Spark Energy, Inc. - FORM 10-Q

Attached files

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EX-31.2 - EXHIBIT 31.2 CERTIFICATION BY CFO - Spark Energy, Inc.	certcfoexh312-q32018.htm
EX-32 - EXHIBIT 32 CERTIFICATION BY CEO AND CFO - Spark Energy, Inc.	certceoandcfoexh32-q3018.htm
EX-31.1 - EXHIBIT 31.1 CERTIFICATION BY CEO - Spark Energy, Inc.	certceoexh311-q32018.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 September 30, 2018

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.)

12140 Wickchester Ln, Suite 100

Houston, Texas 77079

(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 x No o

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 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, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer o Accelerated filer x

Non-accelerated filer o Smaller reporting company o

Emerging Growth Company x

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. x

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 13,393,712 shares of outstanding Class A common stock, 21,485,126 shares of Class B common stock and 3,707,256 shares of Series A Preferred Stock outstanding as of October 31, 2018.



PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS

CONDENSED CONSOLIDATED BALANCE SHEETS AS OF SEPTEMBER 30, 2018 AND DECEMBER 31, 2017 (unaudited)		4

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2018 AND 2017 (unaudited)		5

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2018 (unaudited)		6

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2018 AND 2017 (unaudited)		7

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (unaudited)		9

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		42
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		62
ITEM 4. CONTROLS AND PROCEDURES		64
PART II. OTHER INFORMATION		65
ITEM 1. LEGAL PROCEEDINGS		65
ITEM 1A. RISK FACTORS		65
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		65
ITEM 3. DEFAULTS UPON SENIOR SECURITIES		65
ITEM 4. MINE SAFETY DISCLOSURES		65
ITEM 5. OTHER INFORMATION		65
ITEM 6. INDEX TO EXHIBITS		66
SIGNATURES		69

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Below is a list of terms that are common to our business and used throughout this document.

CFTC. The Commodity Futures Trading Commission.

ERCOT. The Electric Reliability Council of Texas, the independent system operator and the regional coordinator of various electricity systems within Texas.

FERC. The Federal Energy Regulatory Commission, a regulatory body that regulates, among other things, the transmission and wholesale sale of electricity and the transportation of natural gas by interstate pipelines in the United States.

ISO. An independent system operator. An ISO manages and controls transmission infrastructure in a particular region.

MMBtu. One million British Thermal Units, a standard unit of heating equivalent measure for natural gas. A unit of heat equal to 1,000,000 Btus, or 1 MMBtu, is the thermal equivalent of approximately 1,000 cubic feet of natural gas.

MWh. One megawatt hour, a unit of electricity equal to 1,000 kilowatt hours (kWh), or the amount of energy equal to one megawatt of constant power expended for one hour of time.

Non-POR Market. A non-purchase of accounts receivable market.

NYPSC. New York Public Service Commission.

POR Market. A purchase of accounts receivable market.

RCE. A residential customer equivalent, refers to a natural gas customer with a standard consumption of 100 MMBtus per year or an electricity customer with a standard consumption of 10 MWhs per year.

REP. A retail electricity provider.

RTO. A regional transmission organization. A RTO, similar to an ISO, is a third party entity that manages transmission infrastructure in a particular region.

When we refer to "we," "us," "our," "ours," "the Company," or "Spark Energy," we are describing Spark Energy, Inc. and/or our subsidiaries.

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Cautionary Note Regarding Forward-Looking Statements

This report contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. These forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), 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, objectives and beliefs 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, legal proceedings, 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 that 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 and the sufficiency of risk management and hedging policies and practices;


•	extreme and unpredictable weather conditions, and the impact of hurricanes and other natural disasters;


•	federal, state and local regulation, including the industry's ability to address or adapt to potentially restrictive new regulations that may be enacted by the New York Public Service Commission or other public utility commissions;


•	our ability to borrow funds and access credit markets and restrictions in our debt agreements and collateral requirements;


•	credit risk with respect to suppliers and customers;


•	changes in costs to acquire customers and actual attrition rates;


•	accuracy of billing systems;


•	whether our majority stockholder or its affiliates offer us acquisition opportunities at all, or on terms that are commercially acceptable to us;


•	our ability to successfully identify, complete, and efficiently integrate acquisitions into our operations;


•	significant changes in, or new changes by, the ISOs in the regions we operate;


•	competition; and


•	the "Risk Factors" in our Annual Report Form 10-K for the year ended December 31, 2017, in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2018 and our other public filings and press releases.

You should review the risk factors and other factors noted throughout or incorporated by reference in this report that 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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PART 1. — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

SPARK ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

AS OF SEPTEMBER 30, 2018 AND DECEMBER 31, 2017

(in thousands, except share counts)

(unaudited)



	September 30, 2018			December 31, 2017
Assets
Current assets:
Cash and cash equivalents	$	42,796		$	29,419
Accounts receivable, net of allowance for doubtful accounts of $4,324 at September 30 and $4,023 at December 31	134,183			158,814
Accounts receivable—affiliates	3,807			3,661
Inventory	4,077			4,470
Fair value of derivative assets	23,427			31,191
Customer acquisition costs, net	15,600			22,123
Customer relationships, net	18,360			18,653
Deposits	12,631			7,701
Other current assets	31,074			20,706
Total current assets	285,955			296,738
Property and equipment, net	5,383			8,275
Fair value of derivative assets	1,873			3,309
Customer acquisition costs, net	3,466			6,949
Customer relationships, net	28,247			34,839
Deferred tax assets	24,935			24,185
Goodwill	120,343			120,154
Other assets	11,075			11,500
Total assets	$	481,277		$	505,949
Liabilities, Series A Preferred Stock and Stockholders' Equity
Current liabilities:
Accounts payable	$	55,496		$	77,510
Accounts payable—affiliates	2,836			4,622
Accrued liabilities	45,518			33,679
Fair value of derivative liabilities	269			1,637
Current portion of Senior Credit Facility	—			7,500
Current payable pursuant to tax receivable agreement—affiliates	2,508			5,937
Current contingent consideration for acquisitions	2,980			4,024
Other current liabilities	856			2,675
Current portion of note payable	10,535			13,443
Total current liabilities	120,998			151,027
Long-term liabilities:
Fair value of derivative liabilities	489			492
Payable pursuant to tax receivable agreement—affiliates	26,067			26,355
Long-term portion of Senior Credit Facility	112,000			117,750
Subordinated debt—affiliate	10,000			—
Long-term portion of note payable	—			7,051
Contingent consideration for acquisitions	—			626
Other long-term liabilities	—			172
Total liabilities	269,554			303,473
Commitments and contingencies (Note 13)
Series A Preferred Stock, par value $0.01 per share, 20,000,000 shares authorized, 3,707,256 shares issued and outstanding at September 30 and 1,704,339 shares issued and outstanding at December 31	90,758			41,173
Stockholders' equity:
Common Stock:
Class A common stock, par value $0.01 per share, 120,000,000 shares authorized, 13,493,158 issued, and 13,393,712 outstanding at September 30 and 13,235,082 issued and 13,135,636 outstanding at December 31	135			132
Class B common stock, par value $0.01 per share, 60,000,000 shares authorized, 21,485,126 issued and outstanding at September 30 and December 31	216			216
Additional paid-in capital	25,387			26,914
Accumulated other comprehensive loss	(15		)	(11		)
Retained earnings	2,885			11,008
Treasury stock, at cost, 99,446 shares at September 30 and December 31	(2,011		)	(2,011		)
Total stockholders' equity	26,597			36,248
Non-controlling interest in Spark HoldCo, LLC	94,368			125,055
Total equity	120,965			161,303
Total liabilities, Series A Preferred Stock and stockholders' equity	$	481,277		$	505,949

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

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SPARK ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2018 AND 2017

(in thousands, except per share data)

(unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Revenues:
Retail revenues	$	258,127		$	215,856		$	773,616		$	563,960
Net asset optimization revenues/(expense)	348			(320		)	3,798			(681		)
Total Revenues	258,475			215,536			777,414			563,279
Operating Expenses:
Retail cost of revenues	193,409			160,373			645,954			420,771
General and administrative	25,695			25,566			83,522			69,405
Depreciation and amortization	13,917			11,509			39,797			30,435
Total Operating Expenses	233,021			197,448			769,273			520,611
Operating income	25,454			18,088			8,141			42,668
Other (expense)/income:
Interest expense	(2,762		)	(2,863		)	(7,323		)	(8,760		)
Interest and other income (loss)	(47		)	168			707			102
Total other expenses	(2,809		)	(2,695		)	(6,616		)	(8,658		)
Income before income tax expense	22,645			15,393			1,525			34,010
Income tax expense	3,818			2,451			602			5,265
Net income	$	18,827		$	12,942		$	923		$	28,745
Less: Net income attributable to non-controlling interests	13,218			10,595			140			23,049
Net income attributable to Spark Energy, Inc. stockholders	$	5,609		$	2,347		$	783		$	5,696
Less: Dividend on Series A preferred stock	2,027			932			6,081			2,106
Net income (loss) attributable to stockholders of Class A common stock	$	3,582		$	1,415		$	(5,298	)	$	3,590
Other comprehensive income, net of tax:
Currency translation gain (loss)	$	47		$	(13	)	$	(11	)	$	(88	)
Other comprehensive income (loss)	47			(13		)	(11		)	(88		)
Comprehensive income	$	18,874		$	12,929		$	912		$	28,657
Less: Comprehensive income attributable to non-controlling interests	13,247			10,587			133			22,994
Comprehensive income attributable to Spark Energy, Inc. stockholders	$	5,627		$	2,342		$	779		$	5,663

Net income (loss) attributable to Spark Energy, Inc. per share of Class A common stock
Basic	$	0.27		$	0.11		$	(0.40	)	$	0.27
Diluted	$	0.27		$	0.11		$	(0.40	)	$	0.27

Weighted average shares of Class A common stock outstanding
Basic	13,394			13,235			13,254			13,112
Diluted	13,394			13,392			13,254			13,315

Dividends declared per share of Class A common stock	$	0.18125		$	0.18125		$	0.54375		$	0.54375

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

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SPARK ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2018

(in thousands)

(unaudited)



	Issued Shares of Class A Common Stock	Issued Shares of Class B Common Stock	Treasury Stock		Class A Common Stock		Class B Common Stock		Treasury Stock			Accumulated Other Comprehensive Loss			Additional Paid-in Capital			Retained Earnings (Deficit)			Total Stockholders' Equity			Non-controlling Interest			Total Equity
Balance at December 31, 2017	13,235	21,485	(99	)	$	132	$	216	$	(2,011	)	$	(11	)	$	26,914		$	11,008		$	36,248		$	125,055		$	161,303
Stock based compensation	—	—	—		—		—		—			—			3,596			—			3,596			—			3,596
Restricted stock unit vesting	258	—	—		3		—		—			—			(715		)	—			(712		)	—			(712		)
Consolidated net income	—	—	—		—		—		—			—			—			783			783			140			923
Foreign currency translation adjustment for equity method investee	—	—	—		—		—		—			(4		)	—			—			(4		)	(7		)	(11		)
Distributions paid to non-controlling unit holders	—	—	—		—		—		—			—			—			—			—			(23,701		)	(23,701		)
Dividends paid to Class A common stockholders	—	—	—		—		—		—			—			(2,381		)	(4,852		)	(7,233		)	—			(7,233		)
Dividends to Preferred Stock	—	—	—		—		—		—			—			(2,027		)	(4,054		)	(6,081		)	—			(6,081		)
Acquisition of Customers from Affiliate	—	—	—		—		—		—			—			—						—			(7,119		)	(7,119		)
Balance at September 30, 2018	13,493	21,485	(99	)	$	135	$	216	$	(2,011	)	$	(15	)	$	25,387		$	2,885		$	26,597		$	94,368		$	120,965

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

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SPARK ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2018 AND 2017

(in thousands)

(unaudited)

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	Nine Months Ended September 30,
	2018			2017
Cash flows from operating activities:
Net income	$	923		$	28,745
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization expense	38,538			30,584
Deferred income taxes	(749		)	681
Change in TRA liability	79			—
Stock based compensation	3,707			4,023
Amortization of deferred financing costs	1,243			750
Excess tax benefit related to restricted stock vesting	(101		)	179
Change in Fair Value of Earnout liabilities	(63		)	(9,423		)
Accretion on fair value of Earnout liabilities	—			3,787
Bad debt expense	8,480			3,436
Loss on derivatives, net	1,371			34,225
Current period cash settlements on derivatives, net	6,189			(20,816		)
Accretion of discount to convertible subordinated notes to affiliate	—			1,004
Payment of the Major Energy Companies Earnout	—			(1,104		)
Payment of the Provider Companies Earnout	—			(677		)
Other	(489		)	123
Changes in assets and liabilities:
Decrease in accounts receivable	21,029			18,056
Increase in accounts receivable—affiliates	(390		)	(2,508		)
Decrease (increase) in inventory	475			(1,936		)
Increase in customer acquisition costs	(8,949		)	(18,642		)
(Increase) decrease in prepaid and other current assets	(10,999		)	1,536
Increase in intangible assets—customer acquisitions	(86		)	(32		)
Decrease (increase) in other assets	92			(664		)
Decrease in accounts payable and accrued liabilities	(11,062		)	(9,301		)
(Decrease) increase in accounts payable—affiliates	(1,786		)	1,165
(Decrease) increase in other current liabilities	(5,140		)	22
Decrease in other non-current liabilities	(459		)	(1,170		)
Net cash provided by operating activities	41,853			62,043
Cash flows from investing activities:
Purchases of property and equipment	(1,097		)	(1,438		)
Acquisitions of Perigee and other customers	—			(11,464		)
Acquisition of the Verde Companies	—			(65,785		)
Verde working capital settlement	470			—
Acquisition of HIKO	(14,290		)	—
Acquisition of Customers from Affiliate	(8,776		)	—
Net cash used in investing activities	(23,693		)	(78,687		)
Cash flows from financing activities:
Proceeds from issuance of Series A Preferred Stock, net of issuance costs paid	48,490			40,312
Borrowings on notes payable	277,800			139,400
Payments on notes payable	(281,050		)	(119,664		)
Payment of the Major Energy Companies Earnout	(1,607		)	(6,299		)
Payment of the Provider Companies Earnout and installment consideration	—			(7,061		)
Payments on the Verde promissory note	(6,573		)	(2,149		)
Proceeds from disgorgement of stockholders short-swing profits	244			872
Restricted stock vesting	(2,589		)	(2,009		)
Payment of Tax Receivable Agreement liability	(3,577		)	—
Payment of dividends to Class A common stockholders	(7,233		)	(7,137		)
Payment of distributions to non-controlling unitholders	(23,701		)	(24,270		)
Payment of Dividends to Preferred Stock	(4,987		)	(1,174		)
Purchase of Treasury Stock	—			(1,888		)
Net cash (used in) provided by financing activities	(4,783		)	8,933
Increase (decrease) in Cash and cash equivalents	13,377			(7,711		)
Cash and cash equivalents—beginning of period	29,419			18,960
Cash and cash equivalents—end of period	$	42,796		$	11,249
Supplemental Disclosure of Cash Flow Information:
Non-cash items:
Contingent consideration—earnout obligations incurred in connection with the Verde Companies acquisition	$	—		$	5,400
Net contribution by NG&E in excess of cash	$	—		$	1,019
Installment consideration incurred in connection with the Verde Companies acquisition	$	—		$	17,851
Property and equipment purchase accrual	$	(123	)	$	41
Cash paid during the period for:
Interest	$	5,955		$	4,113
Taxes	$	7,461		$	7,769

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

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SPARK ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. Formation and Organization

Organization

Spark Energy 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 natural gas and electricity. The Company is a holding company whose sole material asset consists of units in Spark HoldCo, LLC (“Spark HoldCo”). 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. Spark HoldCo is the direct and indirect owner of the subsidiaries through which we operate. We conduct our business through several brands across our service areas, including Spark Energy, Verde Energy, Oasis Energy, CenStar Energy, Provider Power Massachusetts, Electricity Maine, Electricity N.H., Major Energy, Respond Power, HIKO Energy, and Perigee Energy.

Relationship with our Founder and Majority Shareholder

W. Keith Maxwell, III (our "Founder") is the owner of a majority in voting power of our common stock through his ownership of NuDevco Retail, LLC ("NuDevco Retail") and Retailco, LLC ("Retailco"). Retailco is a wholly owned subsidiary of TxEx Energy Investments, LLC ("TxEx"), which is wholly owned by Mr. Maxwell. NuDevco Retail is a wholly owned subsidiary of NuDevco Retail Holdings LLC ("NuDevco Retail Holdings"), which is a wholly owned subsidiary of Electric HoldCo, LLC, which is also a wholly owned subsidiary of TxEx.

2. Basis of Presentation and Summary of Significant Accounting Policies

Basis of Presentation

The accompanying interim unaudited condensed consolidated 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 Securities and Exchange Commission (“SEC") as it applies to interim financial statements. This information should be read along with our consolidated financial statements and notes contained in our annual report on Form 10-K for the year ended December 31, 2017. Our unaudited condensed consolidated financial statements are presented on a consolidated basis and include all wholly-owned and controlled subsidiaries. We account for investments over which we have significant influence but not a controlling financial interest using the equity method of accounting. All significant intercompany transactions and balances have been eliminated in the unaudited condensed consolidated financial statements.

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 consolidated financial statements. See Note 16 "Subsequent Events" for further discussion.

Use of Estimates

The preparation of our condensed consolidated financial statements requires estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the interim financial statements and the reported amounts of revenues and expenses during the period. Actual results could materially 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 that are, in the opinion of management,

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necessary for a fair presentation of the condensed consolidated financial statements. Operating results for the three and nine months ended September 30, 2018 are not necessarily indicative of the results that may be expected for the full year or for any interim period.

Significant Accounting Policies

There have been no changes to our significant accounting policies as disclosed in our Annual Report on Form 10-K for the year ended December 31, 2017, except as follows:

In May 2014, the FASB issued 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. We adopted the new standard effective January 1, 2018 utilizing the full retrospective approach. The adoption of the new standard resulted in no impact to our total revenues and operating income for the years ended December 31, 2017 and 2016. The standard requires expanded disclosures regarding the qualitative and quantitative information of an entity's nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. See Note 3 "Revenues" for further disclosure.

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments ("ASU 2016-15"). ASU 2016-15 provides guidance on the presentation and classification of certain items in the statement of cash flows. This ASU has been applied using a retrospective transition method for each period presented. We adopted ASU 2016-15 effective January 1, 2018, which resulted in the reclassification of contingent consideration payments made after a business combination as cash outflows for operating and financing activities on a retrospective basis. Because of the change in accounting guidance, we reclassified acquisition related payments of approximately $1.8 million from cash flows from investing activities to cash flows from operating activities for the nine months ended September 30, 2017. We also reclassified other acquisition related payments of approximately $15.5 million from cash flows from investing activities to cash flows from financing activities for the nine months ended September 30, 2017.

In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business ("ASU 2017-01"). ASU 2017-01 clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. We adopted ASU 2017-01 effective January 1, 2018, using it to evaluate all acquisitions after that date.

New Accounting Standards Being Evaluated But Not Yet Adopted

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) ("ASU 2016-02"). Under this new guidance, lessees will be required to recognize assets and liabilities on the balance sheet for the rights and obligations created by all leases with terms of greater than twelve months. The guidance requires qualitative disclosures along with certain specific quantitative disclosures for both lessees and lessors. In July 2018, the FASB issued ASU No. 2018-10, Codification Improvements to Topic 842, Leases (“ASU 2018-10”), and ASU No. 2018-11, Leases (Topic 842): Targeted Improvements (“ASU 2018-11”), to provide additional guidance for the adoption of Topic 842. The ASU and its related amendments are effective for fiscal years beginning after December 15, 2018, with early adoption permitted, and are effective for interim periods in the year of adoption. The ASU should be applied using a modified retrospective approach, which requires lessees and lessors to recognize and measure leases at the beginning of the earliest period presented with an option to use certain practical expedients, which we expect to use. We are continuing to evaluate the impact of this new guidance and have put in place a process to review lease contracts, evaluate existing lease related processes and design training related to the new standard. Although we are in the process of evaluating the impact of the new lease guidance on our consolidated financial statements, we currently believe the primary impact will be related to our real estate operating leases.

