer is transferred to us by the local regulated utility and the time we return the customer to the utility for termination of service, which is generally one to two billing periods. We may also realize a loss on fixed-price customers in this scenario due to the fact that we will have already fully hedged the customer’s expected commodity usage for the life of the contract. We recorded accounts receivable from POR markets of $14.5 million and $22.1 million in accounts receivable on the combined balance sheets as of June 30, 2014 and December 31, 2013, respectively.

In non-POR markets (and in POR markets where we may choose to direct bill our customers), we manage customer credit risk through formal credit review, in the case of commercial customers, and credit screening, deposits and disconnection for non-payment, in the case of residential customers. Our bad debt expense for the six months ending June 30, 2014 and 2013 was approximately 2.0% and 1.0% of non-POR market retail revenues. Economic conditions may affect our and our customers’ ability to pay bills in a timely manner, which could increase customer delinquencies and may lead to an increase in bad debt expense. We also believe that bad debt expense could be negatively impacted in connection with our focus on customer acquisition in the Southwest Region gas market, which is non-POR. In addition, our ability to manage customer credit risk in the Southwest Region gas market is primarily through disconnection.

Factors Affecting Comparability of Historical Financial Results

Tax Receivable Agreement. The Tax Receivable Agreement between us and NuDevco Retail Holdings, LLC, NuDevco Retail, LLC and Spark HoldCo provides for the payment by Spark Energy, Inc. to NuDevco Retail Holdings of 85% of the net cash savings, if any, in U.S. federal, state and local income tax or franchise tax that Spark Energy, Inc. actually realizes (or is deemed to realize in certain circumstances) in periods after the Offering as a result of (i) any tax basis increases resulting from the purchase by Spark Energy, Inc. of Spark HoldCo units from NuDevco Retail Holdings prior to or in connection with the Offering, (ii) any tax basis increases resulting from the exchange of Spark HoldCo units for shares of Class A common stock pursuant to the exchange right set forth in the limited liability company agreement of Spark HoldCo (or resulting from an exchange of Spark HoldCo units for cash pursuant to the Cash Option) and (iii) any imputed interest deemed to be paid by us as a result of, and additional tax basis arising from, any payments we make under the Tax Receivable Agreement. In addition, payments we make under the Tax Receivable Agreement will be increased by any interest accrued from the due date (without extensions) of the corresponding tax return. We will record 85% of the estimated tax benefit as an increase

30


to amounts payable under the Tax Receivable Agreement as a liability. We will retain the benefit of the remaining 15% of these tax savings.

Executive Compensation Programs. Subsequent to the Offering, we granted restricted stock units to our non-employee directors, and certain of our officers, employees and employees of certain of our affiliates who perform services for us under our long-term incentive plan. The initial restricted stock unit awards will generally vest ratably over three or four years commencing May 4, 2015 and will include tandem dividend equivalent rights that will vest upon the same schedule as the underlying restricted stock unit.

Financing. The total amounts outstanding under our Seventh Amended Credit Agreement as of December 31, 2013 and June 30, 2014, include amounts used to fund equity distributions to our common control owner to fund operations of an affiliated company. As such, historical borrowings under our Seventh Amended Credit Agreement may not provide an accurate indication of what we need to operate our natural gas and electricity business. Concurrently with the closing of the Offering, the Company entered into a new $70.0 million Senior Credit Facility. The Company borrowed approximately $10.0 million under its new Senior Credit Facility at the closing of the Offering to repay in full the portion of outstanding indebtedness under the Seventh Amended Credit Agreement that SEG and SE agreed to be responsible for pursuant to an interborrower agreement between SEG, SE and an affiliate. The remainder of indebtedness outstanding under the Seventh Amended Credit Agreement was paid down by our affiliate with its own funds concurrently at the closing of the Offering pursuant to the terms of the interborrower agreement. Following this repayment, the Seventh Amended Credit Agreement was terminated.

Combined Results of Operations

Our results of operations are significantly influenced by our customer acquisition spending, although the impact of increasing or reducing our customer counts on our results of operations may not occur until several months after the shift in strategy. While the time required to recoup the cost we expend to acquire new customers varies based upon contract terms and prevailing market conditions, we typically recover our customer acquisition costs within twelve months. In addition, we generally begin to recognize margin improvements from new customer acquisitions six to twelve months after the customer acquisition cost has been incurred. Similarly, the negative impact on our results of operations of a shift in strategy to decrease customer acquisitions will occur over time as natural customer attrition occurs.