In January 2017, the FASB issued ASU No. 2017-04, Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment ("ASU 2017-04"). ASU 2017-04 simplifies the subsequent measurement of goodwill

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by eliminating Step 2 from the goodwill impairment test. Under this update, an entity should perform its annual or interim, goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount, including goodwill. An entity should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit's fair value. However, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. ASU 2017-04 should be applied on a prospective basis and is effective for annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. We are currently evaluating the impact of adopting this guidance on its consolidated financial statements.

In June 2018, the FASB issued ASU No. 2018-07, Compensation - Stock Compensation (Topic 718): Improvements to Non-employee Share-Based Payment Accounting ("ASU 2018-07"). ASU 2018-07 primarily expands the scope of Topic 718 to include share-based payment transactions for acquiring goods and services from non-employees. ASU 2018-07 is effective for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. We are currently evaluating the impact of adopting this guidance on its consolidated financial statements.

In July 2018, the FASB issued ASU No. 2018-09, Codification Improvements ("ASU 2018-09"). ASU 2018-09 represent changes to clarify, correct errors in, or make minor improvements to the Codification to a variety of topics, including comprehensive income, debt modifications and extinguishment, stock compensation, income taxes, fair value measurement, financial brokers and dealers, and defined contribution plans. The transition and effective date guidance is based on the facts and circumstances of each amendment. Many of the amendments in this Update do have transition guidance with effective dates for annual periods beginning after December 15, 2018. We are currently evaluating the impact of adopting this guidance on its consolidated financial statements.

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3. Revenues

Our revenues are derived primarily from the sale of natural gas and electricity to retail customers. We also record revenue from sales of natural gas and electricity to wholesale counterparties, including affiliates. Revenue is measured based upon the quantity of gas or power delivered to the retail customer or wholesale counterparty at prices contained or referenced in the customer's contract, and excludes any sales incentives (e.g. rebates) and amounts collected on behalf of third parties (e.g. sales tax).

We record gross receipts taxes on a gross basis in retail revenues and retail cost of revenues. During the three months ended September 30, 2018 and 2017, our retail revenues included gross receipts taxes of $2.2 million and $2.1 million, respectively. During the three months ended September 30, 2018 and 2017, our retail cost of revenues included gross receipts taxes of $2.7 million and $2.7 million, respectively. During the nine months ended September 30, 2018 and 2017, our retail revenues included gross receipts taxes of $6.5 million and $4.6 million, respectively. During the nine months ended September 30, 2018 and 2017, our retail cost of revenues included gross receipts taxes of $7.8 million and $6.6 million, respectively.

Our revenues also include asset optimization activities. Asset optimization activities consist primarily of purchases and sales of gas that meet the definition of trading activities per FASB ASC Topic 815, Derivatives and Hedging. They are therefore excluded from the scope of Revenue from Contracts with Customers (Topic 606).

The following is a description of our principal revenue generating activities.

Retail Electricity

Revenues for electricity sales are recognized under the accrual method when our performance obligation to a customer is satisfied, which is the point in time when the product is delivered and control of the product passes to the customer. Electricity products may be sold as fixed or variable rate products. The typical length of a contract to provide electricity is 12 months. Customers are billed and typically pay at least monthly, based on usage. Electricity sales that have been delivered but not billed by period end are estimated. Accrued unbilled revenues are based on estimates of customer usage since the date of the last meter read provided by the utility. Volume estimates are based on forecasted volumes and estimated residential and commercial customer usage. Unbilled revenues are calculated by multiplying these volume estimates by the applicable rate by customer class (residential or commercial). Estimated amounts are adjusted when actual usage is known and billed.

Retail Natural Gas

Revenues for natural gas sales are recognized under the accrual method when our performance obligation to a customer is satisfied, which is the point in time when the product is delivered and control of the product passes to the customer. Natural gas products may be sold as fixed-price or variable-price products. The typical length of a contract to provide natural gas is 12 months. Customers are billed and typically pay at least monthly, based on usage. Natural gas sales that have been delivered but not billed by period end are estimated and recorded as accrued unbilled revenues based on estimates of customer usage since the date of the last meter read provided by the utility. Volume estimates are based on forecasted volumes and estimated residential and commercial customer usage. Unbilled revenues are calculated by multiplying these volume estimates by the applicable rate by customer class (residential or commercial). Estimated amounts are adjusted when actual usage is known and billed.

The following table discloses revenue by primary geographical market, customer type, and customer credit risk profile (in thousands). The table also includes a reconciliation of the disaggregated revenue to revenue by reportable segment (in thousands).

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	Reportable Segments
	Three Months Ended September 30, 2018								Three Months Ended September 30, 2017
	Retail Electricity			Retail Natural Gas		Total Reportable Segments			Retail Electricity		Retail Natural Gas		Total Reportable Segments


Primary markets (a)
New England	$	110,870		$	2,163	$	113,033		$	61,421	$	2,157	$	63,578
Mid-Atlantic	83,846			3,762		87,608			83,955		4,543		88,498
Midwest	20,898			2,557		23,455			20,111		2,570		22,681
Southwest	30,568			3,463		34,031			36,772		4,327		41,099
	$	246,182		$	11,945	$	258,127		$	202,259	$	13,597	$	215,856

Customer type
Commercial	$	101,818		$	4,650	$	106,468		$	55,489	$	5,004	$	60,493
Residential	151,918			7,068		158,986			143,152		8,571		151,723
Unbilled revenue (b)	(7,554		)	227		(7,327		)	3,618		22		3,640
	$	246,182		$	11,945	$	258,127		$	202,259	$	13,597	$	215,856

Customer credit risk
POR	$	172,198		$	5,013	$	177,211		$	138,544	$	5,963	$	144,507
Non-POR	73,984			6,932		80,916			63,715		7,634		71,349
	$	246,182		$	11,945	$	258,127		$	202,259	$	13,597	$	215,856

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	Reportable Segments
	Nine Months Ended September 30, 2018									Nine Months Ended September 30, 2017
	Retail Electricity			Retail Natural Gas			Total Reportable Segments			Retail Electricity		Retail Natural Gas			Total Reportable Segments


Primary markets (a)
New England	$	305,894		$	14,742		$	320,636		$	157,334	$	15,252		$	172,586
Mid-Atlantic	229,329			39,112			268,441			197,877		35,664			233,541
Midwest	56,818			27,243			84,061			43,073		23,893			66,966
Southwest	84,487			15,991			100,478			69,577		21,290			90,867
	$	676,528		$	97,088		$	773,616		$	467,861	$	96,099		$	563,960

Customer type
Commercial	$	275,966		$	39,826		$	315,792		$	140,408	$	40,224		$	180,632
Residential	415,022			73,138			488,160			322,354		70,886			393,240
Unbilled revenue (b)	(14,460		)	(15,876		)	(30,336		)	5,099		(15,011		)	(9,912		)
	$	676,528		$	97,088		$	773,616		$	467,861	$	96,099		$	563,960

Customer credit risk
POR	$	473,438		$	54,565		$	528,003		$	318,440	$	47,907		$	366,347
Non-POR	203,090			42,523			245,613			149,421		48,192			197,613
	$	676,528		$	97,088		$	773,616		$	467,861	$	96,099		$	563,960

(a) The primary markets noted above include the following states:


•	New England - Connecticut, Maine, Massachusetts, New Hampshire;


•	Mid-Atlantic - Delaware, Maryland (including the District of Colombia), New Jersey, New York and Pennsylvania;


•	Midwest - Illinois, Indiana, Michigan and Ohio; and


•	Southwest - Arizona, California, Colorado, Florida, Nevada, and Texas.

(b) Unbilled revenue is recorded in total until it is actualized, at which time it is categorized between commercial and residential customers.

4. Acquisitions

Acquisition of HIKO

On March 1, 2018, we entered into a Membership Interest Purchase Agreement under which we acquired all of the membership interests of HIKO Energy, LLC ("HIKO"), a New York limited liability company, for a total purchase price of $6.0 million in cash, plus working capital. At the time of acquisition, HIKO had a total of approximately 29,000 RCEs located in 42 markets in seven states. The acquisition was accounted for under the acquisition method in accordance with ASC 805, Business Combinations (“ASC 805”). Our preliminary allocation of the purchase price was based upon the estimated fair value of the tangible and identified intangible assets acquired and liabilities assumed in the acquisition. The preliminary allocation was made based on management’s best estimates, and supported by independent third-party analyses. The allocation of the purchase consideration is as follows (in thousands):

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	Reported as of March 31, 2018			2018 Adjustments ⁽¹⁾			As of September 30, 2018
Cash and restricted cash	$	309		$	66		$	375
Intangible assets—customer relationships	6,205			(174		)	6,031
Net working capital, net of cash acquired	9,041			(576		)	8,465
Fair value of derivative liabilities	(205		)	—			(205		)
Total	$	15,350		$	(684	)	$	14,666

(1) Changes to the purchase price allocation in 2018 were due to an agreement to settle the working capital balances with HIKO sellers per the purchase agreement.

Our condensed consolidated statements of operations for the three months ended September 30, 2018 included $4.9 million of revenue and $1.1 million of net income related to the operations of HIKO. Our condensed consolidated statements of operations for the nine months ended September 30, 2018 included $12.9 million of revenue and $3.7 million of net income related to the operations of HIKO.

Acquisition of Verde

On July 1, 2017, we acquired, through our subsidiary CenStar Energy Corp. ("CenStar"), all of the outstanding membership interests and stock in a group of companies (the "Verde Companies") from Verde Energy USA Holdings, LLC (the "Seller"). Total consideration was approximately $90.7 million, of which $20.1 million represented positive net working capital, as adjusted. We funded the closing consideration of $85.8 million through: (i) approximately $6.8 million of cash on hand, (ii) approximately $15.0 million in subordinated debt from our Founder through a subordinated debt facility, (iii) approximately $44.0 million in borrowings under our senior secured revolving credit facility, and (iv) the issuance of a promissory note to the Seller in the aggregate principal amount of $20.0 million (the “Promissory Note”). In addition to the consideration paid at closing, we were obligated to pay an additional amount based on achievement by the Verde Companies of certain performance targets over the 18 month period following the closing of the acquisition (the "Verde Earnout"). The Verde Earnout was initially valued at $5.4 million.

In January 2018, Spark and the Seller agreed to terminate the Verde Earnout and settled the Verde Earnout obligation with the issuance of a $5.9 million promissory note payable to the Seller due in June 2019.

The acquisition of the Verde Companies was accounted for under the acquisition method in accordance with ASC 805, Business Combinations (“ASC 805”). The allocation of purchase consideration was based upon the estimated fair value of the tangible and identifiable intangible assets acquired and liabilities assumed in the acquisition based on management’s best estimates, and supported by independent third-party analyses. The excess of the purchase price over the estimated fair value of tangible and intangible assets acquired and liabilities assumed was allocated to goodwill. The final allocation of the purchase consideration is as follows (in thousands):



	Reported as of December 31, 2017			Adjustments ⁽¹⁾			As of September 30, 2018
Cash and restricted cash	$	1,653		$	—		$	1,653
Property and equipment	4,560			—			4,560
Intangible assets—customer relationships	28,700			—			28,700
Intangible assets—trademarks	3,000			—			3,000
Goodwill⁽¹⁾	39,207			189			39,396
Net working capital, net of cash acquired ⁽¹⁾	19,132			(659		)	18,473
Deferred tax liability	(3,126		)	—			(3,126		)
Fair value of derivative liabilities	(1,942		)	—			(1,942		)
Total	$	91,184		$	(470	)	$	90,714

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(1) Changes to the purchase price allocation in 2018 were due to an agreement to settle the working capital balances with Verde Companies' sellers per the purchase agreement.

The following unaudited pro forma revenue and earnings summary presents our consolidated information as if the acquisition had occurred on January 1, 2016 (in thousands):



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Revenues	$	215,536	$	206,158	$	633,639	$	512,967
Earnings	$	2,347	$	1,761	$	4,991	$	9,623

The pro forma results are not necessarily indicative of our consolidated results of operations in future periods or the results that actually would have been realized had the companies operated on a combined basis during the periods presented. The pro forma results above include actual results and costs as well as adjustments primarily related to amortization of acquired intangibles, and certain accounting policy alignments as well as direct and incremental acquisition related costs reflected in the historical financial statements. The preliminary purchase price allocation was used to prepare the pro forma adjustments.

Acquisition of Perigee

On April 1, 2017, the Company and Spark Holdco acquired all of the outstanding membership interests of Perigee Energy, LLC, a Texas limited liability company ("Perigee"), with operations across 14 utilities in Connecticut, Delaware, Massachusetts, New York and Ohio from our affiliate, National Gas & Electric ("NG&E"). The purchase price for Perigee from NG&E was approximately $4.1 million, which consisted of a base price of $2.0 million, $0.2 million additional customer option payment, and $1.9 million in working capital, subject to adjustments. The acquisition was a transfer of equity interests between entities under common control, and accordingly, the assets acquired and liabilities assumed were based on their historical value as of the acquisition date. NG&E acquired Perigee on February 3, 2017 and the fair value of the net assets acquired was as follows (in thousands):



	Final as of December 31, 2017
Cash	$	23
Intangible assets—customer relationships	1,100
Goodwill	1,540
Net working capital, net of cash acquired	2,085
Fair value of derivative liabilities	(443		)
Total	$	4,305

In each of our acquisitions, we evaluate and allocate purchase price based on the following general assumptions.

Customer relationships

Acquired customer relationships intangibles are reflective of the acquired companies' customer bases, and were valued using an excess earnings method under the income approach. Using this method, we estimate the future cash flows resulting from the existing customer relationships, considering estimated attrition as well as charges for contributory assets, such as net working capital, intangible assets, fixed assets, and any assembled workforce. These future cash flows are then discounted using an appropriate risk-adjusted rate of return to arrive at the present value of the expected future cash flows. These customer relationships are amortized to depreciation and amortization based on the expected future net cash flows by year.

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In the Verde acquisition, customer relationships were bifurcated between unhedged and hedged and are being amortized based on the expected term of the underlying fixed price contract acquired in each reporting period, respectively.

Trademarks

The fair value of acquired trademarks is reflective of the value associated with the recognition and reputation of the acquired company to target markets. The fair value of trademarks are valued using a royalty savings method under the income approach. The value is based on the savings we would realize from owning the trademark rather than paying a royalty for the use of that trademark. Under this approach, we estimate the present value of the expected cash flows resulting from avoiding royalty payments to use a third party trademark. In the Verde acquisition, we analyzed market royalty rates charged for licensing trademarks and applied an expected royalty rate to a forecast of estimated revenue, which was then discounted using an appropriate risk adjusted rate of return. Trademarks are amortized over the estimated life of the asset on a straight-line basis.

Goodwill

The excess of the purchase consideration over the estimated fair value of the amounts initially assigned to the identifiable assets acquired and liabilities assumed is recorded as goodwill. Goodwill arose on the acquisitions of the Verde Companies and Perigee primarily due to the value of their assembled workforce, proprietary sales channels, and/or access to new utility service territories. Goodwill recorded in connection with these acquisitions is deductible for income tax purposes because these were acquisitions of all of the assets of the companies.

5. Equity

Non-controlling Interest

We hold an economic interest and are the sole managing member in Spark HoldCo, with NuDevco Retail and Retailco holding the remaining economic interests in Spark HoldCo. As a result, we have consolidated the financial position and results of operations of Spark HoldCo and reflected the economic interests owned by NuDevco Retail and Retailco as a non-controlling interest. The Company and NuDevco Retail and Retailco owned the following economic interests in Spark HoldCo at December 31, 2017 and September 30, 2018, respectively.



	The Company		NuDevco Retail and Retailco⁽¹⁾
December 31, 2017	38.12	%	61.88	%
September 30, 2018	38.58	%	61.42	%

The following table summarizes the portion of net income and income tax benefit attributable to non-controlling interest (in thousands):



	Three Months Ended September 30,					Nine Months Ended September 30,
	2018		2017			2018		2017

Net income allocated to non-controlling interest	$	13,910	$	9,525		$	830	$	21,094
Income tax expense (benefit) allocated to non-controlling interest	692		(1,070		)	690		(1,955		)
Net income attributable to non-controlling interest	$	13,218	$	10,595		$	140	$	23,049

Share Repurchase Program

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On May 24, 2017, the Company authorized a share repurchase program of up to $50.0 million of Spark Class A common stock through December 31, 2017. The Company funded the program through available cash balances, its credit facilities, and operating cash flows. The share repurchase program expired on December 31, 2017.

Treasury Stock

We use the cost method to account for our treasury shares. Purchases of shares of Class A common stock are recorded at cost.

Class A Common Stock and Class B Common Stock

Holders of the Company's 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.

Dividends declared for the Company's Class A common stock are reported as a reduction of retained earnings, or additional paid in capital in the case retained earnings is exhausted.

Earnings Per Share

Basic earnings per share (“EPS”) is computed by dividing net income attributable to stockholders (the numerator) by the weighted-average number of Class A common shares outstanding for the period (the denominator). Class B common shares are not included in the calculation of basic earnings per share because they are not participating securities and have no economic interest in us. Diluted earnings per share is similarly calculated except that the denominator is increased (1) using the treasury stock method to determine the potential dilutive effect of our outstanding unvested restricted stock units and (2) using the if-converted method to determine the potential dilutive effect of our Class B common stock.

The following table presents the computation of earnings (loss) per share for the three and nine months ended September 30, 2018 and 2017 (in thousands, except per share data):

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	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018			2017
Net income attributable to Spark Energy, Inc. stockholders	$	5,609	$	2,347	$	783		$	5,696
Less: Dividend on Series A preferred stock	2,027		932		6,081			2,106
Net income (loss) attributable to stockholders of Class A common stock	$	3,582	$	1,415	$	(5,298	)	$	3,590

Basic weighted average Class A common shares outstanding	13,394		13,235		13,254			13,112
Basic earnings (loss) per share attributable to stockholders	$	0.27	$	0.11	$	(0.40	)	$	0.27

Net income (loss) attributable to stockholders of Class A common stock	$	3,582	$	1,415	$	(5,298	)	$	3,590
Effect of conversion of Class B common stock to shares of Class A common stock	—		—		—			—
Diluted net income (loss) attributable to stockholders of Class A common stock	$	3,582	$	1,415	$	(5,298	)	$	3,590

Basic weighted average Class A common shares outstanding	13,394		13,235		13,254			13,112
Effect of dilutive Class B common stock	—		—		—			—
Effect of dilutive restricted stock units	—		157		—			203
Diluted weighted average shares outstanding	13,394		13,392		13,254			13,315

Diluted earnings (loss) per share attributable to stockholders	$	0.27	$	0.11	$	(0.40	)	$	0.27

The computation of diluted earnings per share for the three and nine months ended September 30, 2018 excludes 21.5 million shares of Class B common stock and 0.8 million restricted stock units because of their antidilutive effect. The Company's outstanding shares of Series A Preferred Stock were not included in the calculation of diluted earnings per share because they contain only contingent redemption provisions which have not occurred.

Variable Interest Entity

Spark HoldCo is a variable interest entity due to its lack of rights to participate in significant financial and operating decisions and its inability to dissolve or otherwise remove its management. Spark HoldCo owns all of the outstanding membership interests in each of the operating subsidiaries through which we operate. We are the sole managing member of Spark HoldCo, manage Spark HoldCo's operating subsidiaries through this managing membership interest, and are considered the primary beneficiary of Spark HoldCo. The assets of Spark HoldCo cannot be used to settle our obligations except through distributions to us, and the liabilities of Spark HoldCo cannot be settled by us except through contributions to Spark HoldCo. The following table includes the carrying amounts and classification of the assets and liabilities of Spark HoldCo that are included in our condensed consolidated balance sheet as of September 30, 2018 (in thousands):

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	September 30, 2018
Assets
Current assets:
Cash and cash equivalents	$	42,677
Accounts receivable	134,183
Other current assets	102,338
Total current assets	279,198
Non-current assets:
Goodwill	120,343
Other assets	47,958
Total non-current assets	168,301
Total Assets	$	447,499

Liabilities
Current liabilities:
Accounts payable and accrued liabilities	$	101,004
Contingent consideration	2,980
Other current liabilities	14,496
Total current liabilities	118,480
Long-term liabilities:
Long-term portion of Senior Credit Facility	112,000
Subordinated debt — affiliate	10,000
Other long-term liabilities	489
Total long-term liabilities	122,489
Total Liabilities	$	240,969

6. Preferred Stock

On March 15, 2017, we issued 1,610,000 shares of 8.75% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Stock ("Series A Preferred Stock"), par value $0.01 per share and liquidation preference $25.00 per share, plus accumulated and unpaid dividends, at a price to the public of $25.00 per share ($24.21 per share to us, net of underwriting discounts and commissions). We received approximately $39.0 million in net proceeds from the offering, after deducting underwriting discounts and commissions and a structuring fee. Offering expenses of $1.0 million were recorded as a reduction to the carrying value of the Series A Preferred Stock. The net proceeds from the offering were contributed to Spark HoldCo to use for general corporate purposes.

On July 21, 2017, we entered into an At-the-Market Issuance Sales Agreement ("the ATM Agreement") with FBR Capital Markets & Co. as sales agent (the "Agent"). Pursuant to the terms of the ATM Agreement, we may sell, from time to time through the Agent, our Series A Preferred Stock, having an aggregate offering price of up to $50.0 million. During the year ended December 31, 2017, we sold an aggregate of 94,339 shares of Series A Preferred Stock under the ATM Agreement. We received net proceeds of $2.4 million and paid compensation to the sales agent of less than $0.1 million with respect to these sales. During the nine months ended September 30, 2018, we sold an aggregate of 2,917 shares of Series A Preferred Stock under the ATM Agreement. We received net proceeds of $0.1 million and paid compensation to the sales agent of less than $0.1 million with respect to these sales.

On January 23, 2018, we commenced a public offering of our Series A Preferred Stock pursuant to an effective shelf registration statement on Form S-3 previously filed with the SEC. The offering closed on January 26, 2018. As part of the offering, we issued 2,000,000 shares of Series A Preferred Stock, plus accumulated and unpaid dividends, at a price to the public of $25.25 per share ($24.45 per share, net of underwriting discounts and commissions). The

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Company received approximately $48.9 million in net proceeds from the offering, after deducting underwriting discounts and commissions and a structuring fee. Offering expenses of $0.5 million were recorded as a reduction to the carrying value of the Series A Preferred Stock. The net proceeds from the offering were contributed to Spark HoldCo to use for general corporate purposes.

Holders of the Series A Preferred Stock have no voting rights, except in specific circumstances of delisting or in the case the dividends are in arrears as specified in the Series A Preferred Stock Certificate of Designations. The Series A Preferred Stock accrue dividends at an annual percentage rate of 8.75%, and the liquidation preference provisions of the Series A Preferred Stock are considered contingent redemption provisions because there are rights granted to the holders of the Series A Preferred Stock that are not solely within our control upon a change in control of the Company. Accordingly, the Series A Preferred Stock is presented between liabilities and the equity sections in the accompanying consolidated balance sheet.

During the three and nine months ended September 30, 2018, respectively, we paid $2.0 million and $5.0 million in dividends to holders of the Series A Preferred Stock. As of September 30, 2018, we had accrued $2.0 million related to dividends to holders of the Series A Preferred Stock. This dividend was paid on October 15, 2018.

A summary of our preferred equity balance for the nine months ended September 30, 2018 is as follows:



	(in thousands)
Balance at December 31, 2017	$	41,173
Issuance of Series A Preferred Stock, net of issuance cost	48,490
Accumulated dividends on Series A Preferred Stock	1,095
Balance at September 30, 2018	$	90,758

In connection with the issuance of the Series A Preferred Stock, the Company and Spark HoldCo entered into the Third Amended and Restated Spark HoldCo Limited Liability Company Agreement to amend the prior agreement to provide for, among other things, the designation and issuance of Spark HoldCo Series A preferred units, as another equity security of Spark HoldCo to be issued concurrently with the issuance of Series A Preferred Stock by us, including specific terms relating to distributions by Spark HoldCo in connection with the payment by us of dividends on the Series A Preferred Stock, the priority of liquidating distributions by Spark HoldCo, the allocation of income and loss to us in connection with distributions by Spark HoldCo on Series A preferred units, and other terms relating to the redemption and conversion by us of the Series A Preferred Stock.

7. Property and Equipment

Property and equipment consist of the following amounts (in thousands):



	Estimated useful lives (years)	September 30, 2018			December 31, 2017
Information technology	2 – 5	$	34,279		$	34,103
Leasehold improvements	2 – 5	4,568			4,568
Furniture and fixtures	2 – 5	1,964			1,964
Building improvements	2 – 5	809			809
Total		41,620			41,444
Accumulated depreciation		(36,237		)	(33,169		)
Property and equipment—net		$	5,383		$	8,275

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 September 30, 2018 and December 31, 2017, information technology includes $0.5 million and $1.2 million, respectively, of costs associated with assets not yet placed into service.

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Depreciation expense recorded in the condensed consolidated statements of operations was $1.0 million and $0.8 million for the three months ended September 30, 2018 and 2017, respectively, and $3.1 million and $1.8 million for the nine months ended September 30, 2018 and 2017, respectively.

8. Goodwill, Customer Relationships and Trademarks

Goodwill, customer relationships and trademarks consist of the following amounts (in thousands):



	September 30, 2018			December 31, 2017
Goodwill	$	120,343		$	120,154
Customer relationships - Acquired
Cost	$	99,402		$	93,371
Accumulated amortization	(58,671		)	(46,681		)
Customer relationships - Acquired, net	$	40,731		$	46,690
Customer relationships - Other
Cost	$	14,080		$	12,336
Accumulated amortization	(8,204		)	(5,534		)
Customer relationships - Other, net	$	5,876		$	6,802
Trademarks
Cost	$	9,770		$	9,770
Accumulated amortization	(2,023		)	(1,212		)
Trademarks, net	$	7,747		$	8,558

Changes in goodwill, customer relationships and trademarks consisted of the following (in thousands):



	Goodwill		Customer Relationships - Acquired & Non-Compete Agreements			Customer Relationships - Others			Trademarks
Balance at December 31, 2017	$	120,154	$	46,690		$	6,802		$	8,558
Additions	—		6,205			1,744			—
Adjustments ⁽¹⁾	189		(174		)	—			—
Amortization	—		(11,990		)	(2,670		)	(811		)
Balance at September 30, 2018	$	120,343	$	40,731		$	5,876		$	7,747

(1) Related to Spark's agreement to working capital balances with Verde Companies and HIKO sellers. Refer to Note 4 "Acquisitions."

Estimated future amortization expense for customer relationships and trademarks at September 30, 2018 is as follows (in thousands):



Year ending December 31,
2018	$	5,877
2019	16,958
2020	11,692
2021	10,118
2022	5,907
> 5 years	3,802
Total	$	54,354

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9. Debt

Debt consists of the following amounts as of September 30, 2018 and December 31, 2017 (in thousands):



	September 30, 2018		December 31, 2017
Current:
Senior Credit Facility—Bridge Loan⁽²⁾	$	—	$	7,500
Note Payable—Verde	10,535		13,443
Total current portion of debt	10,535		20,943
Long-term debt:
Senior Credit Facility ^{(1) (2)}	112,000		117,750
Subordinated Debt	10,000		—
Note Payable—Verde	—		7,051
Total long-term debt	122,000		124,801
Total debt	$	132,535	$	145,744

(1) As of September 30, 2018 and December 31, 2017, we had $61.2 million and $47.2 million in letters of credit issued, respectively.

(2) As of September 30, 2018 and December 31, 2017, the weighted average interest rate on the Senior Credit Facility was 5.13% and 4.61%, respectively.

Capitalized financing costs associated with our Senior Credit Facility were $1.5 million and $1.6 million as of September 30, 2018 and December 31, 2017, respectively. Of these amounts, $1.5 million and $1.2 million are recorded in other current assets, and zero and $0.4 million are recorded in other non-current assets in the condensed consolidated balance sheet as of September 30, 2018 and December 31, 2017, respectively.

Interest expense consists of the following components for the periods indicated (in thousands):



	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
Senior Credit Facility	$	1,423	$	988	$	3,895	$	2,216
Convertible subordinated notes to affiliate	—		—		—		1,052
Subordinated debt	13		153		20		161
Verde promissory note	288		162		978		162
Accretion related to Earnouts	—		1,127		—		3,787
Letters of credit and commitment fees	407		214		1,187		632
Amortization of deferred financing costs	631		219		1,243		750
Interest Expense	$	2,762	$	2,863	$	7,323	$	8,760

Senior Credit Facility

On May 19, 2017, the Company, as guarantor, and Spark HoldCo (the “Borrower” and, together with each subsidiary of Spark HoldCo (the “Co-Borrowers”), entered into a senior secured borrowing base credit facility (as amended, the “Senior Credit Facility”) in an aggregate amount of $120.0 million. The Verde Companies and HIKO became Co-Borrowers upon the completion of our acquisition of these companies.

During November 2017, January 2018, and July 2018, the Company and Co-Borrowers entered into amendments to the Senior Credit Facility to increase commitments under the facility. In connection with the increase in commitments, the various limits on advances for Working Capital Loans, Letters of Credit and Bridge Loans were increased accordingly. Subject to applicable sublimits and terms of the Senior Credit Facility, as amended, borrowings are available for the issuance of letters of credit (“Letters of Credit”), working capital and general purpose revolving credit loans up to $250.0 million (“Working Capital Loans”), and bridge loans up to $62.5 million (“Bridge Loans”) for the purpose of partial funding for acquisitions. Borrowings under the Senior Credit

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Facility may be used to pay fees and expenses in connection with the current Senior Credit Facility, finance ongoing working capital requirements and general corporate purpose requirements of the Co-Borrowers, to provide partial funding for acquisitions, as allowed under terms of the Senior Credit Facility, and to make open market purchases of our Class A common stock and Series A Preferred Stock.

As of September 30, 2018, we had a maximum borrowing capacity of $192.5 million and $112.0 million outstanding under the Senior Credit Facility, as well as $61.2 million of outstanding letters of credit.

The Senior Credit Facility, as amended, will mature on May 19, 2020, and all amounts outstanding thereunder will be payable on the maturity date. Borrowings under the Bridge Loan sublimit, if any, will be repaid 25% per year on a quarterly basis (or 6.25% per quarter), with the remainder due at maturity. As of September 30, 2018, there were no Bridge Loans outstanding.

At our election, the interest rate for Working Capital Loans and Letters of Credit under the Senior Credit Facility is generally determined by reference to the Eurodollar rate plus an applicable margin of up to 3.00% per annum (based on the prevailing utilization) or an alternate base rate plus an applicable margin of up to 2.00% per annum (based on the prevailing utilization). The alternate base rate is equal to the highest of (i) the prime rate (as published in the Wall Street Journal), (ii) the federal funds rate plus 0.50% per annum, or (iii) the reference Eurodollar rate plus 1.00%.

Bridge Loan borrowings, if any, under the Senior Credit Facility are generally determined by reference to the Eurodollar rate plus an applicable margin of 3.75% per annum or an alternate base rate plus an applicable margin of 2.75% per annum. The alternate base rate is equal to the highest of (i) the prime rate (as published in the Wall Street Journal), (ii) the federal funds rate plus 0.50% per annum, or (iii) the reference Eurodollar rate plus 1.00%.

The Co-Borrowers pay a commitment fee of 0.50% quarterly in arrears on the unused portion of the Senior Credit Facility. In addition, the Co-Borrowers are subject to additional fees including an upfront fee, an annual agency fee, and letter of credit fees based on a percentage of the face amount of letters of credit payable to any syndicate member that issues a letter of credit.

The Senior Credit Facility contains covenants that, among other things, require the maintenance of specified ratios or conditions including:

•

Minimum Fixed Charge Coverage Ratio. We must maintain a minimum fixed charge coverage ratio of not less than 1.25 to 1.00. The Fixed Charge Coverage Ratio is defined as the ratio of (a) Adjusted EBITDA to (b) the sum of consolidated (with respect to the Company and the Co-Borrowers) interest expense (other than interest paid-in-kind in respect of any subordinated debt but including interest in respect of that certain promissory note made by CenStar in connection with the permitted acquisition from Verde Energy USA Holdings, LLC, letter of credit fees, commitment fees, acquisition earn-out payments (excluding earnout payments funded with proceeds from newly issued preferred or common equity), distributions, the aggregate amount of repurchases of our Class A common stock, Series A Preferred Stock, or commitments for such purchases, taxes and scheduled amortization payments.


•	Maximum Total Leverage Ratio. We must maintain a ratio of total indebtedness (excluding eligible subordinated debt and letter of credit obligations) to Adjusted EBITDA of no more than 2.50 to 1.00.

•

Maximum Senior Secured Leverage Ratio. We must maintain a Senior Secured Leverage Ratio of no more than 1.85 to 1.00. The Senior Secured Leverage Ratio is defined as the ratio of (a) all indebtedness of the loan parties on a consolidated basis that is secured by a lien on any property of any loan party (including the effective amount of all loans then outstanding (but, in any case, limited to 50% of the effective amount of letter of credit obligations attributable to performance standby letters of credit) but excluding subordinated debt permitted by the Credit Agreement as amended by the Amendment) to (b) Adjusted EBITDA.

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The Senior Credit Facility contains various negative covenants that limit our ability to, among other things, incur certain additional indebtedness, grant certain liens, engage in certain asset dispositions, merge or consolidate, make certain payments, distributions, investments, acquisitions or loans, materially modify certain agreements, or enter into transactions with affiliates.

In addition, the Senior Credit Facility also contains affirmative covenants that are customary for credit facilities of this type. As of September 30, 2018, we are in compliance with our various covenants under the Senior Credit Facility.

The Senior Credit Facility is secured by pledges of the equity of the portion of Spark HoldCo owned by us, the equity of Spark HoldCo’s subsidiaries, the Co-Borrowers’ present and future subsidiaries, and substantially 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.

We are entitled to pay cash dividends to the holders of the Series A Preferred Stock and Class A common stock and will be entitled to repurchase up to an aggregate amount of 10,000,000 shares of our Class A common stock, and up to $92.7 million of Series A Preferred Stock through one or more normal course open market purchases through NASDAQ so long as: (a) no default exists or would result therefrom; (b) the Co-Borrowers are in pro forma compliance with all financial covenants before and after giving effect thereto; and (c) the outstanding amount of all loans and letters of credit does not exceed the borrowing base limits.

The Senior Credit Facility contains certain customary representations and warranties and events of default. Events of default include, among other things, payment defaults, breaches of representations and warranties, covenant defaults, cross-defaults and cross-acceleration to certain indebtedness, certain events of bankruptcy, certain events under ERISA, material judgments in excess of $5.0 million, certain events with respect to material contracts, actual or asserted failure of any guaranty or security document supporting the Senior Credit Facility to be in full force and effect, failure of Nathan Kroeker to retain his position as President and Chief Executive Officer of the Company, and failure of W. Keith Maxwell III to retain his position as chairman of the board of directors. A default will also occur if at any time W. Keith Maxwell III ceases to, directly or indirectly, own at least 13,600,000 Class A and Class B shares on a combined basis (to be adjusted for any stock split, subdivisions or other stock reclassification or recapitalization), and a controlling percentage of the voting equity interest of the Company, and certain other changes in control. If such an event of default occurs, the lenders under the Senior Credit Facility would be entitled to take various actions, including the acceleration of amounts due under the facility and all actions permitted to be taken by a secured creditor.

Subordinated Debt Facility

On December 27, 2016, the Company and Spark HoldCo jointly issued to Retailco, an entity owned by our Founder, a 5% subordinated note in the principal amount of up to $25.0 million. The subordinated note allows the Company and Spark HoldCo to draw advances in increments of no less than $1.0 million per advance up to the maximum principal amount of the subordinated note. The subordinated note matures in July 2020, and advances thereunder accrue interest at 5% per annum from the date of the advance. We have the right to capitalize interest payments under the subordinated note. The subordinated note is subordinated in certain respects to our Senior Credit Facility pursuant to a subordination agreement. We may pay interest and prepay principal on the subordinated note so long as we are in compliance with its covenants under the Senior Credit Facility, is not in default under the Senior Credit Facility and has minimum availability of $5.0 million under the borrowing base under the Senior Credit Facility. Payment of principal and interest under the subordinated note is accelerated upon the occurrence of certain change of control or sale transactions.

Verde Companies Promissory Note

In connection with the acquisition of the Verde Companies, on July 1, 2017, we entered into a Promissory Note in the aggregate principal amount of $20.0 million (the "Verde Promissory Note"). The Verde Promissory Note

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required repayment in eighteen monthly installments beginning on August 1, 2017, and accrued interest at 5% per annum from the date of issuance. The Verde Promissory Note, including principal and interest, was unsecured, but is guaranteed by us.

On January 12, 2018, in connection with the Earnout Termination Agreement (defined below), CenStar issued to the seller of the Verde Companies an amended and restated promissory note (the “Amended and Restated Verde Promissory Note”), which amended and restated the Verde Promissory Note. The Amended and Restated Verde Promissory Note, effective January 12, 2018, matures in January 2019, and bears interest at a rate of 9% per annum beginning January 1, 2018. Principal and interest are payable monthly on the first day of each month in which the Amended and Restated Verde Promissory Note is outstanding. CenStar deposits a portion of each payment under the Amended and Restated Verde Promissory Note into an escrow account, which serves as security for certain indemnification claims and obligations under the purchase agreement. The amount deposited into the escrow account was increased from the Verde Promissory Note. As of December 31, 2017, there was $14.6 million outstanding under the Verde Promissory note, and as of September 30, 2018, there was $4.6 million outstanding under the Amended and Restated Verde Promissory Note.

Verde Earnout Termination Note

On January 12, 2018, we issued a promissory note in the principal amount of $5.9 million in connection with an agreement to terminate the earnout obligations arising in connection with our acquisition of the Verde Companies (the “Verde Earnout Termination Note”). The Verde Earnout Termination Note matures on June 30, 2019 (subject to early maturity upon certain events) and bears interest at a rate of 9% per annum. CenStar is permitted to withhold amounts otherwise due at maturity related to certain indemnifiable matters. Interest is payable monthly on the first day of each month in which the Verde Earnout Termination Note is outstanding. The principal and any outstanding interest is due on June 30, 2019.

10. 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 the credit standing of counterparties involved and the impact of credit enhancements.

We apply fair value measurements to our commodity derivative instruments and contingent payment arrangements based on the following fair value hierarchy, which prioritizes the inputs to the 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 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. The Level 3 category includes estimated earnout obligations related to our acquisitions.

Other Financial Instruments

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The carrying amount of cash and cash equivalents, accounts receivable, accounts receivable—affiliates, accounts payable, accounts payable—affiliates, and accrued liabilities recorded in the condensed consolidated balance sheets approximate fair value due to the short-term nature of these items. The carrying amounts of the Senior Credit Facility and Prior Senior Credit Facility recorded in the condensed consolidated balance sheets approximate fair value because of the variable rate nature of our line of credit, and are considered Level 2 measurements because interest rates charged are similar to other financial instruments with similar terms and maturities. The fair value of our convertible subordinated notes to affiliates and the payable pursuant to tax receivable agreement—affiliate is not determinable for accounting purposes due to the affiliate nature and terms of the associated agreements with the affiliate.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The following table presents assets and liabilities measured and recorded at fair value in our condensed consolidated balance sheets on a recurring basis by and their level within the fair value hierarchy (in thousands):



	Level 1			Level 2			Level 3			Total
September 30, 2018
Non-trading commodity derivative assets	$	223		$	25,077		$	—		$	25,300
Trading commodity derivative assets	—			—			—			—
Total commodity derivative assets	$	223		$	25,077		$	—		$	25,300
Non-trading commodity derivative liabilities	$	(63	)	$	(502	)	$	—		$	(565	)
Trading commodity derivative liabilities	(189		)	(4		)	—			(193		)
Total commodity derivative liabilities	$	(252	)	$	(506	)	$	—		$	(758	)
Contingent payment arrangement	$	—		$	—		$	(2,980	)	$	(2,980	)



	Level 1			Level 2			Level 3			Total
December 31, 2017
Non-trading commodity derivative assets	$	158		$	33,886		$	—		$	34,044
Trading commodity derivative assets	—			456			—			456
Total commodity derivative assets	$	158		$	34,342		$	—		$	34,500
Non-trading commodity derivative liabilities	$	(387	)	$	(950	)	$	—		$	(1,337	)
Trading commodity derivative liabilities	(555		)	(237		)	—			(792		)
Total commodity derivative liabilities	$	(942	)	$	(1,187	)	$	—		$	(2,129	)
Contingent payment arrangement	$	—		$	—		$	(4,650	)	$	(4,650	)

We had no transfers of assets or liabilities between any of the above levels during the nine months ended September 30, 2018 and the year ended December 31, 2017.