In 2011, we invested approximately $24 million in growing and maintaining our customer base. The expansion was successful in expanding our customer base by approximately 63% or 123,000 customers, net of attrition, in 2011. In 2012, our owner made the determination to invest excess cash flows from our operations in other affiliated businesses. As a result, we significantly reduced our customer acquisition costs, including completely discontinuing some marketing channels, and focused our efforts on integrating and optimizing our existing expanded customer base. In addition, we took steps to decrease our general and administrative expenses through implementation of system improvements and reduced head count to create a more efficient scalable platform.

In 2013, we evaluated our customer base through segmentation and optimization strategies which resulted in reduced customer count as certain underperforming segments experienced higher attrition levels. This segmentation and corresponding customer attrition, coupled with a decreased focus on lower margin commercial customers in 2013, resulted in lower overall sales volumes and Adjusted EBITDA in our retail segments in 2013, but increased gross margin per unit sold.

Recognizing the growth opportunities in the retail energy space, beginning in the second quarter of 2013, we increased our customer acquisition spending and reactivated certain marketing channels. By the end of 2013, we had grown the customer base by 8% from the low point in August of 2013. This growth trajectory has increased through the second quarter of 2014 resulting in an increase of approximately 33% in our customer base as of June 30, 2014 from August of 2013.


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We accelerated our customer growth in the second quarter of 2014 to take advantage of the market opportunity to acquire carbon neutral gas customers in California. During the second quarter, we spent $6.4 million on customer acquisition costs, of which $3.6 million was attributable to new gas customers in the Southwest Region. Our average cost per customer was approximately $96, which is comparable to customer acquisitions made since we relaunched our marketing efforts in the second half of 2013. Consistent with our historical experience, we anticipate seeing the results of this increased investment reflected in gross margins six to twelve months from the acquisition date of each customer. This increased customer acquisition spending reduced Adjusted EBITDA as compared to the same period in 2013, where only $0.6 million was spent on customer acquisition.

Our average monthly customer attrition rate in the second quarter was 5.1% which reflects an increase from 4.1% in the prior quarter. We attribute this increase to: (i) early tenure attrition (which typically occurs when customers switch back to the utility shortly after signing on with the competitive retail provider) associated with the success of our California gas customer acquisition campaigns, and (ii) increased attrition in the Northeast following last winter’s extreme weather patterns and associated high bills.   

Management believes that the high early tenure attrition in the California gas market is the result of confusion and lack of awareness by consumers in an early stage competitive market and the fact that there are very few competitive gas retailers in the market. We also believe that this high level of early tenure attrition is not unusual given the nascency of this market. We are currently working with our vendors in this market to better educate consumers at the time of the sale in order to lower early tenure attrition, as well as lowering the overall cost to acquire these customers.

The retail energy industry suffered higher supply costs in the first quarter of 2014 due to capacity constraints resulting from the extreme weather conditions in the Northeast in that period. These increases are reflected in our retail cost of revenues for both the first quarter of 2014 and for the six month period ended June 30, 2014.


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Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013

In Thousands
Three Months Ended June 30,



2014
 
2013
 
Change
Revenues:

 

 

Retail revenues
$65,743
 
$67,263
 
$(1,520)
Net asset optimization revenues
197

 
(1,782
)
 
1,979

Total Revenues
65,940

 
65,481

 
459

Operating Expenses:


 


 


Retail cost of revenues
52,387

 
52,406

 
(19
)
General and administrative
9,747

 
9,437

 
310

Depreciation and amortization
3,252

 
4,284

 
(1,032
)
Total Operating Expenses
65,386

 
66,127

 
(741
)
Operating income
554

 
(646
)
 
1,200

Other (expense)/income:


 


 


Interest expense
(222
)
 
(286
)
 
64

Interest and other income
1

 
1

 

Total other (expenses)/income
(221
)
 
(285
)
 
64

Income before income tax expense
333

 
(931
)
 
1,264

Income tax expense
132

 
14

 
118

Net income (loss)
$201
 
$(945)
 