Our derivative contracts include exchange-traded contracts valued utilizing readily available quoted market prices and non-exchange-traded contracts valued using market price quotations available through brokers or over-the-counter and on-line exchanges. In addition, in determining the fair value of our derivative contracts, we apply 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 September 30, 2018 and December 31, 2017, the credit risk valuation adjustment was not material.

The contingent payment arrangements referred to above reflect estimated earnout obligations incurred in relation to our acquisition of the Major Energy Companies in 2016. Of these amounts, $3.0 million and $4.0 million were classified as current liabilities as of September 30, 2018 and December 31, 2017, respectively, and zero and $0.6 million were classified as long-term liabilities as of September 30, 2018 and December 31, 2017, respectively.

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The Major Earnout is based on the achievement by the Major Energy Companies of certain performance targets over the 33 month period following NG&E's closing of the Major Energy Companies acquisition (i.e., April 15, 2016). The previous members of Major Energy Companies are entitled to a maximum of $20.0 million in earnout payments based on the level of performance targets attained, as defined by the Major Purchase Agreement. The Stock Earnout obligation is contingent upon the Major Energy Companies achieving the Major Earnout's performance target ceiling, thereby earning the maximum Major Earnout payments. If the Major Energy Companies earn such maximum Major Earnout payments, NG&E would be entitled to a maximum of 400,000 shares of Class B common stock (and a corresponding number of Spark HoldCo units). In determining the fair value of the Major Earnout and the Stock Earnout, we forecasted certain expected performance targets and calculated the probability of such forecast being attained. For the nine months ended September 30, 2018 and 2017, we paid $1.6 million and $7.4 million, respectively, related to the Major Earnout. We have classified the Major Earnout as a Level 3 measurement.

The following table presents a reconciliation of liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the nine months ended September 30, 2018.



	Major Earnout and Stock Earnout
Fair Value at December 31, 2017	$	4,650
Change in fair value of contingent consideration, net	(63		)
Payments and settlements	(1,607		)
Fair Value at September 30, 2018	$	2,980

11. Accounting for Derivative Instruments

We are exposed to the impact of market fluctuations in the price of electricity and natural gas, basis differences in the price of natural gas, storage charges, Renewable Energy Credits, capacity charges from independent system operators, and other ancillary costs. We use derivative instruments in an effort to manage our cash flow exposure to these risks. These instruments are not designated as hedges for accounting purposes, and accordingly, changes in the market value of these derivative instruments are recorded in the cost of revenues. As part of our strategy to optimize pricing in our natural gas related activities, we manage a portfolio of commodity derivative instruments held for trading purposes. Our commodity trading activities are subject to limits within our 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 our condensed consolidated balance sheets when the derivative instruments are executed with the same counterparty under a master netting arrangement. Our 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 we have 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 September 30, 2018 and December 31, 2017, we had paid zero and $0.1 million in collateral outstanding, respectively. The specific types of derivative instruments we may execute to manage the commodity price risk include the following:


•	Forward contracts, which commit us 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.

Interest Rate Swaps

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During the three months ended September 30, 2018, we entered into two interest rate swap agreements to manage interest rate risk. The interest rate swap agreements were not designated as hedges for accounting purposes. As such, all changes in fair value were recognized in earnings, within interest and other income. As of September 30, 2018, the notional amount of the interest swap was $10.0 million. A fair value liability of less than $0.1 million was recorded in other current liabilities on the condensed consolidated balance sheet as of September 30, 2018.

Volumetric Underlying Derivative Transactions

The following table summarizes the net notional volume buy/(sell) of our open derivative financial instruments accounted for at fair value, broken out by commodity (in thousands):

Non-trading



Commodity	Notional	September 30, 2018	December 31, 2017
Natural Gas	MMBtu	6,099	9,191
Natural Gas Basis	MMBtu	140	—
Electricity	MWh	5,980	8,091

Trading



Commodity	Notional	September 30, 2018	December 31, 2017
Natural Gas	MMBtu	221	26
Natural Gas Basis	MMBtu	78	(225	)

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 September 30,
	2018			2017
Gain (loss) on non-trading derivatives, net	$	17,888		$	(2,568	)
Gain (loss) on trading derivatives, net	229			(184		)
Gain (loss) on derivatives, net	18,117			(2,752		)
Current period settlements on non-trading derivatives ⁽¹⁾	1,035			7,481
Current period settlements on trading derivatives	(113		)	(24		)
Total current period settlements on derivatives	$	922		$	7,457

(1) Excludes settlements of $0.1 million and $1.5 million, respectively, for the three months ended September 30, 2018 and 2017 related to non-trading derivative liabilities assumed in various acquisitions.

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	Nine Months Ended September 30,
	2018			2017
Loss on non-trading derivatives, net	$	(2,223	)	$	(34,146	)
Gain (loss) on trading derivatives, net	852			(79		)
Loss on derivatives, net	(1,371		)	(34,225		)
Current period settlements on non-trading derivatives ⁽¹⁾	(5,054		)	19,016
Current period settlements on trading derivatives	(769		)	(208		)
Total current period settlements on derivatives	$	(5,823	)	$	18,808

(1) Excludes settlements of $(0.4) million and $2.0 million, respectively, for the nine months ended September 30, 2018 and 2017 related to non-trading derivative liabilities assumed in various acquisitions.

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 cost of revenues on the condensed consolidated statements of operations.

Fair Value of Derivative Instruments

The following tables summarize the fair value and offsetting amounts of our derivative instruments by counterparty and collateral received or paid (in thousands):



	September 30, 2018
Description	Gross Assets		Gross Amounts Offset			Net Assets		Cash Collateral Offset		Net Amount Presented
Non-trading commodity derivatives	$	42,794	$	(19,367	)	$	23,427	$	—	$	23,427
Trading commodity derivatives	—		—			—		—		—
Total Current Derivative Assets	42,794		(19,367		)	23,427		—		23,427
Non-trading commodity derivatives	10,003		(8,130		)	1,873		—		1,873
Trading commodity derivatives	—		—			—		—		—
Total Non-current Derivative Assets	10,003		(8,130		)	1,873		—		1,873
Total Derivative Assets	$	52,797	$	(27,497	)	$	25,300	$	—	$	25,300



	September 30, 2018
Description	Gross Liabilities			Gross Amounts Offset		Net Liabilities			Cash Collateral Offset		Net Amount Presented
Non-trading commodity derivatives	$	(280	)	$	15	$	(265	)	$	—	$	(265	)
Trading commodity derivatives	(4		)	—		(4		)	—		(4		)
Total Current Derivative Liabilities	(284		)	15		(269		)	—		(269		)
Non-trading commodity derivatives	(1,118		)	818		(300		)	—		(300		)
Trading commodity derivatives	(255		)	66		(189		)	—		(189		)
Total Non-current Derivative Liabilities	(1,373		)	884		(489		)	—		(489		)
Total Derivative Liabilities	$	(1,657	)	$	899	$	(758	)	$	—	$	(758	)

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	December 31, 2017
Description	Gross Assets		Gross Amounts Offset			Net Assets		Cash Collateral Offset		Net Amount Presented
Non-trading commodity derivatives	$	60,167	$	(29,432	)	$	30,735	$	—	$	30,735
Trading commodity derivatives	918		(462		)	456		—		456
Total Current Derivative Assets	61,085		(29,894		)	31,191		—		31,191
Non-trading commodity derivatives	16,055		(12,746		)	3,309		—		3,309
Trading commodity derivatives	—		—			—		—		—
Total Non-current Derivative Assets	16,055		(12,746		)	3,309		—		3,309
Total Derivative Assets	$	77,140	$	(42,640	)	$	34,500	$	—	$	34,500



	December 31, 2017
Description	Gross Liabilities			Gross Amounts Offset		Net Liabilities			Cash Collateral Offset		Net Amount Presented
Non-trading commodity derivatives	$	(4,517	)	$	3,059	$	(1,458	)	$	65	$	(1,393	)
Trading commodity derivatives	(517		)	273		(244		)	—		(244		)
Total Current Derivative Liabilities	(5,034		)	3,332		(1,702		)	65		(1,637		)
Non-trading commodity derivatives	(676		)	732		56			—		56
Trading commodity derivatives	(566		)	18		(548		)	—		(548		)
Total Non-current Derivative Liabilities	(1,242		)	750		(492		)	—		(492		)
Total Derivative Liabilities	$	(6,276	)	$	4,082	$	(2,194	)	$	65	$	(2,129	)

12. Income Taxes

Income Taxes

We and our subsidiaries, CenStar and Verde Energy USA, Inc. ("Verde Corp"), are each subject to U.S. federal income tax as corporations. CenStar and Verde Corp file consolidated tax returns in jurisdictions that allow combined reporting. Spark HoldCo and its subsidiaries, with the exception of CenStar and Verde Corp, are treated as flow-through entities for U.S. federal income tax purposes, and, as such, are generally not subject to U.S. federal income tax at the entity level. Rather, the tax liability with respect to their taxable income is passed through to their members or partners. Accordingly, we are subject to U.S. federal income taxation on our allocable share of Spark HoldCo’s net U.S. taxable income.

In our financial statements, we report federal and state income taxes for our share of the partnership income attributable to our ownership in Spark HoldCo and for the income taxes attributable to CenStar and Verde Corp. Net income attributable to non-controlling interests includes the provision for income taxes related to CenStar and Verde Corp.

We account for income taxes using the assets and liabilities method. Deferred tax assets and liabilities are recognized for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and the tax bases of the assets and liabilities. We apply existing tax law and the tax rate that we expect to apply to taxable income in the years in which those differences are expected to be recovered or settled in calculating the deferred tax assets and liabilities. Effects of changes in tax rates on deferred tax assets and liabilities are recognized in income in the period of the tax rate enactment. A valuation allowance is recorded when it is not more likely than not that some or all of the benefit from the deferred tax asset will be realized.

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On December 22, 2017, the President signed the Tax Cuts and Jobs Act (“U.S. Tax Reform”), which enacts a wide range of changes to the U.S. Corporate income tax system. For U.S. federal purposes, a corporate statutory income tax rate of 21% was utilized for the 2018 tax year. We remeasured our U.S. federal deferred tax assets and liabilities as of December 31, 2017 using the newly enacted 21% corporate tax rate. We have not revised any of the 2017 provisional estimates under SAB No. 118 and ASU No 2018-05, but continue to gather information and wait on further guidance from the IRS, SEC and FASB on U.S. Tax Reform.

On a quarterly basis, we assess whether it is more likely than not that we will generate sufficient taxable income to realize our deferred income tax assets. In making this determination, we consider all available positive and negative evidence and makes certain assumptions. We consider, among other things, our deferred tax liabilities, the overall business environment, our historical earnings and losses, current industry trends, and our outlook for future years. We believe it is more likely than not that our deferred tax assets will be realized.

As of September 30, 2018, we had a net deferred tax asset of approximately $15.6 million related to the original step up in tax basis resulting from the initial purchase of Spark HoldCo units from NuDevco Retail and NuDevco Retail Holdings (predecessor to Retailco) in connection with our initial public offering. In addition, as of September 30, 2018, we had a total liability of $28.6 million for the effect of the Tax Receivable Agreement liability, with approximately $2.5 million classified as short-term liability and the remainder as long-term. As of September 30, 2018, we had a long-term deferred tax asset of approximately $7.2 million related to the Tax Receivable Agreement liability. See Note 14 "Transactions with Affiliates" for further discussion.

The effective U.S. federal and state income tax rate for the nine months ended September 30, 2018 and 2017 is 39.5% and 15.5%, respectively. The effective tax rate for the nine months ended September 30, 2018 reflects the lower corporate U.S. federal statutory tax rate of 21% enacted for 2018, applied to the mix of earnings between corporate and partnership income, offset by the tax effect of Series A Preferred Stock dividends. Total income tax benefit for the nine months ended September 30, 2018 differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income primarily due to state taxes and the impact of permanent differences between book and taxable income, most notably the income attributable to non-controlling interests. The effective tax rate includes a rate benefit attributable to the fact that Spark HoldCo operates as a limited liability company treated as a partnership for federal and state income tax purposes and is not subject to federal and state income taxes. Accordingly, the portion of earnings attributable to non-controlling interest is subject to tax when reported as a component of the non-controlling interest’s taxable income.

13. Commitments and Contingencies

From time to time, we may be involved in legal, tax, regulatory and other proceedings in the ordinary course of business. Other than proceedings discussed below, management does not believe that we are a party to any litigation, claims or proceedings that will have a material impact on our condensed consolidated financial condition or results of operations. Liabilities for loss contingencies arising from claims, assessments, litigations or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.

Indirect Tax Audits

We are undergoing various types of indirect tax audits spanning from years 2009 to 2017 for which we may have additional liabilities arise. At the time of filing these condensed consolidated financial statements, these indirect tax audits are at an early stage and subject to substantial uncertainties concerning the outcome of audit findings and corresponding responses. As of September 30, 2018, we have accrued $1.0 million related to indirect tax audits. The outcome of these indirect tax audits may result in additional expense.

Legal Proceedings

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We are subject to lawsuits and claims arising in the ordinary course of business from time to time. We are also subject of the following lawsuits. At the time of filing these combined and consolidated financial statements, this litigation is at an early stage and subject to substantial uncertainties concerning the outcome of material factual and legal issues. Accordingly, we cannot currently predict the manner and timing of the resolution of this litigation or estimate a range of possible losses or a minimum loss that could result from an adverse verdict in a potential lawsuit. While the lawsuits and claims are asserted for amounts that may be material should an unfavorable outcome occur, management does not currently expect that any currently pending matters will have a material adverse effect on our financial position or results of operations, except as described below.

Katherine Veilleux and Jennifer Chon, individually and on behalf of all other similarly situated v. Electricity Maine. LLC, Provider Power, LLC, Spark HoldCo, LLC, Kevin Dean and Emile Clavet is a purported class action lawsuit filed on November 18, 2016 in the United States District Court of Maine, alleging that Electricity Maine, LLC, an entity acquired by Spark HoldCo, LLC in mid-2016, enrolled and re-enrolled customers through fraudulent and misleading advertising, promotions, and other communications prior to the acquisition. Plaintiffs further allege that some improper enrollment and re-enrollment practices have continued to the present date. Plaintiffs alleged claims under RICO, the Maine Unfair Trade Practice Act, negligence, negligent misrepresentation, fraudulent misrepresentation, unjust enrichment and breach of contract. Plaintiffs seek damages for themselves and the purported class, rescission of contracts with Electricity Maine, injunctive relief, restitution, and attorney’s fees. By order dated November 15, 2017, the Court, pursuant to Rule 12(b)(6), dismissed all claims against Spark HoldCo except the claims for violation of the Maine Unfair Trade Practices Act and for unjust enrichment. Discovery is limited to issues relevant to class certification under Rule 23 of the Federal Rules of Civil Procedure. Plaintiffs have recently filed a motion seeking leave to amend their complaint to reassert RICO claims against Spark, in addition to claims for civil conspiracy, unjust enrichment and unfair trade practices. The proposed amended complaint involves allegations relating to Spark’s and Electricity Maine’s door-to-door sales practices in Maine. Spark and Electricity Maine opposed the motion and the Court has not yet ruled on these motions. Spark HoldCo intends to vigorously defend this matter and the allegations asserted therein, including the request to certify a class. We cannot predict the outcome or consequences of this case at this time. We believe we are fully indemnified for this litigation matter, subject to certain limitations.

Gillis et al. v. Respond Power, LLC is a purported class action lawsuit that was originally filed on May 21, 2014 in the Philadelphia Court of Common Pleas. On June 23, 2014, the case was removed to the United States District Court for the Eastern District of Pennsylvania. On September 15, 2014, the plaintiffs filed an amended class action complaint seeking a declaratory judgment that the disclosure statement contained in Respond Power, LLC’s variable rate contracts with Pennsylvania consumers limited the variable rate that could be charged to no more than the monthly rate charged by the consumers’ local utility company. The plaintiffs also allege that Respond Power, LLC (i) breached its variable rate contract with Pennsylvania consumers, and the covenant of good faith and fair dealing therein, by charging rates in excess of the monthly rate charged by the consumers’ local utility company; (ii) engaged in deceptive conduct in violation of the Pennsylvania Unfair Trade Practices and Consumer Protection Law; and (iii) engaged in negligent misrepresentation and fraudulent concealment in connection with purported promises of savings. The amount of damages sought is not specified. By order dated August 31, 2015, the district court denied class certification. The plaintiffs appealed the district court’s denial of class certification to the United States Court of Appeals for the Third Circuit. The United States Court of Appeals for the Third Circuit vacated the district court’s denial of class certification and remanded the matter to the district court for further proceedings. The district court ordered briefing on defendant’s motion to dismiss. On July 16, 2018, the court granted Respond Power LLCs motion to dismiss the Plaintiff’s class action claims. Plaintiffs filed their notice of appeal to the Third Circuit Court on August 7, 2018. The final appellate briefing has not yet been completed. The Third Circuit has not yet ruled or set any hearings on this appeal. We currently cannot predict the outcome or consequences of this case at this time. We believe we are fully indemnified for this litigation matter, subject to certain limitations.

Jurich v. Verde Energy USA, Inc., is a class action originally filed on March 3, 2015 in the United States District Court for the District of Connecticut and subsequently re-filed on October 8, 2015 in the Superior Court of Judicial District of Hartford, State of Connecticut. The Amended Complaint asserts that the Verde Companies charged rates in violation of its contracts with Connecticut customers and alleges (i) violation of the Connecticut Unfair Trade

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Practices Act, Conn. Gen. Stat. §§ 42-110a et seq., and (ii) breach of the covenant of good faith and fair dealing. Plaintiffs are seeking unspecified actual and punitive damages for the class and injunctive relief. The parties have exchanged initial discovery. On December 6, 2017, the Court granted the plaintiffs’ class certification motion. However, the Court opted not to send out class notices, and instead directed the parties to submit briefing on legal issues that could result in a modification or decertification of the class. On June 21, 2018, the Court issued an opinion granting in part and denying in part the Plaintiffs’ motion for partial summary judgment. The Court granted the motion as to liability on a limited and discrete issue (whether Verde’s terms of service complied with a Connecticut statute’s requirement of sufficient clarity regarding rates). The full implications of that ruling are not yet clear. The Court has questioned whether such a statutory violation could justify an award of any compensatory damages. In its order, the Court also rejected the Plaintiffs’ principal theory that Verde’s Terms of Service obligated Verde to track Verde’s wholesale costs in setting its retail rates. Verde filed a motion for summary judgment and motion to decertify the class in August 2018 and plaintiffs filed their reply to that motion in September 2018. No hearing has been set on these motions. As part of an agreement in connection with the acquisition of the Verde Companies, the original owners of the Verde Companies are handling this matter, and we believe we are fully indemnified for this matter, subject to certain limitations. Given the early stage of this matter, we cannot predict the outcome or consequences of this case at this time.

Richardson et al v. Verde Energy USA, Inc. is a purported class action filed on November 25, 2015 in the United States District Court for the Eastern District of Pennsylvania alleging that the Verde Companies violated the Telephone Consumer Protection Act by placing marketing calls using an automatic telephone dialing system or a prerecorded voice to the purported class members’ cellular phones without prior express consent and by continuing to make such calls after receiving requests for the calls to cease. Plaintiffs are seeking statutory damages for the purported class and injunctive relief prohibiting Verde Companies' alleged conduct. Discovery on the claims of the named plaintiffs closed on November 10, 2017, and dispositive motions on the named plaintiffs’ claims were filed on November 24, 2017. The parties are now awaiting the Court’s decision on the pending dispositive motions. The case was recently reassigned to a new judge and the first status conference was held on October 12, 2018. As part of an agreement in connection with the acquisition of the Verde Companies, the original owners of the Verde Companies are handling this matter, and we believe we are fully indemnified for this matter, subject to certain limitations. Given the early stages of this matter, we cannot predict the outcome or consequences of this case at this time.

Saul Horowitz, as Sellers’ Representative for the former owners of the Major Energy Companies v. National Gas & Electric, LLC (NG&E) and Spark Energy, Inc. (Spark), has filed a lawsuit asserting claims of fraudulent inducement against NG&E, breach of contract against NG&E and us, and tortious interference with contract against us related to the membership interest purchase, subsequent transfer, and associated earnout agreements with the Major Energy Companies' former owners. The relief sought includes unspecified compensatory and punitive damages, prejudgment and post judgment interest, and attorneys’ fees. The lawsuit was filed on October 10, 2017 in the United States District Court for the Southern District of New York, and after the Company and NG&E filed a motion to dismiss, Horowitz filed an Amended Complaint, asserting the same four claims. The Company and NG&E filed a motion to dismiss the fraud and tortious interference claims on January 15, 2018. Briefing on the motion to dismiss concluded on March 1, 2018, On September 24, 2018. the court granted the motion in part and dismissed the plaintiffs’ fraudulent inducement claims but allowed the tortious interference claims to remain as well as the claims for consequential damages and punitive damages. NG&E and Spark filed their affirmative defenses and answer to the remaining claims on October 15, 2018. Discovery has commenced and written discovery requests have been exchanged between the parties. This case is currently set for trial on September 9, 2019. The Company and NG&E deny the allegations asserted and intend to vigorously defend this matter. Given the early stages of this matter, we cannot predict the outcome or consequences of this case at this time.

Regulatory Matters

On April 9, 2018 the Attorney General for the State of Illinois filed a complaint against Major Energy Electric Services, LLC (Major) asserting claims that Major engaged in a pattern and practice of deceptive conduct intended to defraud Illinois consumers through door-to-door and telephone solicitations, in-person solicitations at retail

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establishments, advertisements on its website and direct mail advertisements to sign up for electricity services. The complaint seeks injunctive relief and monetary damages representing the amounts Illinois consumers have allegedly lost due to fraudulent marketing activities. The Attorney General also requests civil penalties under the Consumer Fraud Act and to revoke Major’s authority to operate in the state. The complaint was filed in the Circuit Court of Cook County, Illinois, County Department, Chancery Division. Major filed its motion to dismiss on August 1, 2018. On October 10, 2018, the court denied Major’s Motion to Dismiss. A status conference is set with the judge on October 24, 2018. Major denies the allegations asserted and intends to vigorously defend this matter. Given the early stages of this matter, we cannot predict the outcome or consequences of this case at this time.

Spark Energy, LLC is the subject of two current investigations by the Connecticut Public Utilities Regulatory Authority (“PURA”). The first investigation constitutes a notice of violation and assessment of a proposed civil penalty in the amount of $0.9 million primarily for Spark Energy, LLC’s alleged failure to comply with regulations implemented in 2016 requiring that customer bills include any changes to existing rates effective for the next billing cycle. PURA has granted a motion by the Office of Consumer Counsel of the State of Connecticut to postpone briefing on this matter pending settlement negotiations. The second investigation involves a notice of violation into the marketing practices of one of Spark Energy, LLC’s former outbound telemarketing vendors and assessment of a proposed civil penalty of $0.8 million. Certain agents managed by this vendor were allegedly using an unauthorized script in outbound marketing calls. Spark Energy, LLC has already responded to several interrogatories regarding this matter and is awaiting further instruction from PURA. We are unable to predict the outcome of these proceedings but have accrued $0.2 million as of September 30, 2018, which represents our current estimate for a negotiated penalty for the matter. While investigations of this nature have become common and are often resolved in a manner that allows the retailer to continue operating in Connecticut, there can be no assurance that PURA will not take more severe action.

14. Transactions with Affiliates

Transactions with Affiliates

We enter into transactions with and pay certain costs on behalf of affiliates that are commonly controlled in order to reduce risk, reduce administrative expense, create economies of scale, create strategic alliances and supply goods and services to these related parties. We also sell and purchase natural gas and electricity with affiliates. We present receivables and payables with the same affiliate on a net basis in the condensed consolidated balance sheets as all affiliate activity is with parties under common control.

These transactions include certain services to the affiliated companies associated with employee benefits provided through our benefit plans, insurance plans, leased office space, administrative salaries for management, due diligence work, recurring management consulting, and accounting, tax, legal, or technology services based on services provided, departmental usage, or headcount, which are considered reasonable by management. As such, the accompanying condensed consolidated financial statements include costs that have been incurred by us and then directly billed or allocated to affiliates, as well as costs that have been incurred by our affiliates and then directly billed or allocated to us, and are recorded net in general and administrative expense on the condensed consolidated statements of operations with a corresponding accounts receivable—affiliates or accounts payable—affiliates, respectively, recorded in the condensed consolidated balance sheets. Transactions with 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 condensed consolidated statements of operations with a corresponding accounts receivable—affiliate or accounts payable—affiliate in the condensed consolidated balance sheets.

Acquisitions from Related Parties

In April 2017, we acquired Perigee from our affiliate, NG&E, for total consideration of approximately $4.1 million. The acquisition was treated as a transfer of equity interests of entities under common control.

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On March 7, 2018, we entered into an asset purchase agreement with NG&E pursuant to which we agreed to acquire up to 50,000 RCEs from NG&E for a cash purchase price of $250 for each RCE, or up to $12.5 million in the aggregate. These customers began transferring after April 1, 2018 and are located in 24 markets in 8 states. For the nine months ended September 30, 2018, we paid NG&E $8.8 million under the terms of the purchase agreement for approximately 35,000 RCEs. We do not anticipate any additional customer transfers or consideration will be paid on this transaction. The acquisition was treated as a transfer of assets between entities under common control, and accordingly, the assets were recorded at their historical value at the date of transfer. The transaction resulted in $7.1 million recorded in equity as a net distribution to affiliate as of September 30, 2018.

Master Service Agreement with Retailco Services, LLC

Prior to April 1, 2018, we were a party to a Master Service Agreement with companies owned by our Founder. The Master Service Agreement provided us with operational support services such as: enrollment and renewal transaction services; customer billing and transaction services; electronic payment processing services; customer services and information technology infrastructure and application support services under the Master Service Agreement. Effective April 1, 2018, we terminated the agreement, and these operational support services were transferred back to us. See "Cost Allocations" for further discussion of the fees paid in connection with the Master Service Agreement during the three and nine months ended September 30, 2018.

Accounts Receivable and Payable—Affiliates

We recorded current accounts receivable—affiliates of $3.8 million and $3.7 million as of September 30, 2018 and December 31, 2017, respectively, and current accounts payable—affiliates of $2.8 million and $4.6 million as of September 30, 2018 and December 31, 2017, respectively, for certain direct billings and cost allocations for services we provided to affiliates, services our affiliates provided to us, and sales or purchases of natural gas and electricity with affiliates.

Revenues and Cost of Revenues—Affiliates

Revenues—affiliates, recorded in net asset optimization revenues in the condensed consolidated statements of operations for the three months ended September 30, 2018 and 2017 were $0.3 million and zero, respectively. Revenues—affiliates, recorded in net asset optimization revenues in the condensed consolidated statements of operations for the nine months ended September 30, 2018 and 2017 were $1.3 million and zero, respectively.

Cost of revenues—affiliates, recorded in net asset optimization revenues in the condensed consolidated statements of operations for the three months ended September 30, 2018 and 2017 were less than $0.1 million and zero, respectively. Cost of revenues—affiliates, recorded in net asset optimization revenues in the condensed consolidated statements of operations for the nine months ended September 30, 2018 and 2017 were $0.1 million and zero, respectively.

Cost Allocations

We paid certain expenses on behalf of affiliates, which are reimbursed by our affiliates, and our affiliates paid certain expenses on our behalf, which are reimbursed by us. These transactions include costs that can be specifically identified and certain allocated overhead costs associated with general and administrative services, including executive management, due diligence work, recurring management consulting, 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 or us could not be determined by specific identification for direct billing, the costs were allocated to the affiliated entities or us based on estimates of percentage of departmental usage, wages or headcount. The total net amount direct billed and allocated from affiliates was $0.3 million and $5.7 million, respectively, for the three months ended September 30, 2018 and 2017, respectively. The total net amount direct billed and allocated from affiliates was $8.7 million and $19.4 million, respectively, for the nine months ended September 30, 2018 and 2017.

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Of the $0.3 million and $5.7 million total net amounts directly billed and allocated from affiliates, we recorded general and administrative expense of less than $0.1 million and $5.1 million for the three months ended September 30, 2018 and 2017, respectively, and of the $8.7 million and $19.4 million total net amounts directly billed and allocated from affiliates, we recorded general and administrative expense of $5.8 million and $17.0 million for the nine months ended September 30, 2018 and 2017, respectively, in the condensed consolidated statement of operations in connection with fees paid under the Master Service Agreement with Retailco Services. Additionally under the Master Service Agreement, we capitalized zero and $0.2 million of property and equipment for the application, development and implementation of various systems during the three months ended September 30, 2018 and 2017, respectively, and we capitalized $0.5 million and $0.5 million of property and equipment for the application, development and implementation of various systems during the nine months ended September 30, 2018 and 2017, respectively.

Distributions to and Contributions from Affiliates

During the nine months ended September 30, 2018 and 2017, Spark HoldCo made distributions to NuDevco Retail and Retailco of $11.7 million, for payments of quarterly distributions on its Spark HoldCo units. During the nine months ended September 30, 2018 and 2017, Spark HoldCo made distributions to NuDevco Retail and Retailco for gross-up distributions of $12.0 million and $12.6 million, respectively, in connection with distributions made between Spark HoldCo and Spark Energy, Inc. for payment of income taxes incurred by us.

Proceeds from Disgorgement of Stockholder Short-swing Profits

During the three and nine months ended September 30, 2018, we received zero and $0.2 million cash, respectively, for the disgorgement of stockholder short-swing profits under Section 16(b) under the Exchange Act accrued at December 31, 2017. The amount was recorded as an increase to additional paid-in capital in our consolidated balance sheet as of December 31, 2017.

Subordinated Debt Facility

Tax Receivable Agreement

We maintain a Tax Receivable Agreement with affiliates that generally provides for the payment by us to affiliates of 85% of the net cash savings, if any, in U.S. federal, state and local income tax or franchise tax that we realize or will realize (or are deemed to realize in certain circumstances) in future periods as a result of (i) any tax basis increases resulting from the initial purchase by us of Spark HoldCo units from Retailco LLC (a successor to NuDevco Retail Holdings) and NuDevco Retail, (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 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. We retain the benefit of the remaining 15% of these tax savings. See Note 12 "Income Taxes" for further discussion.

In certain circumstances, we may defer or partially defer any payment due (a “TRA Payment”) to the holders of rights under the Tax Receivable Agreement for the five year period ending September 30, 2019. Deferral of payment is required to the extent that Spark HoldCo does not generate sufficient Cash Available for Distribution (as

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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 us to receive distributions of cash equal to (i) the targeted quarterly distribution we intend to pay to holders of its Class A common stock and Series A Preferred Stock payable during the applicable four-quarter period, plus (ii) the estimated taxes payable by us 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.

Following the five-year deferral period ending September 30, 2019, we will be obligated to pay any outstanding deferred TRA Payments to the extent such deferred TRA Payments do not exceed (i) the lesser of our proportionate share of aggregate Cash Available for Distribution of Spark HoldCo during the five-year deferral period or the cash distributions actually received by us 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 $0.18125 per Class A common stock share and $0.546875 per Series A Preferred Stock share per quarter) during the five-year deferral period, (b) our estimated taxes during the five-year deferral period, and (c) all prior TRA Payments and (d) 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 us 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.

We met the threshold coverage ratio required to fund the TRA Payments to Retailco and NuDevco Retail under the Tax Receivable Agreement for the four-quarter periods ending September 30, 2016 and 2017. Retailco and NuDevco Retail granted the Company the right to defer the TRA payment related to the four-quarter period ending September 30, 2016 until May 2018. Accordingly, these TRA Payments were made in April and May 2018. We also met the threshold coverage ratio required to fund the payment to Retailco and NuDevco Retail under the Tax Receivable Agreement during the four-quarter period ending September 30, 2018, resulting in the related TRA Payment being due in January of 2019. We have classified $2.5 million and $5.9 million as a current liability in our consolidated balance sheet at September 30, 2018 and December 31, 2017, respectively. A TRA Payment of $2.3 million was made in October 2018 for the 2017 tax year, and the remainder of the current portion of the liability as of September 30, 2018 will be due in January 2019.

15. Segment Reporting

Our determination of reportable business segments considers the strategic operating units under which we make financial decisions, allocate resources and assess performance of our business. Our 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 priced natural gas to serve retail gas load, are included in the retail natural gas segment. For the three months ended September 30, 2018 and 2017, we recorded asset optimization revenues of $28.3 million and $31.7 million and asset optimization cost of revenues of $28.0 million and $32.0 million, respectively. For the nine months ended September 30, 2018 and 2017, we recorded asset optimization revenues of $139.2 million and $132.8 million and asset optimization cost of revenues of $135.4 million and $133.5 million, 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.

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The acquisitions of Perigee and the Verde Companies in 2017 and the acquisition of HIKO in 2018 had no impact on our reportable business segments as the portions of those acquisitions related to retail natural gas and retail electricity have been included in those existing business segments.

We use retail gross margin to assess the performance of our operating segments. Retail gross margin is defined as operating income (loss) plus (i) depreciation and amortization expenses and (ii) general and administrative expenses, less (i) net asset optimization revenues (expenses), (ii) net gains (losses) on non-trading derivative instruments, and (iii) net current period cash settlements on non-trading derivative instruments. We deduct net gains (losses) on non-trading 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 non-trading derivative instruments. 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 (in thousands):



	Three Months Ended September 30,					Nine Months Ended September 30,
	2018		2017			2018			2017
Reconciliation of Retail Gross Margin to Income before taxes
Income before income tax expense	$	22,645	$	15,393		$	1,525		$	34,010
Interest and other income	47		(168		)	(707		)	(102		)
Interest expense	2,762		2,863			7,323			8,760
Operating income	25,454		18,088			8,141			42,668
Depreciation and amortization	13,917		11,509			39,797			30,435
General and administrative	25,695		25,566			83,522			69,405
Less:
Net asset optimization revenues / (expenses)	348		(320		)	3,798			(681		)
Net, gain (loss) on non-trading derivative instruments	17,888		(2,568		)	(2,223		)	(34,146		)
Net, Cash settlements on non-trading derivative instruments	1,035		7,481			(5,054		)	19,016
Retail Gross Margin	$	45,795	$	50,570		$	134,939		$	158,319

Financial data for business segments are as follows (in thousands):



Three Months Ended September 30,
2018	Retail Electricity		Retail Natural Gas			Corporate and Other		Eliminations			Spark Retail
Total Revenues	$	246,182	$	12,293		$	—	$	—		$	258,475
Retail cost of revenues	186,449		6,960			—		—			193,409
Less:
Net asset optimization revenue	—		348			—		—			348
Gains (losses) on non-trading derivatives	18,415		(527		)	—		—			17,888
Current period settlements on non-trading derivatives	1,066		(31		)	—		—			1,035
Retail Gross Margin	$	40,252	$	5,543		$	—	$	—		$	45,795
Total Assets at September 30, 2018	$	1,719,297	$	581,530		$	249,814	$	(2,069,364	)	$	481,277
Goodwill at September 30, 2018	$	117,813	$	2,530		$	—	$	—		$	120,343

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2017	Retail Electricity			Retail Natural Gas			Corporate and Other		Eliminations			Spark Retail
Total revenues	$	202,259		$	13,277		$	—	$	—		$	215,536
Retail cost of revenues	153,594			6,779			—		—			160,373
Less:
Net asset optimization expense	—			(320		)	—		—			(320		)
Gains (losses) on non-trading derivatives	(2,762		)	194			—		—			(2,568		)
Current period settlements on non-trading derivatives	6,932			549			—		—			7,481
Retail Gross Margin	$	44,495		$	6,075		$	—	$	—		$	50,570
Total Assets at December 31, 2017	$	1,228,552		$	421,896		$	209,428	$	(1,353,927	)	$	505,949
Goodwill at December 31, 2017	$	117,624		$	2,530		$	—	$	—		$	120,154



Nine Months Ended September 30,
2018	Retail Electricity			Retail Natural Gas			Corporate and Other		Eliminations			Spark Retail
Total revenues	$	676,528		$	100,886		$	—	$	—		$	777,414
Retail cost of revenues	587,949			58,005			—		—			645,954
Less:
Net asset optimization revenue	—			3,798			—		—			3,798
Losses on non-trading derivatives	1,216			(3,439		)	—		—			(2,223		)
Current period settlements on non-trading derivatives	(5,250		)	196			—		—			(5,054		)
Retail Gross Margin	$	92,613		$	42,326		$	—	$	—		$	134,939
Total Assets at September 30, 2018	$	1,719,297		$	581,530		$	249,814	$	(2,069,364	)	$	481,277
Goodwill at September 30, 2018	$	117,813		$	2,530		$	—	$	—		$	120,343



2017	Retail Electricity			Retail Natural Gas			Corporate and Other		Eliminations			Spark Retail
Total revenues	$	467,861		$	95,418		$	—	$	—		$	563,279
Retail cost of revenues	364,518			56,253			—		—			420,771
Less:
Net asset optimization expenses	—			(681		)	—		—			(681		)
Losses on non-trading derivatives	(31,722		)	(2,424		)	—		—			(34,146		)
Current period settlements on non-trading derivatives	18,936			80			—		—			19,016
Retail Gross Margin	$	116,129		$	42,190		$	—	$	—		$	158,319
Total Assets at December 31, 2017	$	1,228,552		$	421,896		$	209,428	$	(1,353,927	)	$	505,949
Goodwill at December 31, 2017	$	117,624		$	2,530		$	—	$	—		$	120,154

16. Subsequent Events

Declaration of Dividends

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On October 18, 2018, we declared a quarterly dividend of $0.18125 to holders of record of our Class A common stock on November 30, 2018 and payable on December 14, 2018.

We also declared a quarterly cash dividend in the amount of $0.546875 per share of Series A Preferred Stock. The dividend will be paid January 15, 2019 to holders of record of the Series A Preferred Stock on January 1, 2019.

Acquisition of Customer Book

On October 19, 2018, we entered into an asset purchase agreement pursuant to which we will acquire approximately 60,000 RCEs from Starion Energy Inc., Starion Energy NY Inc. and Starion Energy PA Inc. for a cash purchase price of up to a maximum of $10.7 million. These customers are expected to begin transferring in late November 2018, and are located in our existing markets.

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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 consolidated financial statements and the related notes thereto included elsewhere in this report and the audited combined and consolidated financial statements and notes thereto and management's discussion and analysis of financial condition and results of operations included in our Form 10-K for the year ended December 31, 2017 that was filed with the Securities and Exchange Commission (“SEC”).

Overview

Spark Energy, Inc. is an 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 September 30, 2018, we operated in 94 utility service territories across 19 states and the District of Columbia.

Our business consists of two operating segments:

•

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 three months ended September 30, 2018 and 2017, approximately 95% and 94%, respectively, of our retail revenues were derived from the sale of electricity.

•

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 and variable-price contracts. For the three months ended September 30, 2018 and 2017, approximately 5% and 6%, respectively, of our retail revenues were derived from the sale of natural gas. We also attempt to improve our profitability on natural gas by identifying and executing on wholesale natural gas arbitrage opportunities, which we refer to as asset optimization.

Recent Developments

Acquisition of Customer Book

On October 19, 2018, we entered into an asset purchase agreement pursuant to which we will acquire up to 60,000 RCEs from Starion Energy Inc., Starion Energy NY Inc. and Starion Energy PA Inc. for a cash purchase price of up to a maximum of $10.7 million. These customers are expected to begin transferring in late November 2018, and are located in our existing markets.