$1,146
Adjusted EBITDA
$1,444
 
$5,216
 
$(3,772)
Retail Gross Margin
17,891

 
17,016

 
875

Customer Acquisition Costs
6,441

 
646

 
5,795

Customer Attrition
5.1%

 
3.9%

 
1.2%


Total Revenues. Total revenues for the three months ended June 30, 2014 were approximately $65.9 million, an increase of approximately $0.4 million, or 1%, from approximately $65.5 million for the three months ended June 30, 2013. This increase was primarily due to increased customer pricing that we implemented to capture a portion of increased supply costs, which resulted in an increase in total revenues of $8.6 million, as well as a $2.0 million increase in net asset optimization revenues. This increase was offset by a decrease of $10.2 million due to customer sales volumes which were lower, primarily due to the strategic shift of the concentration of our marketing efforts from commercial customers to residential customers.

Net Asset Optimization Revenues. Net asset optimization revenues for the three months ended June 30, 2014 were approximately $0.2 million, an increase of approximately $2.0 million, or 111%, from $(1.8) million in the same period in the prior year. In 2014, winter price volatility created physical gas arbitrage opportunities, which exceeded the demand charges from our transportation assets and were not present in 2013.

Retail Cost of Revenues. Total retail cost of revenues for the three months ended June 30, 2014 was approximately $52.4 million, which is consistent with the approximate $52.4 million for the three months ended June 30, 2013. Customer sales volumes for the second quarter of 2014 were lower, primarily due to the strategic shift of the concentration from commercial customers to residential customers, which resulted in a decrease of total retail cost of revenues of $7.8 million. This decrease was offset by an increase of $5.4 million due to increased supply costs, reflecting the higher wholesale price environment for natural gas and electricity as well as an increase of $2.4 million due to increased net losses on retail derivative instruments, net of cash settlements.


33


Depreciation and Amortization Expense. Depreciation and amortization expense for the three months ended June 30, 2014 was approximately $3.3 million, a decrease of approximately $1.0 million, or 23%, from approximately $4.3 million for the three months ended June 30, 2013. This decrease was primarily due to the depreciation of certain software assets that were fully depreciated in 2013.

Customer Acquisition Cost. Customer acquisition cost for the three months ended June 30, 2014 was approximately $6.4 million, an increase of approximately $5.8 million from approximately $0.6 million for the three months ended June 30, 2013. This increase was primarily due to our increased marketing efforts to grow our customer base, primarily in the Southwest Region gas market, where we spent $3.6 million. Our average cost per customer was approximately $96, which is comparable to customer acquisitions made since we relaunched our marketing efforts in the second half of 2013.

Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013

In Thousands
Six Months Ended June 30,
 


2014
 
2013
 
Change
Revenues:


 

 

Retail revenues
$170,095
 
$167,716
 
$2,379
Net asset optimization revenues
1,821

 
(2,939
)
 
4,760

Total Revenues
171,916

 
164,777

 
7,139

Operating Expenses:


 


 


Retail cost of revenues
140,508

 
122,399

 
18,109

General and administrative
17,860

 
18,712

 
(852
)
Depreciation and amortization
6,211

 
9,314

 
(3,103
)
Total Operating Expenses
164,579

 
150,425

 
14,154

Operating income
7,337

 
14,352

 
(7,015
)
Other (expense)/income:


 


 


Interest expense
(535
)
 
(670
)
 
135

Interest and other income
71

 
12

 
59

Total other (expenses)/income
(464
)
 
(658
)
 
194

Income before income tax expense
6,873

 
13,694

 
(6,821
)
Income tax expense
164

 
28

 
136

Net income
$6,709
 
$13,666
 
$(6,957)
Adjusted EBITDA
$10,767
 
$24,263
 
$(13,496)
Retail Gross Margin
35,575

 
48,808

 
(13,233
)
Customer Acquisition Costs
11,668

 
866

 
10,802

Customer Attrition
4.6%

 
3.9%

 
0.7%


Total Revenues. Total revenues for the six months ended June 30, 2014 were approximately $171.9 million, an increase of approximately $7.1 million, or 4%, from approximately $164.8 million for the six months ended June 30, 2013. This increase was primarily due to increased customer pricing that we implemented to capture a portion of increased supply costs, which resulted in an increase in total revenues of $24.9 million, as well as a $4.8 million increase in net asset optimization revenues. This increase was offset by a decrease of $22.6 million due to customer sales volumes which were lower, primarily due to the strategic shift of the concentration of our marketing efforts from commercial customers to residential customers.