Residential Customer Equivalents

We measure our number of customers using residential customer equivalents ("RCEs"). The following table shows activity of our RCEs during the three and nine months ended September 30, 2018:

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RCEs:
(In thousands)	June 30, 2018	Additions	Attrition	September 30, 2018	% Increase (Decrease)
Retail Electricity	883	45	(105)	823	(7)%
Retail Natural Gas	166	9	(19)	156	(6)%
Total Retail	1,049	54	(124)	979	(7)%



RCEs:
(In thousands)	January 1, 2018	Additions	Attrition	September 30, 2018	% Increase (Decrease)
Retail Electricity	868	269	(314)	823	(5)%
Retail Natural Gas	174	45	(63)	156	(10)%
Total Retail	1,042	314	(377)	979	(6)%

The following table details our count of RCEs by geographical location as of September 30, 2018:



RCEs by Geographic Location:
(In thousands)	Electricity	% of Total	Natural Gas	% of Total	Total	% of Total
New England	413	50%	31	20%	444	45%
Mid-Atlantic	275	33%	63	40%	338	35%
Midwest	58	7%	44	28%	102	10%
Southwest	77	10%	18	12%	95	10%
Total	823	100%	156	100%	979	100%

The geographical regions noted above include the following states:


•	New England - Connecticut, Maine, Massachusetts and New Hampshire;


•	Mid-Atlantic - Delaware, Maryland (including the District of Columbia), New Jersey, New York and Pennsylvania;


•	Midwest - Illinois, Indiana, Michigan and Ohio; and


•	Southwest - Arizona, California, Colorado, Florida, Nevada and Texas.

Across our market areas, we currently operate under eleven different retail brands. During 2018, we began consolidating these brands, and as a result, we will reduce this number to four separate brands, including Spark Energy, Verde Energy, Provider Power, and Major Energy. We expect the consolidation to be completed in 2019.

Drivers of our Business

The ultimate success of our business and our profitability are impacted by a number of drivers, the most significant of which are discussed below.

Customer Growth

Customer growth is a key driver of our operations. Our customer growth strategy includes growing organically through existing sales channels and acquiring customers through acquisitions to expand our presence in our existing markets and service areas. During the third quarter of 2018, we added approximately 54,000 RCEs through our various organic sales channels, and during the nine months ended September 30, 2018, we added a total of

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approximately 314,000 RCEs, of which 64,000 RCEs were added as part of the acquisitions of HIKO and customers from an affiliate.

Organic Growth

Our organic sales strategies are designed to offer competitive pricing, price certainty, and/or green product offerings to residential and commercial customers. 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 offered by the local regulated utility. 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 provides customer value and 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 profitability targets.

In 2017, we emphasized growing our commercial and industrial (“C&I”) volume. After significant growth in our C&I volume in 2017, we shifted our focus in 2018 toward residential and small commercial customers. Going forward, we expect to focus more on mass market RCE count, as these customers have historically been more profitable on a per unit basis.

Acquisitions

We acquire companies and portfolios of customers through both external and affiliated channels. In 2015, our Founder formed National Gas & Electric, LLC, an affiliate of the Company ("NG&E"), for the purpose of purchasing retail energy companies and retail customer books, as well as adding customers organically, that could ultimately be resold to us. Our ability to make acquisitions in the future that provide returns that are acceptable to us are dependent on our ability to successfully identify and negotiate transactions, which is impacted by market and industry conditions and by our affiliates' willingness to offer acquisitions to us, which they are under no obligation to do. Acquisition activity will also be impacted by our ability to fund these transactions through our existing capital structure. Finally, the ultimate success of our acquisitions will be based on our ability to effectively integrate customers and processes into our existing activities.

Effective integration of acquisitions is a key driver of our business. During 2016, we acquired the Major Energy Companies. The Major Energy Companies acquisition has an earnout obligation that concludes at the end of 2018. As a result, our ability to fully integrate this acquisition will not be achieved until the conclusion of that obligation. In 2017, we acquired the Verde Companies, and settled the related earnout obligation on that acquisition in early 2018. As a result, we were able to fully integrate the Verde Companies in 2018, enabling us to recognize synergies relating to the acquisition beginning with the second quarter. For acquisitions where earnouts are not present, we are able to immediately begin integrating their activities.

Customer Acquisition Costs Incurred

Managing customer acquisition costs is a key component of our profitability. Customer acquisition costs are those costs related to obtaining customers organically and do not include the cost of acquiring customers through acquisitions, which are recorded as customer relationships.

We attempt to maintain a disciplined approach to recovery of our customer acquisition costs within a 12 month period. We capitalize and amortize our customer acquisition costs over a two year period, which is based on the expected average length of a customer relationship. We factor in the recovery of customer acquisition costs in determining which markets we enter into and the pricing of our products in those markets. Accordingly, our results are significantly influenced by our customer acquisition costs.

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Customer acquisition costs incurred for the three months ended September 30, 2018 and 2017 were approximately $2.7 million and $6.6 million, respectively, and customer acquisition costs incurred for the nine months ended September 30, 2018 and 2017 were approximately $8.9 million and $18.6 million, respectively. Our customer acquisition costs were lower than the previous year because we were more focused on acquisitions of businesses, customer portfolio additions, and integration during the first three quarters of 2018.

Customer Attrition

Customer attrition occurs primarily as a result of: (i) customer initiated switches; (ii) residential moves and (iii) disconnection for customer payment defaults. Customer attrition for the three months ended September 30, 2018 and 2017 was 4.0% and 4.2%, respectively, and customer attrition for the nine months ended September 30, 2018 and 2017 was 4.0%. Our customer attrition was slightly lower than the prior year because of a relative slow-down in organic sales activity year-over-year, somewhat offset by the attrition caused by brand consolidations.

Customer Credit Risk

Our bad debt expense for the three months ended September 30, 2018 and 2017 was 2.8% and 3.4%, respectively, and our bad debt expense for the nine months ended September 30, 2018 and 2017 was 3.2% and 1.8%, respectively, of non-POR market retail revenues. As our geographic and acquisition channel mix has changed, our bad debt expense has increased. In order to manage this exposure, we have increased our focus on collection efforts in the latter part of 2017 and 2018, and focused on timely billing along with tighter credit requirements for new enrollments in non-POR markets.

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.

Our risk management policies direct that we hedge substantially all of our forecasted demand, which is typically hedged to long-term normal weather patterns. We also attempt to add additional contracts from time to time to protect us from volatility in markets where we have historically experienced higher exposure to extreme weather conditions. During the first quarter of 2018, the New England, Mid-Atlantic and Midwest regions experienced extreme unpredicted weather patterns, resulting in much higher than normal demand for electricity and natural gas, as well as prolonged periods of well-above normal prices for commodities in the day-ahead and real-time markets. This negatively impacted the gross margin for the additional commodity that we supplied to our customers above the normal-weather load we had estimated and hedged. Following that event, we entered into additional longer term hedges designed to mitigate the effects of this weather event and provide additional insurance against future extreme weather events, which have also had a negative impact on our commodity costs during 2018.

During the third quarter of 2018, we experienced warmer than normal weather across many of our markets, which increased demand for electricity from our customer base. In response to increased demand in ERCOT, we purchased additional power at elevated prices. Additionally, capacity costs in New England increased for the current capacity period, which began June 1, 2018. These factors negatively impact our results of operations for 2018.

Asset Optimization

Asset optimization opportunities primarily arise during the winter heating season when demand for natural gas is the highest. As such, the majority of our asset optimization profits are made in the winter. Given the opportunistic nature of these activities, we experience variability in our earnings from our asset optimization activities from year to year. We account for these activities using mark to-market accounting. As a result, the timing of our revenue

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recognition often differs from the actual cash settlement. As a result of the weather conditions during the first few weeks of 2018, we were unable to optimize our position as effectively as we had in the first half of 2017.

Net asset optimization results were a gain of $0.3 million for the three months ended September 30, 2018, primarily due to arbitrage opportunities we captured, offset by $0.2 million of our annual legacy demand charges during the quarter. During the full year 2018, we are obligated to pay demand charges of approximately $1.0 million under certain long-term legacy transportation assets that our predecessor entity acquired prior to 2013.

Other Performance Measures

We use Non-GAAP performance measures to evaluate and measure our operating results as follows:



	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2018		2017		2018		2017
Adjusted EBITDA	$	18,611	$	19,610	$	50,597	$	74,003
Retail Gross Margin	$	45,795	$	50,570	$	134,939	$	158,319

Adjusted EBITDA. We define “Adjusted EBITDA” as EBITDA less (i) customer acquisition costs incurred in the current period, (ii) net gain (loss) on derivative instruments, and (iii) net current period cash settlements on derivative instruments, plus (iv) non-cash compensation expense, and (v) other non-cash and non-recurring operating items. EBITDA is defined as net income before provision for income taxes, interest expense and depreciation and amortization.

We deduct all current period customer acquisition costs (representing spending for organic customer acquisitions) in the Adjusted EBITDA calculation because such costs reflect a cash outlay in the period in which they are incurred, even though we capitalize and amortize such costs over two years. The comparability of Adjusted EBITDA between periods may be affected by varying levels of customer acquisition costs. For example, our Adjusted EBITDA is lower in periods of organic customer growth reflecting larger customer acquisition spending. We do not deduct the cost of customer acquisitions through acquisitions of businesses or portfolios of customers in calculating Adjusted EBITDA.

We deduct our net gains (losses) on derivative instruments, excluding current period cash settlements, from the Adjusted EBITDA calculation in order to remove the non-cash impact of net gains and losses on derivative instruments. We also deduct non-cash compensation expense as a result of restricted stock units that are issued under our long-term incentive plan.

We believe that the presentation of Adjusted EBITDA provides information useful to investors in assessing our liquidity and financial condition and results of operations and that Adjusted EBITDA is also useful to investors as a financial indicator of our ability to incur and service debt, pay dividends and fund capital expenditures. Adjusted EBITDA is a supplemental financial measure that management and external users of our condensed consolidated financial statements, such as industry analysts, investors, commercial banks and rating agencies, use to assess the following:


•	our operating performance as compared to other publicly traded companies in the retail energy industry, without regard to financing methods, capital structure or historical cost basis;


•	the ability of our assets to generate earnings sufficient to support our proposed cash dividends; and


•	our ability to fund capital expenditures (including customer acquisition costs) and incur and service debt.

The GAAP measures most directly comparable to Adjusted EBITDA are net income and net cash provided by operating activities. The following table presents a reconciliation of Adjusted EBITDA to net income for each of the periods indicated.

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	Three Months Ended September 30,					Nine Months Ended September 30,
(in thousands)	2018		2017			2018			2017
Reconciliation of Adjusted EBITDA to Net Income:
Net income	$	18,827	$	12,942		$	923		$	28,745
Depreciation and amortization	13,917		11,509			39,797			30,435
Interest expense	2,762		2,863			7,323			8,760
Income tax expense	3,818		2,451			602			5,265
EBITDA	39,324		29,765			48,645			73,205
Less:
Net, Gain (losses) on derivative instruments	18,117		(2,752		)	(1,371		)	(34,225		)
Net, Cash settlements on derivative instruments	922		7,457			(5,823		)	18,808
Customer acquisition costs	2,695		6,568			8,949			18,642
Plus:
Non-cash compensation expense	1,021		1,118			3,707			4,023
Adjusted EBITDA	$	18,611	$	19,610		$	50,597		$	74,003

The following table presents a reconciliation of Adjusted EBITDA to net cash provided by operating activities for each of the periods indicated.



	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2018			2017			2018			2017
Reconciliation of Adjusted EBITDA to net cash provided by operating activities:
Net cash provided by operating activities	$	5,443		$	16,418		$	41,853		$	62,043
Amortization of deferred financing costs	(631		)	(219		)	(1,243		)	(750		)
Allowance for doubtful accounts and bad debt expense	(2,755		)	(2,517		)	(8,480		)	(3,436		)
Interest expense	2,762			2,863			7,323			8,760
Income tax expense	3,818			2,451			602			5,265
Changes in operating working capital
Accounts receivable, prepaids, current assets	16,248			4,457			(9,640		)	(17,084		)
Inventory	2,218			2,246			(475		)	1,936
Accounts payable and accrued liabilities	(5,946		)	(12,857		)	17,988			8,114
Other	(2,546		)	6,768			2,669			9,155
Adjusted EBITDA	$	18,611		$	19,610		$	50,597		$	74,003
Cash Flow Data:
Cash flows provided by operating activities	$	5,443		$	16,418		$	41,853		$	62,043
Cash flows provided by (used in) investing activities	$	307		$	(3,178	)	$	(23,693	)	$	(78,687	)
Cash flows provided by (used in) financing activities	$	1,344		$	(16,036	)	$	(4,783	)	$	8,933

Retail Gross Margin. We define retail gross margin as operating income plus (i) depreciation and amortization expenses and (ii) general and administrative expenses, less (iii) net asset optimization revenues, (iv) net gains (losses) on non-trading derivative instruments, and (v) net current period cash settlements on non-trading derivative instruments. Retail gross margin is included as a supplemental disclosure because it 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 non-cash income impact of our economic hedging activities. As an indicator of our retail energy business’ operating performance, retail gross margin should not be

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considered an alternative to, or more meaningful than, operating income, its most directly comparable financial measure calculated and presented in accordance with GAAP.

We believe retail gross margin provides information useful to investors as an indicator of our retail energy business's operating performance.

The GAAP measure most directly comparable to Retail Gross Margin is operating income. The following table presents a reconciliation of Retail Gross Margin to operating income for each of the periods indicated.



	Three Months Ended September 30,					Nine Months Ended September 30,
(in thousands)	2018		2017			2018			2017
Reconciliation of Retail Gross Margin to Operating Income:
Operating income	$	25,454	$	18,088		$	8,141		$	42,668
Plus:
Depreciation and amortization	13,917		11,509			39,797			30,435
General and administrative	25,695		25,566			83,522			69,405
Less:
Net asset optimization revenues (expenses)	348		(320		)	3,798			(681		)
Net, gains (losses) on non-trading derivative instruments	17,888		(2,568		)	(2,223		)	(34,146		)
Net, Cash settlements on non-trading derivative instruments	1,035		7,481			(5,054		)	19,016
Retail Gross Margin	$	45,795	$	50,570		$	134,939		$	158,319
Retail Gross Margin - Retail Electricity Segment	$	40,252	$	44,495		$	92,613		$	116,129
Retail Gross Margin - Retail Natural Gas Segment	$	5,543	$	6,075		$	42,326		$	42,190

Our non-GAAP financial measures of Adjusted EBITDA and Retail Gross Margin should not be considered as alternatives to net income, net cash provided by operating activities, or operating income. Adjusted EBITDA and Retail Gross Margin are not presentations made in accordance with GAAP and have important limitations as analytical tools. You should not consider Adjusted EBITDA or Retail Gross Margin in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA and Retail Gross Margin exclude some, but not all, items that affect net income, net cash provided by operating activities, and operating income, and are defined differently by different companies in our industry, our definition of Adjusted EBITDA and Retail Gross Margin may not be comparable to similarly titled measures of other companies.

Management compensates for the limitations of Adjusted EBITDA and Retail Gross Margin as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these data points into management’s decision-making process.

Consolidated Results of Operations

Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017

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(In Thousands)	Three Months Ended September 30,
	2018			2017			Change
Revenues:
Retail revenues	$	258,127		$	215,856		$	42,271
Net asset optimization revenues (expenses)	348			(320		)	668
Total Revenues	258,475			215,536			42,939
Operating Expenses:
Retail cost of revenues	193,409			160,373			33,036
General and administrative	25,695			25,566			129
Depreciation and amortization	13,917			11,509			2,408
Total Operating Expenses	233,021			197,448			35,573
Operating income	25,454			18,088			7,366
Other (expense)/income:
Interest expense	(2,762		)	(2,863		)	101
Interest and other income	(47		)	168			(215		)
Total other expenses	(2,809		)	(2,695		)	(114		)
Income before income tax expense	22,645			15,393			7,252
Income tax expense	3,818			2,451			1,367
Net income	$	18,827		$	12,942		$	5,885
Other Performance Metrics:
Adjusted EBITDA ⁽¹⁾	$	18,611		$	19,610		$	(999	)
Retail Gross Margin ⁽¹⁾	$	45,795		$	50,570		$	(4,775	)
Customer Acquisition Costs	$	2,695		$	6,568		$	(3,873	)
RCE Attrition	4.0		%	4.2		%	(0.2		)%

(1) Adjusted EBITDA and Retail Gross Margin are non GAAP financial measures. See " — Other Performance Measures" for a reconciliation of Adjusted EBITDA and Retail Gross Margin to their most directly comparable GAAP financial measures.

Total Revenues. Total revenues for the three months ended September 30, 2018 were approximately $258.5 million, an increase of approximately $43.0 million, or 20%, from approximately $215.5 million for the three months ended September 30, 2017, as indicated in the table below (in millions). This increase was primarily due to an increase in electricity volumes due to the acquisitions of HIKO and customers from an affiliate, warmer than normal weather across many of our service territories, and an increase in electricity prices.



Change in electricity volumes sold	$	36.1
Change in natural gas volumes sold	(2.5		)
Change in electricity unit revenue per MWh	7.8
Change in natural gas unit revenue per MMBtu	0.8
Change in net asset optimization revenue	0.8
Change in total revenues	$	43.0

Retail Cost of Revenues. Total retail cost of revenues for the three months ended September 30, 2018 was approximately $193.4 million, an increase of approximately $33.0 million, or 21%, from approximately $160.4 million for the three months ended September 30, 2017, as indicated in the table below (in millions). This increase was primarily due to an increase in electricity volumes driven by the acquisitions of HIKO and customers from an affiliate, warmer than normal weather across many of our service territories, regulatory and capacity cost changes from 2017 to 2018, and additional hedges in ERCOT we purchased to insure against elevated prices, all of which resulted in increased electricity unit cost. The increase was offset by decrease in the fair value of our retail derivative portfolio.

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Change in electricity volumes sold	$	28.2
Change in natural gas volumes sold	(1.4		)
Change in electricity unit cost per MWh	19.9
Change in natural gas unit cost per MMBtu	0.3
Change in value of retail derivative portfolio	(14.0		)
Change in retail cost of revenues	$	33.0

General and Administrative Expense. General and administrative expense for the three months ended September 30, 2018 was approximately $25.7 million, an increase of approximately $0.1 million, or 0%, as compared to $25.6 million for the three months ended September 30, 2017. This increase was primarily attributable to variable costs associated with increased RCEs as a result of the acquisition of HIKO and increased commissions paid to commercial brokers. In addition, the third quarter of 2017 benefited from an adjustment to reduce the fair value of earnout liabilities, which decreased general and administrative expenses in 2017 and did not recur in 2018.

Depreciation and Amortization Expense. Depreciation and amortization expense for the three months ended September 30, 2018 was approximately $13.9 million, an increase of approximately $2.4 million, or 21%, from approximately $11.5 million for the three months ended September 30, 2017. This increase was primarily due to the increased amortization expense associated with customer intangibles from the acquisitions of HIKO and customers from an affiliate, and the write-off of assets no longer in use as a result of integration activities.

Customer Acquisition Cost. Customer acquisition cost for the three months ended September 30, 2018 was approximately $2.7 million, a decrease of approximately $3.9 million, or 59%, from approximately $6.6 million for the three months ended September 30, 2017. This decrease was primarily due to a decrease in the number of organic sales in 2018 as we were more focused on acquisitions of businesses, customer portfolio additions, and integration.

Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017

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(In Thousands)	Nine Months Ended September 30,
	2018			2017			Change
Revenues:
Retail revenues	$	773,616		$	563,960		$	209,656
Net asset optimization expenses	3,798			(681		)	4,479
Total Revenues	777,414			563,279			214,135
Operating Expenses:
Retail cost of revenues	645,954			420,771			225,183
General and administrative	83,522			69,405			14,117
Depreciation and amortization	39,797			30,435			9,362
Total Operating Expenses	769,273			520,611			248,662
Operating income	8,141			42,668			(34,527		)
Other (expense)/income:
Interest expense	(7,323		)	(8,760		)	1,437
Interest and other income	707			102			605
Total other expenses	(6,616		)	(8,658		)	2,042
Income before income tax expense	1,525			34,010			(32,485		)
Income tax (benefit) expense	602			5,265			(4,663		)
Net income	$	923		$	28,745		$	(27,822	)
Other Performance Metrics:
Adjusted EBITDA ⁽¹⁾	$	50,597		$	74,003		$	(23,406	)
Retail Gross Margin ⁽¹⁾	$	134,939		$	158,319		$	(23,380	)
Customer Acquisition Costs	$	8,949		$	18,642		$	(9,693	)
RCE Attrition	4.0		%	4.0		%	—		%

Total Revenues. Total revenues for the nine months ended September 30, 2018 were approximately $777.4 million, an increase of approximately $214.1 million, or 38%, from approximately $563.3 million for the nine months ended September 30, 2017, as indicated in the table below (in millions). This increase was primarily due to an increase in electricity volumes driven by the acquisitions of the Verde Companies, HIKO and customers from an affiliate, commercial growth in 2017, and higher-than-normal electricity and natural gas pricing in 2018, partially offset by a decrease in natural gas volumes due to warmer-than-normal weather in the second and third quarters of 2018.



Change in electricity volumes sold	$	189.5
Change in natural gas volumes sold	(4.9		)
Change in electricity unit revenue per MWh	19.1
Change in natural gas unit revenue per MMBtu	5.9
Change in net asset optimization revenue (expense)	4.5
Change in total revenues	$	214.1

Retail Cost of Revenues. Total retail cost of revenues for the nine months ended September 30, 2018 was approximately $646.0 million, an increase of approximately $225.2 million, or 54%, from approximately $420.8 million for the nine months ended September 30, 2017, as indicated in the table below (in millions). This increase was primarily due to an increase in electricity volumes driven by the acquisitions of the Verde Companies, HIKO and customers from an affiliate, commercial growth in 2017, higher-than-normal electricity and natural gas prices

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due to the extreme unpredictable weather in the first quarter of 2018, as well as by regulatory changes, increased capacity costs in the second and third quarter of 2018, and additional hedges in ERCOT in the third quarter of 2018.



Change in electricity volumes sold	$	142.5
Change in natural gas volumes sold	(2.8		)
Change in electricity unit cost per MWh	89.7
Change in natural gas unit cost per MMBtu	3.6
Change in value of retail derivative portfolio	(7.8		)
Change in retail cost of revenues	$	225.2

General and Administrative Expense. General and administrative expense for the nine months ended September 30, 2018 was approximately $83.5 million, an increase of approximately $14.1 million, or 20%, as compared to $69.4 million for the nine months ended September 30, 2017. This increase was primarily attributable to variable costs associated with increased RCEs as a result of the acquisition of the Verde Companies and HIKO, increased commissions paid to commercial brokers, and costs related to customer acquisition activities for the Verde Companies that we cannot capitalize. In addition, the first three quarters of 2017 benefited from adjustments to reduce the fair value of earnout liabilities, which decreased general and administrative expenses in 2017 and did not recur in 2018.

Depreciation and Amortization Expense. Depreciation and amortization expense for the nine months ended September 30, 2018 was approximately $39.8 million, an increase of approximately $9.4 million, or 31%, from approximately $30.4 million for the nine months ended September 30, 2017. This increase was primarily due to the increased amortization expense associated with customer relationship intangibles from the acquisitions of the Verde Companies, HIKO and customers from an affiliate, and the write-off of assets no longer in use as a result of integration activities.

Customer Acquisition Cost. Customer acquisition cost for the nine months ended September 30, 2018 was approximately $8.9 million, a decrease of approximately $9.7 million, or 52%, from approximately $18.6 million for the nine months ended September 30, 2017. This decrease was primarily due to a decrease in the number of organic sales in 2018 as we were more focused on acquisitions of businesses, customer portfolio additions, and integration.

Operating Segment Results

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	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
	(in thousands, except volume and per unit operating data)
Retail Electricity Segment
Total Revenues	$	246,182		$	202,259		$	676,528		$	467,861
Retail Cost of Revenues	186,449			153,594			587,949			364,518
Less: Net gains (losses) on non-trading derivatives, net of cash settlements	19,481			4,170			(4,034		)	(12,786		)
Retail Gross Margin⁽¹⁾ — Electricity	$	40,252		$	44,495		$	92,613		$	116,129
Volumes — Electricity (MWhs)	2,432,314			2,063,894			6,784,345			4,828,629
Retail Gross Margin ⁽²⁾— Electricity per MWh	$	16.55		$	21.56		$	13.65		$	24.05

Retail Natural Gas Segment
Total Revenues	12,293			13,277			100,886			95,418
Retail Cost of Revenues	6,960			6,779			58,005			56,253
Less: Net Asset Optimization Revenues (Expenses)	348			(320		)	3,798			(681		)
Less: Net gains (losses) on non-trading derivatives, net of cash settlements	(558		)	743			(3,243		)	(2,344		)
Retail Gross Margin ⁽¹⁾— Gas	$	5,543		$	6,075		$	42,326		$	42,190
Volumes — Gas (MMBtus)	1,395,377			1,706,132			11,913,180			12,554,497
Retail Gross Margin ⁽²⁾— Gas per MMBtu	$	3.97		$	3.56		$	3.55		$	3.36

(1) Reflects the Retail Gross Margin attributable to our Retail Electricity Segment or Retail Natural Gas Segment, as applicable. Retail Gross Margin is a non GAAP financial measure. See " — Other Performance Measures" for a reconciliation of Retail Gross Margin to most directly comparable financial measure presented in accordance with GAAP.


(2)	Reflects the Retail Gross Margin for the Retail Electricity Segment or Retail Natural Gas Segment, as applicable, divided by the total volumes in MWh or MMBtu, respectively.

Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017

Retail Electricity Segment

Total revenues for the Retail Electricity Segment for the three months ended September 30, 2018 were approximately $246.2 million, an increase of approximately $43.9 million, or 22%, from approximately $202.3 million for the three months ended September 30, 2017. This increase was largely due to an increase in volumes. Our volumes were higher year-over-year because of our commercial growth during 2017, our acquisitions of HIKO and customers from an affiliate, and warmer than normal weather across much of our service territories during the third quarter of 2018, resulting in an increase of $36.1 million. This increase was further impacted by a higher electricity pricing environment, which resulted in an increase of $7.8 million.

Retail cost of revenues for the Retail Electricity Segment for the three months ended September 30, 2018 were approximately $186.4 million, an increase of approximately $32.8 million, or 21%, from approximately $153.6 million for the three months ended September 30, 2017. This increase was primarily due to an increase in volumes as a result of the acquisitions of HIKO and customers from an affiliate, commercial growth during 2017, and warmer than normal weather across much of our service territory, resulting in an increase of $28.2 million. Our supply costs also increased by $19.9 million as a result of hedges with longer terms that we purchased in early 2018 and as a result of increased capacity costs and regulatory changes, and additional hedges we purchased in ERCOT for the third quarter. We also recognized a change in the value of our retail derivative portfolio used for hedging, which resulted in a decrease of $15.3 million.

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Retail gross margin for the Retail Electricity Segment for the three months ended September 30, 2018 was approximately $40.3 million, a decrease of approximately $4.2 million, or 10%, from approximately $44.5 million for the three months ended September 30, 2017, as indicated in the table below (in millions).



Change in volumes sold	$	7.9
Change in unit margin per MWh	(12.1		)
Change in retail electricity segment retail gross margin	$	(4.2	)

Retail Natural Gas Segment

Total revenues for the Retail Natural Gas Segment for the three months ended September 30, 2018 were approximately $12.3 million, a decrease of approximately $0.9 million, or 7%, from approximately $13.2 million for the three months ended September 30, 2017. This decrease was primarily attributable to an increase of $0.7 million in net asset optimization revenues, and higher rates, which resulted in an increase in total revenues of $0.8 million, and decreased volumes, which decreased total revenues by $2.5 million.

Retail cost of revenues for the Retail Natural Gas Segment for the three months ended September 30, 2018 were approximately $7.0 million, an increase of $0.2 million, or 3%, from approximately $6.8 million for the three months ended September 30, 2017. This increase was primarily due to a change in the value of our derivative portfolio used for hedging, which resulted in an increase of $1.3 million, and higher natural gas prices, which resulted in an increase of $0.3 million. This was partially offset by a decrease of $1.4 million in volumes.

Retail gross margin for the Retail Natural Gas Segment for the three months ended September 30, 2018 was approximately $5.5 million, a decrease of approximately $0.6 million, or 9%, from approximately $6.1 million for the three months ended September 30, 2017, as indicated in the table below (in millions).



Change in volumes sold	$	(1.1	)
Change in unit margin per MMBtu	0.5
Change in retail natural gas segment retail gross margin	$	(0.6	)

Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017

Retail Electricity Segment

Total revenues for the Retail Electricity Segment for the nine months ended September 30, 2018 were approximately $676.5 million, an increase of approximately $208.6 million, or 45%, from approximately $467.9 million for the nine months ended September 30, 2017. This increase was largely due to an increase in volumes, a result of our acquisitions of the Verde Companies, HIKO and customers from an affiliate, commercial growth in 2017, extreme cold weather in the first quarter of 2018, and warmer than normal weather in the second and third quarters of 2018 resulting in an increase of $189.5 million. This increase was further impacted by the higher electricity pricing environment, which resulted in an increase of $19.1 million.

Retail cost of revenues for the Retail Electricity Segment for the nine months ended September 30, 2018 was approximately $587.9 million, an increase of approximately $223.4 million, or 61%, from approximately $364.5 million for the nine months ended September 30, 2017. This increase was primarily due to an increase in volumes as a result of the acquisitions of the Verde Companies, HIKO and customers from an affiliate, commercial growth in 2017, extreme cold weather in the first quarter of 2018, and warmer than normal weather in second and third quarter of 2018, resulting in an increase of $142.5 million. This increase was further impacted by increased electricity prices, REC requirements and capacity costs, which resulted in an increase in retail cost of revenues of $89.7 million. Additionally, there was a decrease of $8.8 million due to a change in the value of our retail derivative portfolio used for hedging.

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Retail gross margin for the Retail Electricity Segment for the nine months ended September 30, 2018 was approximately $92.6 million, a decrease of approximately $23.5 million, or 20%, from approximately $116.1 million for the nine months ended September 30, 2017, as indicated in the table below (in millions).



Change in volumes sold	$	47.0
Change in unit margin per MWh	(70.5		)
Change in retail electricity segment retail gross margin	$	(23.5	)

Retail Natural Gas Segment

Total revenues for the Retail Natural Gas Segment for the nine months ended September 30, 2018 were approximately $100.9 million, an increase of approximately $5.5 million, or 6%, from approximately $95.4 million for the nine months ended September 30, 2017. This increase was primarily attributable to higher rates, which resulted in an increase in total revenues of $5.9 million, and an increase of $4.5 million in net optimization revenues. This was offset by a decrease in volumes of $4.9 million.

Retail cost of revenues for the Retail Natural Gas Segment for the nine months ended September 30, 2018 was approximately $58.0 million, an increase of approximately $1.7 million, or 3%, from approximately $56.3 million for the nine months ended September 30, 2017. This increase was due to increased supply costs of $3.6 million and a $0.9 million change in the fair value of our retail derivative portfolio used for hedging, offset by a decrease of $2.8 million related to decreased volume.

Retail gross margin for the Retail Natural Gas Segment for the nine months ended September 30, 2018 was approximately $42.3 million, an increase of approximately $0.1 million, or 0%, from approximately $42.2 million for the nine months ended September 30, 2017, as indicated in the table below (in millions).



Change in volumes sold	$	(2.2	)
Change in unit margin per MMBtu	2.3
Change in retail natural gas segment retail gross margin	$	0.1

Liquidity and Capital Resources

Overview

Our primary sources of liquidity are cash generated from operations and borrowings under our Senior Credit Facility. Our principal liquidity requirements are to meet our financial commitments, finance current operations, fund organic growth and/or acquisitions, service debt and pay dividends. Our liquidity requirements fluctuate with our customer acquisition costs, acquisitions, collateral posting requirements on our derivative instruments portfolio, distributions, the effects of the timing between payments of payables and receipts of receivables, including bad debt receivables, weather conditions, and our general working capital needs for ongoing operations. We believe that cash generated from operations and our available liquidity sources will be sufficient to sustain current operations and to pay required taxes and quarterly cash distributions, including the quarterly dividends to the holders of the Class A common stock and the Series A Preferred Stock, for the next twelve months. We believe that the financing of any additional growth through acquisitions or the need for more liquidity in 2018, may require further equity or debt financing and/or further expansion of our Senior Credit Facility. Estimating our liquidity requirements is highly dependent on then-current market conditions, including forward prices for natural gas and electricity, and market volatility.

Liquidity Position

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The following table details our available liquidity as of the date presented:



($ in thousands)	September 30, 2018
Cash and cash equivalents	$	42,796
Senior Credit Facility Availability	19,281
Subordinated Debt Availability ⁽¹⁾	15,000
Total Liquidity	$	77,077

(1) The availability of the Subordinated Facility is dependent on our Founder's financial position and liquidity. See"— Subordinated Debt Facility."

Borrowings and related posting of letters of credit under our Senior Credit Facility are subject to material variations on a seasonal basis due to the timing of commodity purchases to satisfy natural gas inventory requirements and to meet customer demands during periods of peak usage. Additionally, borrowings are subject to borrowing base and covenant restrictions.

We generally experience lower levels of liquidity in the first quarter of our fiscal year. In early 2018, the northeast experienced colder than normal weather conditions. This weather event created increased collateral requirements in the Northeast for us. As a result, we took steps to increase our liquidity, including exercising the accordion feature under our Senior Credit Facility and issuing additional Preferred Stock. For further discussion of our Senior Credit Facility and related restrictions, see Note 9 "Debt."

Cash Flows

Our cash flows were as follows for the respective periods (in thousands):



	Nine Months Ended September 30,
	2018			2017			Change
Net cash provided by operating activities	$	41,853		$	62,043		$	(20,190	)
Net cash used in investing activities	$	(23,693	)	$	(78,687	)	$	54,994
Net cash (used in) provided by financing activities	$	(4,783	)	$	8,933		$	(13,716	)

Nine Months Ended September 30, 2018 Compared to the Nine Months Ended September 30, 2017

Cash Flows Provided by Operating Activities. Cash flows provided by operating activities for the nine months ended September 30, 2018 decreased by $20.2 million compared to the nine months ended September 30, 2017. The decrease was primarily the result of a decrease in the changes in working capital for the nine months ended September 30, 2018.

Cash Flows Used in Investing Activities. Cash flows used in investing activities decreased by $55.0 million for the nine months ended September 30, 2018. The decrease was primarily the result of the $65.8 million acquisition of the Verde Companies during the nine months ended September 30, 2017, offset by the acquisitions of HIKO of $14.3 million and customers from an affiliate of $8.8 million during the nine months ended September 30, 2018.

Cash Flows Used in Financing Activities. Cash flows used in financing activities increased by $13.7 million for the nine months ended September 30, 2018. The increase in cash flows used in financing activities was primarily due to increased net paydown of our Senior Credit Facility, additional dividends paid to holders of Series A Preferred Stock, and payments related to the Verde Promissory Note for the nine months ended September 30, 2018.

Sources of Liquidity and Capital Resources

Senior Credit Facility

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We currently have total commitments under our Senior Credit Facility of $192.5 million, of which $173.2 million is outstanding as of September 30, 2018, including $61.2 million of outstanding letters of credit. Under the Senior Credit Facility, as amended, we have various limits on advances for Working Capital Loans, Letters of Credit and Bridge Loans. The Senior Credit Facility matures on May 19, 2020.

For a description of the terms and conditions of our Senior Credit Facility, including descriptions of the interest rate, commitment fee, covenants and terms of default, please see Note 9 "Debt" in the notes to our condensed consolidated financial statements. As of September 30, 2018, we were in compliance with the covenants under our Senior Credit Facility.

Shelf Registration Statement

On October 7, 2016, we filed a registration statement under the Securities Act on Form S-3 covering offers and sales, from time to time, by us of up to $200,000,000 of Class A common stock, preferred stock, depositary shares and warrants, and by the selling stockholders named therein of up to 22,679,126 shares of Class A common stock (the "Shelf Registration Statement"). The Shelf Registration Statement was declared effective on October 20, 2016.

Series A Preferred Stock Issuances

On January 26, 2018, the Company issued 2,000,000 shares of Series A Preferred Stock from the Shelf Registration Statement and received net proceeds from the offering of approximately $48.9 million (net of underwriting discounts, commissions and a structuring fee).

At-the-Market Sales Agreement

We have an at-the-market sales agreement (the "ATM Agreement") that enables us to sell our Series A Preferred Stock, from time to time, having an aggregate offering price of up to $50.0 million under the Shelf Registration Statement. We intend to use the proceeds from any sales pursuant to the ATM Agreement, after deducting the sales agent’s commissions and our offering expenses, for general corporate purposes, which may include, among other things, funding working capital, capital expenditures, liquidity for operational contingencies, debt repayments and acquisitions.

During the nine months ended September 30, 2018, we sold an aggregate of 2,917 shares of Series A Preferred Stock under the ATM Agreement. We received net proceeds of $0.1 million and paid compensation to the sales agent of less than $0.1 million with respect to these sales.

Subordinated Debt Facility

Our Subordinated Facility allows us and Spark HoldCo to draw advances in increments of no less than $1.0 million per advance up to $25.0 million. See Note 9 "Debt" for additional details.

We may use the Subordinated Facility from time to time to enhance short term liquidity, but we do not view the Subordinated Facility as a material source of liquidity. As of September 30, 2018, there was $10.0 million outstanding borrowings under the Subordinated Facility, which was repaid in October 2018.

Uses of Liquidity and Capital Resources

Repayment of Current Portion of Senior Credit Facility

Repayment of the $7.5 million current portion of our Senior Credit Facility due in 2018 was made with proceeds of the offering of our Series A Preferred Stock in January 2018.

Customer Acquisitions

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Our customer acquisition strategy consists of customer growth obtained through opportunistic acquisitions complemented by traditional organic customer acquisitions.

Capital Expenditures

Capital expenditures for the nine months ended September 30, 2018 included approximately $8.9 million for customer acquisitions and $1.1 million related to information systems improvements.

Dividends

The Spark HoldCo, LLC Agreement provides, to the extent cash is available, for distributions pro rata to the holders of Spark HoldCo units such that we receive an amount of cash sufficient to cover the estimated taxes payable by us, the targeted quarterly dividend we intend to pay to holders of our Class A common stock, the quarterly dividends on our Series A Preferred Stock, and payments under the Tax Receivable Agreement we have entered into with Spark HoldCo, Retailco and NuDevco Retail.

During the nine months ended September 30, 2018, we paid dividends to holders of our Class A common stock for the three months ended December 31, 2017, March 31, 2018, and June 30, 2018 of approximately $0.18125 per share for each dividend declaration or $7.2 million in the aggregate. On October 18, 2018, our Board of Directors declared a quarterly dividend of $0.18125 per share of the Class A common stock for the third quarter of 2018. This dividend will be paid on December 14, 2018 to the holders of record as of November 30, 2018. Our ability to pay dividends in the future will depend on many factors, including the performance of our business in the future and restrictions under our Senior Credit Facility. The financial covenants included in the Senior Credit Facility require us to retain increasing amounts of working capital over time, which may have the effect of restricting our ability to pay dividends. Management does not currently believe that the financial covenants in the Senior Credit Facility will cause any such restrictions.

In order to pay our stated dividends to holders of our Class A common stock, Spark HoldCo is required to make corresponding distributions to holders of our non-controlling interest. As such, Spark HoldCo generally is required to distribute approximately $15.6 million on an annualized basis to Retailco, holder of Spark HoldCo units. If our business does not generate sufficient cash for Spark HoldCo to make such distributions, we may have to borrow to pay our dividend. If our business generates cash in excess of the annual dividend (currently $0.725 per share of Class A common stock), we expect to reinvest such excess cash flows into our business and not increase the dividends payable to holders of our Class A common stock. Our future dividend policy is within the discretion of our Board of Directors and will depend upon various factors, including the results of our operations, our financial condition, capital requirements and investment opportunities.

For the nine months ended September 30, 2018, we paid $5.0 million related to dividends to holders of Series A Preferred Stock. As of September 30, 2018, we had accrued $2.0 million related to dividends to holders of our Series A Preferred Stock, which was paid on October 15, 2018. On October 18, 2018, our Board of Directors declared a quarterly cash dividend in the amount of $0.546875 per share on the Series A Preferred Stock. The dividend will be paid on January 15, 2019 to holders of record on January 1, 2019. For the full year ended December 31, 2018, we anticipate Series A Preferred Stock dividends of $2.1875 per share, or $8.1 million in the aggregate based on the Series A Preferred Stock outstanding as of September 30, 2018.