Net Asset Optimization Revenues. Net asset optimization revenues for the six months ended June 30, 2014 were approximately $1.8 million, an increase of approximately $4.7 million, or 162%, from $(2.9) million in the same period in the prior year. This increase was primarily due to physical gas arbitrage opportunities in the Northeast that

34


arose due to extreme winter weather conditions in 2014 and losses we recognized in 2013 from a hedge strategy involving interruptible transportation that did not repeat in 2014.

Retail Cost of Revenues. Total retail cost of revenues for the six months ended June 30, 2014 was approximately $140.5 million, an increase of approximately $18.1 million, or 15%, from approximately $122.4 million for the six months ended June 30, 2013. This increase was primarily due to increased supply costs arising from capacity constraints from the extreme weather conditions in the Northeast during the first quarter of 2014, which resulted in an increase of total retail cost of revenues of $32.3 million, as well as an increase of $2.5 million due to increased net losses on retail derivative instruments, net of cash settlements. This increase was offset by a decrease of $16.7 million due to customer sales volumes which were lower, primarily due to the strategic shift of the concentration of our marketing efforts from commercial customers to residential customers.

General and Administrative Expense. General and administrative expense for the six months ended June 30, 2014 was approximately $17.9 million, a decrease of approximately $0.8 million, or 4%, as compared to $18.7 million for the six months ended June 30, 2013. This decrease is primarily due to slight reductions in payroll and sales and marketing expenses.

Depreciation and Amortization Expense. Depreciation and amortization expense for the six months ended June 30, 2014 was approximately $6.2 million, a decrease of approximately $3.1 million, or 33%, from approximately $9.3 million for the six months ended June 30, 2013. This decrease was primarily due to the depreciation of certain software assets that were fully depreciated in 2013.

Customer Acquisition Cost. Customer acquisition cost for the six months ended June 30, 2014 was approximately $11.7 million, an increase of approximately $10.8 million from approximately $0.9 million for the six months ended June 30, 2013. This increase was due to our increased marketing efforts to grow our customer base beginning in the second half of 2013 and continuing during 2014 primarily in the Southwest Region gas market, where we spent approximately $6.1 million in the second quarter of 2014.


35


Operating Segment Results
 
  
Historical
 
Three Months
Ended June 30,
 
Six Months
Ended June 30,
  
2014
 
2013
 
2014
 
2013
 
 
 
 
 
 
 
 
 
(in millions, except per unit operating data)
Retail Natural Gas Segment
 
 
 
 
 
 
 
Total Revenues
$
23.2

 
$
18.6

 
$
85.7

 
$
70.4

Retail Cost of Revenues
16.7

 
14.9

 
67.1

 
50.4

Less: Net Asset Optimization Revenues
0.2

 
(1.8
)
 
1.8

 
(2.9
)
Less: Net Gains (Losses) on non-trading derivatives, net of cash settlements
(0.8
)
 
(0.7
)
 
(1.0
)
 
(3.2
)
Retail Gross Margin—Gas
7.1

 
6.2

 
17.8

 
26.1

Retail Gross Margin-Gas per MMBtu
2.83

 
2.28

 
1.96

 
2.69

Retail Electricity Segment
 
 
 
 
 
 
 
Total Revenues
$
42.8

 
$
46.9

 
$
86.2

 
$
94.4

Retail Cost of Revenues
35.8

 
37.5

 
73.4

 
72.0

Less: Net Gains (Losses) on non-trading derivatives, net of cash settlements
(3.8
)
 
(1.4
)
 
(4.9
)
 