Tax Receivable Agreement

We are required to make payments under a Tax Receivable Agreement that we have entered into with Retailco LLC (as assignee of NuDevco Retail Holdings), NuDevco Retail and Spark HoldCo in connection with our initial public offering ("IPO"). Except in cases where we elect to terminate the Tax Receivable Agreement early (or the Tax Receivable Agreement is terminated early due to certain mergers or other changes of control) or we have available cash but fail to make payments when due, we may request to defer payments due under the Tax Receivable

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Agreement for up to five years if we do not have available cash to satisfy our payment obligations or if our contractual obligations limit our ability to make these payments. Any such deferred payments under the Tax Receivable Agreement generally will accrue interest. If we were to defer substantial payment obligations under the Tax Receivable Agreement on an ongoing basis, the accrual of those obligations would reduce the availability of cash for other purposes, but we would not be prohibited from paying dividends on our Class A common stock.

For the nine months ended September 30, 2018, we paid a total of $3.6 million related to TRA payments for the 2015 and 2016 tax years. We met the threshold coverage ratio required to fund the payment under the Tax Receivable Agreement during the four-quarter period ending September 30, 2018, resulting in related TRA Payment for the 2017 tax year being due in January of 2019. We have classified $2.5 million and $5.9 million as a current liability in our consolidated balance sheet at September 30, 2018 and December 31, 2017, respectively. A TRA payment for the 2017 tax year of $2.3 million was made in October 2018, and the remainder of the current portion of the liability as of September 30, 2018 will be due in January 2019. See Note 14 "Transactions with Affiliates" in the notes to our condensed consolidated financial statements for additional details on the Tax Receivable Agreement.

On December 22, 2017, the President signed the Tax Cuts and Jobs Act (“U.S. Tax Reform”), which enacts a wide range of changes to the U.S. Corporate income tax system. For U.S. federal purposes, a corporate statutory income tax rate of 21% was utilized for the 2018 tax year. We remeasured our U.S. federal deferred tax assets and liabilities as of December 31, 2017 using the newly enacted 21% corporate tax rate, the rate expected to be applied when the temporary differences are settled.

Verde Companies Promissory Note

In July 2017, our subsidiary entered into a Promissory Note in the aggregate principal amount of $20.0 million in connection with the Verde acquisition (the "Verde Promissory Note"). The Verde Promissory Note required eighteen monthly installments beginning on August 1, 2017, and accrued interest at 5% per annum from the date of issuance. On January 12, 2018, in connection with the Earnout Termination Agreement (defined below), CenStar issued to the seller of the Verde Companies an amended and restated promissory note (the “Amended and Restated Verde Promissory Note”), which amended and restated the Verde Promissory Note. The Amended and Restated Verde Promissory Note, effective January 12, 2018, matures in January 2019, and bears interest at a rate of 9% per annum beginning January 1, 2018. Principal and interest are payable monthly on the first day of each month in which the Amended and Restated Verde Promissory Note is outstanding. CenStar deposits a portion of each payment under the Amended and Restated Verde Promissory Note into an escrow account, which serves as security for certain indemnification claims and obligations under the purchase agreement. The amount deposited into the escrow account was increased from the amount previously deposited in connection with the Verde Promissory Note. As of December 31, 2017, there was $14.6 million outstanding under the Verde Promissory note, and as of September 30, 2018, there was $4.6 million outstanding under the Amended and Restated Verde Promissory Note.

Verde Earnout Termination Note

On January 12, 2018, we issued a promissory note in the principal amount of $5.9 million in connection with an agreement to terminate the earnout obligation arising in connection with our acquisition of the Verde Companies. The note matures on June 30, 2019 (subject to early maturity upon certain events) and bears interest at a rate of 9% per annum. CenStar is permitted to withhold amounts otherwise due at maturity related to certain indemnifiable matters. Interest is payable monthly on the first day of each month in which the note is outstanding.

Ongoing Obligations in Connection with Acquisitions

We are obligated to make earnout and installment payments in connection with the acquisition of the Major Energy Companies, as more fully described in this Quarterly Report on Form 10-Q. Maximum payments under this agreement could have been as much as $35 million depending upon operating results and the customer counts through the end of 2018. Based on results to date, however, we expect these payments will be significantly less than

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the maximum. See further discussion related to the valuation of the earnouts in Note 10 "Fair Value Measurements" to our quarterly financial statements included herein.

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Off-Balance Sheet Arrangements

As of September 30, 2018, we had no material off-balance sheet arrangements.

Related Party Transactions

For a discussion of related party transactions, see Note 14 "Transactions with Affiliates" in the unaudited condensed consolidated financial statements.

Critical Accounting Policies and Estimates

Our critical accounting policies and estimates are described in “Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” in our Annual Report on Form 10-K for the year ended December 31, 2017. There have been no changes to these policies and estimates since the date of our Annual Report on Form 10-K for the year ended December 31, 2017.

Refer to Note 2 "Basis of Presentation and Summary of Significant Accounting Policies" for a discussion on recent accounting pronouncements.

Contingencies

In the ordinary course of business, we may become party to lawsuits, administrative proceedings and governmental investigations, including regulatory and other matters. Except as described in Note 13 "Commitments and Contingencies," as of September 30, 2018, management does not believe that any of our outstanding lawsuits, administrative proceedings or investigations could result in a material adverse effect. Liabilities for loss contingencies arising from claims, assessments, litigation, fines, penalties and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. For a discussion of the status of current litigation and governmental investigations, see Note 13 "Commitments and Contingencies" in our unaudited condensed consolidated financial statements.

Emerging Growth Company Status

We are an “emerging growth company” within the meaning of the federal securities laws. For as long as we are an emerging growth company, we will not be required to comply with certain requirements that are applicable to other public companies that are not “emerging growth companies” including, but not limited to, not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act, the reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements and the exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and stockholder approval of any golden parachute payments not previously approved. In addition, Section 107 of the JOBS Act provides that an emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards, but we have irrevocably opted out of the extended transition period and, as a result, we will adopt new or revised accounting standards on the relevant dates on which adoption of such standards is required for other public companies.

We intend to take advantage of these exemptions until we are no longer an emerging growth company. We will cease to be an “emerging growth company” upon the earliest of: (i) the last day of the fiscal year in which we have $1.07 billion or more in annual revenues; (ii) the date on which we become a “large accelerated filer” (the fiscal year-end on which the total market value of our common equity securities held by non-affiliates is $700 million or more as of June 30); (iii) the date on which we issue more than $1.0 billion of non-convertible debt over a three-year period; or (iv) the last day of 2019.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market risks relating to our operations result primarily from changes in commodity prices and interest rates, as well as counterparty credit risk. We employ established policies and procedures to manage our exposure to these risks.

Commodity Price Risk

We hedge and procure our energy requirements from various wholesale energy markets, including both physical and financial markets and through short and long term contracts. Our financial results are largely dependent on the margin we are able to realize between the wholesale purchase price of natural gas and electricity plus related costs and the retail sales price we charge our customers for these commodities. We actively manage our commodity price risk by entering into various derivative or non-derivative instruments to hedge the variability in future cash flows from fixed-price forecasted sales and purchases of natural gas and electricity in connection with our retail energy operations. These instruments include forwards, futures, swaps, and option contracts traded on various exchanges, such as NYMEX and Intercontinental Exchange, or ICE, as well as over-the-counter markets. These contracts have varying terms and durations, which range from a few days to several years, depending on the instrument. We also utilize similar derivative contracts in connection with our asset optimization activities to attempt to generate incremental gross margin by effecting transactions in markets where we have a retail presence. Our net gain (loss) on our non-trading derivative instruments net of cash settlements was $18.9 million and $4.9 million for the three months ended September 30, 2018 and 2017, respectively, and $(7.3) million and $(15.1) million for the nine months ended September 30, 2018 and 2017, respectively.

We have adopted risk management policies to measure and limit market risk associated with our fixed-price portfolio and our hedging activities. For additional information regarding our commodity price risk and our risk management policies, see “Item 1A—Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2017.

We measure the commodity risk of our non-trading energy derivatives using a sensitivity analysis on our net open position. As of September 30, 2018, our Gas Non-Trading Fixed Price Open Position (hedges net of retail load) was a short position of 469,684 MMBtu. An increase of 10% in the market prices (NYMEX) from their September 30, 2018 levels would have increased the fair market value of our net non-trading energy portfolio by $0.1 million. Likewise, a decrease of 10% in the market prices (NYMEX) from their September 30, 2018 levels would have decreased the fair market value of our non-trading energy derivatives by $0.1 million. As of September 30, 2018, our Electricity Non-Trading Fixed Price Open Position (hedges net of retail load) was a long position of 11,631 MWhs. An increase of 10% in the forward market prices from their September 30, 2018 levels would have increased the fair market value of our net non-trading energy portfolio by $0.2 million. Likewise, a decrease of 10% in the forward market prices from their September 30, 2018 levels would have decreased the fair market value of our non-trading energy derivatives by $0.2 million.

Credit Risk

In many of the utility services territories where we conduct business, POR programs have been established, whereby the local regulated utility purchases our receivables, and becomes responsible for billing the customer and collecting payment from the customer. 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 69% and 68% of our retail revenues were derived from territories in which substantially all of our credit risk was directly linked to local regulated utility companies for the three and nine months ended September 30, 2018, all of which had investment grade ratings as of such date. During the same period, we paid these local regulated utilities a weighted average discount of approximately 0.9% and 1.0%, respectively, of total revenues for customer credit risk protection. 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.

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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.

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 score screening, deposits and disconnection for non-payment, in the case of residential customers. Economic conditions may affect 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. Our bad debt expense for the three and nine months ended September 30, 2018 was approximately 2.8% and 3.2%, respectively, of non-POR market retail revenues. See “Management's Discussion and Analysis of Financial Condition and Results of Operations—Drivers of Our Business” for an analysis of our bad debt expense related to non-POR markets during the nine months ended September 30, 2018.

We are exposed to wholesale counterparty credit risk in our retail and asset optimization activities. We manage this risk at a counterparty level and secure our exposure with collateral or guarantees when needed. At September 30, 2018, approximately $2.7 million of our total exposure of $22.1 million was either with a non-investment grade counterparty or otherwise not secured with collateral or a guarantee.

Interest Rate Risk

We are exposed to fluctuations in interest rates under our variable-price debt obligations. At September 30, 2018, we were co-borrowers under the Senior Credit Facility, under which $112.0 million of variable rate indebtedness was outstanding. Based on the average amount of our variable rate indebtedness outstanding during the three months ended September 30, 2018, a 1% increase in interest rates would have resulted in additional annual interest expense of approximately $1.1 million. During the three months ended September 30, 2018, we entered into two interest rate swap agreements to manage interest rate risk.

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ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our Chief Executive Officer and our Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10-Q. The term “disclosure controls and procedures,” as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to our management, including our principal executive and principal financial officers or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving their objectives and management necessarily applies its judgment in evaluating the cost benefit relationship of possible controls and procedures. Based on this evaluation, management concluded that our disclosure controls and procedures were effective as of September 30, 2018 at a reasonable assurance level.

Changes in Internal Control over Financial Reporting

There was no change in our internal control over financial reporting identified in connection with the evaluation required by Rule 13a-15(d) and 15d-15(d) of the Exchange Act that occurred during the three months ended September 30, 2018 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

See Part I, Financial Information, Note 13 "Commitments and Contingencies."

Item 1A. Risk Factors.

Security holders and potential investors in our securities should carefully consider the risk factors under "Item 1A— Risk Factors" in our 2017 Annual Report on Form 10-K and in our Quarterly Report on Form 10-Q for the first quarter of 2018, which are incorporated herein by reference. There has been no material change in our risk factors from those described in the 2017 Annual Report on Form 10-K and our Quarterly Report on Form 10-Q for the first quarter of 2018. Our description of risks are not the sole risks for investors. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or results of operations.

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

None.

Item 3. Defaults Upon Senior Securities.

None.

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

Not applicable.

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Item 6. Exhibits
		Incorporated by Reference
Exhibit	Exhibit Description	Form	Exhibit Number		Filing Date	SEC File No.
2.1#	Membership Interest Purchase Agreement, by and among Spark Energy, Inc., Spark HoldCo, LLC, Provider Power, LLC, Kevin B. Dean and Emile L. Clavet, dated as of May 3, 2016.	10-Q		2.1	5/5/2016	001-36559
2.2#	Membership Interest Purchase Agreement, by and among Spark Energy, Inc., Spark HoldCo, LLC, Retailco, LLC and National Gas & Electric, LLC, dated as of May 3, 2016.	10-Q		2.2	5/5/2016	001-36559
2.3#	Amendment No. 1 to the Membership Interest Purchase Agreement, dated as of July 26, 2016, by and among Spark Energy, Inc., Spark HoldCo, LLC, Provider Power, LLC, Kevin B. Dean and Emile L. Clavet.	8-K		2.1	8/1/2016	001-36559
2.4#	Membership Interest and Stock Purchase Agreement, by and among Spark Energy, Inc., CenStar Energy Corp. and Verde Energy USA Holdings, LLC, dated as of May 5, 2017.	10-Q		2.4	5/8/2017	001-36559
2.5	First Amendment to the Membership Interest and Stock Purchase Agreement, dated July 1, 2017, by and among Spark Energy, Inc., CenStar Energy Corp., and Verde Energy USA Holdings, LLC.	8-K		2.1	7/6/2017	001-36559
2.6#	Agreement to Terminate Earnout Payments, effective January 12, 2018, by and among Spark Energy, Inc., CenStar Energy Corp., Woden Holdings, LLC (fka Verde Energy USA Holdings, LLC), Verde Energy USA, Inc., Thomas FitzGerald, and Anthony Mench.	8-K		2.1	1/16/2018	001-36559
2.7#	Asset Purchase Agreement, dated March 7, 2018, by and between Spark HoldCo, LLC and National Gas & Electric, LLC.	10-K		2.7	3/9/2018	001-36559
2.8#	Asset Purchase Agreement, by and between Spark HoldCo, LLC, Starion Energy Inc., Starion Energy NY Inc., and Starion Energy PA Inc., dated October 19, 2018.	8-K		2.1	10/25/2018	001-36559
3.1	Amended and Restated Certificate of Incorporation of Spark Energy, Inc.	8-K		3.1	8/4/2014	001-36559
3.2	Amended and Restated Bylaws of Spark Energy, Inc.	8-K		3.2	8/4/2014	001-36559
3.3	Certificate of Designations of Rights and Preferences of 8.75% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Stock	8-A		5	3/14/2017	001-36559
4.1	Class A Common Stock Certificate	S-1		4.1	6/30/2014	333-196375
10.1	Amendment No. 2 to the Credit Agreement, dated as of July 17, 2018, by and among Spark Energy, Inc., the Co-Borrowers, the Banks party thereto, and Brown Brothers Harriman & Co., as exiting bank.	8-K		10.1	7/20/2018	001-36559
10.2 †	Amended Employment Agreement between Spark Energy, Inc. and Nathan Kroeker dated August 1, 2018.	10-Q		10.2	8/3/2018	001-36559
10.3 †	Amended and Restated Employment Agreement between Spark Energy, Inc. and Jason Garrett dated August 1, 2018.	10-Q		10.3	8/3/2018	001-36559
10.4 †	Amended and Restated Employment Agreement between Spark Energy, Inc. and Gil Melman dated August 1, 2018.	10-Q		10.4	8/3/2018	001-36559
10.5 †	Form of Notice of Grant of Restricted Stock Unit (Change in Control Restricted Stock Units).	10-Q		10.5	8/3/2018	001-36559

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31.1*			Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
31.2*			Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
32**			Certifications pursuant to 18 U.S.C. Section 1350.
101.INS*			XBRL Instance Document.
101.SCH*			XBRL Schema Document.
101.CAL*			XBRL Calculation Document.
101.LAB*			XBRL Labels Linkbase Document.
101.PRE*			XBRL Presentation Linkbase Document.
101.DEF*			XBRL Definition Linkbase Document.

* Filed herewith

** Furnished herewith

# The registrant agrees to furnish supplementally a copy of any omitted schedule to the Commission upon request

† Compensatory plan or arrangement

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INDEX TO EXHIBITS
		Incorporated by Reference
Exhibit	Exhibit Description	Form	Exhibit Number		Filing Date	SEC File No.
2.1#	Membership Interest Purchase Agreement, by and among Spark Energy, Inc., Spark HoldCo, LLC, Provider Power, LLC, Kevin B. Dean and Emile L. Clavet, dated as of May 3, 2016.	10-Q		2.1	5/5/2016	001-36559
2.2#	Membership Interest Purchase Agreement, by and among Spark Energy, Inc., Spark HoldCo, LLC, Retailco, LLC and National Gas & Electric, LLC, dated as of May 3, 2016.	10-Q		2.2	5/5/2016	001-36559
2.3#	Amendment No. 1 to the Membership Interest Purchase Agreement, dated as of July 26, 2016, by and among Spark Energy, Inc., Spark HoldCo, LLC, Provider Power, LLC, Kevin B. Dean and Emile L. Clavet.	8-K		2.1	8/1/2016	001-36559
2.4#	Membership Interest and Stock Purchase Agreement, by and among Spark Energy, Inc., CenStar Energy Corp. and Verde Energy USA Holdings, LLC, dated as of May 5, 2017.	10-Q		2.4	5/8/2017	001-36559
2.5	First Amendment to the Membership Interest and Stock Purchase Agreement, dated July 1, 2017, by and among Spark Energy, Inc., CenStar Energy Corp., and Verde Energy USA Holdings, LLC.	8-K		2.1	7/6/2017	001-36559
2.6#	Agreement to Terminate Earnout Payments, effective January 12, 2018, by and among Spark Energy, Inc., CenStar Energy Corp., Woden Holdings, LLC (fka Verde Energy USA Holdings, LLC), Verde Energy USA, Inc., Thomas FitzGerald, and Anthony Mench.	8-K		2.1	1/16/2018	001-36559
2.7#	Asset Purchase Agreement, dated March 7, 2018, by and between Spark HoldCo, LLC and National Gas & Electric, LLC.	10-K		2.7	3/9/2018	001-36559
2.8#	Asset Purchase Agreement, by and between Spark HoldCo, LLC, Starion Energy Inc., Starion Energy NY Inc., and Starion Energy PA Inc., dated October 19, 2018.	8-K		2.1	10/25/2018	001-36559
3.1	Amended and Restated Certificate of Incorporation of Spark Energy, Inc.	8-K		3.1	8/4/2014	001-36559
3.2	Amended and Restated Bylaws of Spark Energy, Inc.	8-K		3.2	8/4/2014	001-36559
3.3	Certificate of Designations of Rights and Preferences of 8.75% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Stock	8-A		5	3/14/2017	001-36559
4.1	Class A Common Stock Certificate	S-1		4.1	6/30/2014	333-196375
10.1	Amendment No. 2 to the Credit Agreement, dated as of July 17, 2018, by and among Spark Energy, Inc., the Co-Borrowers, the Banks party thereto, and Brown Brothers Harriman & Co., as exiting bank.	8-K		10.1	7/20/2018	001-36559
10.2 †	Amended Employment Agreement between Spark Energy, Inc. and Nathan Kroeker dated August 1, 2018.	10-Q		10.2	8/3/2018	001-36559
10.3 †	Amended and Restated Employment Agreement between Spark Energy, Inc. and Jason Garrett dated August 1, 2018.	10-Q		10.3	8/3/2018	001-36559
10.4 †	Amended and Restated Employment Agreement between Spark Energy, Inc. and Gil Melman dated August 1, 2018.	10-Q		10.4	8/3/2018	001-36559
10.5 †	Form of Notice of Grant of Restricted Stock Unit (Change in Control Restricted Stock Units).	10-Q		10.5	8/3/2018	001-36559
31.1*	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.

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31.2*			Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
32**			Certifications pursuant to 18 U.S.C. Section 1350.
101.INS*			XBRL Instance Document.
101.SCH*			XBRL Schema Document.
101.CAL*			XBRL Calculation Document.
101.LAB*			XBRL Labels Linkbase Document.
101.PRE*			XBRL Presentation Linkbase Document.
101.DEF*			XBRL Definition Linkbase Document.

* Filed herewith

** Furnished herewith

# The registrant agrees to furnish supplementally a copy of any omitted schedule to the Commission upon request

† Compensatory plan or arrangement

SIGNATURES

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




	Spark Energy, Inc.


November 2, 2018		/s/ Robert Lane
		Robert Lane
		Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)

Spark Energy, Inc. - FORM 10-Q - November 2, 2018

Attached files

Spark Energy, Inc. Reports