(0.3
)
Retail Gross Margin—Electricity
10.8

 
10.8

 
17.7

 
22.7

Retail Gross Margin—Electricity per MWh
29.17

 
23.84

 
23.55

 
24.37


Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013
Retail Natural Gas Segment
Retail revenues for the Retail Natural Gas Segment for the three months ended June 30, 2014 were approximately $23.2 million, an increase of approximately $4.6 million, or 25%, from approximately $18.6 million for the three months ended June 30, 2013. This increase was due to increased customer pricing, which resulted in an increase in total revenues of $4.0 million, as well as an increase of $2.0 million due to net asset optimization revenues. This increase was offset by a decrease of $1.4 million due to lower customer sales volumes.
Retail cost of revenues for the Retail Natural Gas Segment for the three months ended June 30, 2014 was approximately $16.6 million, an increase of approximately $1.7 million, or 11%, from approximately $14.9 million for the three months ended June 30, 2013. This increase was due to increased supply costs, which resulted in an increase of $2.6 million, as well as an increase of $0.1 million due to increased net losses on retail derivative instruments, net of cash settlements. This increase was offset by a decrease of retail cost of revenues of $1.0 million due to lower customer sales volumes.
Retail gross margin for the Retail Natural Gas Segment for the three months ended June 30, 2014 was approximately $7.1 million, an increase of approximately $0.9 million, or 15%, from approximately $6.2 million for the three months ended June 30, 2013, as indicated in the table below (in millions).
 
Decrease in volumes sold
$
(0.4
)
Increase in unit margin per MMBtu
1.3

Increase in retail natural gas segment retail gross margin
$
0.9


36


The volumes of natural gas sold decreased from 2,702,803 MMBtu during the three months June 30, 2013 to 2,519,172 MMBtu during the three months ended June 30, 2014 due to the shift in our customer base to lower volume, higher margin residential gas users, primarily in the Southwest Region.
Retail Electricity Segment
Retail revenues for the Retail Electricity Segment for the three months ended June 30, 2014 were approximately $42.8 million, a decrease of approximately $4.1 million, or 9%, from approximately $46.9 million for the three months ended June 30, 2013. This decrease was primarily due to lower customer sales volumes, which resulted in a decrease of $8.8 million. This decrease was offset by an increase of retail revenues of $4.7 million due to increased customer pricing.
Retail cost of revenues for the Retail Electricity Segment for the three months ended June 30, 2014 was approximately $35.8 million, a decrease of approximately $1.7 million, or 5%, from approximately $37.5 million for the three months ended June 30, 2013. This decrease was primarily due to lower customer sales volumes, which resulted in a decrease in retail cost of revenues of $6.8 million. This decrease was offset by an increase of retail cost of revenues of $2.8 million due to increased commodity prices and $2.3 million due to increased net losses on retail derivative instruments, net of cash settlements.
Retail gross margin for the Retail Electricity Segment for the three months ended June 30, 2014 was approximately $10.8 million, which is consistent with the approximate $10.8 million for the three months ended June 30, 2013, as indicated in the table below (in millions). 
 
 
Decrease in volumes sold
$
(2.0
)
Increase in unit margin per MWh
2.0

Decrease in retail electricity segment retail gross margin
$

The volumes of electricity sold decreased from 454,802 MWh during the three months ended June 30, 2013 to 369,341 MWh during the three months ended June 30, 2014, primarily due to the strategic shift of the concentration of our marketing efforts from commercial to residential customers.
Six Months Ended June 30, 2014 Compared to the Six Months Ended June 30, 2013
Retail Natural Gas Segment
Retail revenues for the Retail Natural Gas Segment for the six months ended June 30, 2014 were approximately $85.7 million, an increase of approximately $15.3 million, or 22%, from approximately $70.4 million for the six months ended June 30, 2013. This increase was primarily due to increased customer pricing we implemented to capture a portion of increased supply costs from our customers, which resulted in an increase of $14.9 million, as well as an increase of $4.8 million due to net asset optimization revenue. This increase was offset by a decrease of $4.4 million due to decreased customer sales volumes.
Retail cost of revenues for the Retail Natural Gas Segment for the six months ended June 30, 2014 were approximately $67.1 million, an increase of approximately $16.7 million, or 33%, from approximately $50.4 million for the six months ended June 30, 2013. This increase was primarily due to increased supply costs resulting from the extreme weather conditions experienced across the United States, which resulted in an increase of $21.6 million. This increase was offset by a $2.9 million decrease due to decreased customer sales volumes, as well as a $2.0 million decrease due to decreased net losses on retail derivative instruments, net of cash settlements.
Retail gross margin for the Retail Natural Gas Segment for the six months ended June 30, 2014 was approximately $17.8 million, a decrease of approximately $8.3 million, or 32%, from approximately $26.1 million for the six months ended June 30, 2013, as indicated in the table below (in millions).


37


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