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, 2019
 
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)
Securities registered pursuant to Section 12(b) of the Act:

			
Title of each class	Trading Symbols(s)	Name of exchange on which registered	
Class A common stock, par value $0.01 per share	SPKE	The NASDAQ Global Select Market	
8.75% Series A Fixed-to-Floating Rate

Cumulative Redeemable Perpetual Preferred Stock, par value $0.01 per share	SPKEP	The NASDAQ Global Select Market	
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, a 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 14,379,553 shares of outstanding Class A common stock, 20,800,000 shares of Class B common stock and 3,702,756 shares of Series A Preferred Stock outstanding as of November 4, 2019.

	
			
SPARK ENERGY, INC.	 	 	
INDEX TO QUARTERLY REPORT ON FORM 10-Q	 	 	
For the Quarter Ended September 30, 2019	 	 	
 	 	Page No.	
PART I. FINANCIAL INFORMATION	 	 	
ITEM 1. FINANCIAL STATEMENTS	 	 	
 	 	 	
CONDENSED CONSOLIDATED BALANCE SHEETS AS OF SEPTEMBER 30, 2019 AND DECEMBER 31, 2018 (unaudited)	 	3	
 	 	 	
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2019 AND 2018 (unaudited)	 	4	
 	 	 	
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2019 AND 2018 (unaudited)	 	5	
 	 	 	
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2019 AND 2018 (unaudited)	 	9	
 	 	 	
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (unaudited)	 	11	
 	 	 	
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	 	44	
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	 	63	
ITEM 4. CONTROLS AND PROCEDURES	 	65	
PART II. OTHER INFORMATION	 	66	
ITEM 1. LEGAL PROCEEDINGS	 	66	
ITEM 1A. RISK FACTORS	 	66	
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	 	66	
ITEM 6. EXHIBITS	 	67	
SIGNATURES	 	69	

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Cautionary Note Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q (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,” “project,” 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;	
		
•	the sufficiency of risk management and hedging policies and practices;	
		
•	the impact of extreme and unpredictable weather conditions, including hurricanes and other natural disasters;	
		
•	federal, state and local regulations, including the industry's ability to address or adapt to potentially restrictive new regulations that may be enacted by public utility commissions;	
		
•	our ability to borrow funds and access credit markets;	
		
•	restrictions in our debt agreements and collateral requirements;	
		
•	credit risk with respect to suppliers and customers;	
		
•	changes in costs to acquire customers as well as actual attrition rates;	
		
•	accuracy of billing systems;	
		
•	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, 2018, in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2019, and 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 I. — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS
SPARK ENERGY, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands, except share counts)
(unaudited)

								
	September 30, 2019		December 31, 2018	
Assets				
Current assets:				
Cash and cash equivalents	$	42,580			$	41,002		
Restricted cash	1,002			8,636		
Accounts receivable, net of allowance for doubtful accounts of $2,995 at September 30, 2019 and $3,353 at December 31, 2018	101,672			150,866		
Accounts receivable—affiliates	1,419			2,558		
Inventory	3,580			3,878		
Fair value of derivative assets	1,143			7,289		
Customer acquisition costs, net	8,389			14,431		
Customer relationships, net	14,623			16,630		
Deposits	6,723			9,226		
Renewable energy credit asset	16,414			25,717		
Other current assets	14,296			11,747		
Total current assets	211,841			291,980		
Property and equipment, net	3,255			4,366		
Fair value of derivative assets	94			3,276		
Customer acquisition costs, net	9,328			3,893		
Customer relationships, net	20,715			26,429		
Deferred tax assets	23,130			27,321		
Goodwill	120,343			120,343		
Other assets	9,696			11,130		
Total assets	$	398,402			$	488,738		
Liabilities, Series A Preferred Stock and Stockholders' Equity				
Current liabilities:				
Accounts payable	$	45,708			$	68,790		
Accounts payable—affiliates	351			2,464		
Accrued liabilities	23,755			10,845		
Renewable energy credit liability	30,638			42,805		
Fair value of derivative liabilities	4,460			6,478		
Current payable pursuant to tax receivable agreement—affiliates	—			1,658		
Current contingent consideration for acquisitions	1,328			1,328		
Current portion of Note Payable	—			6,936		
Other current liabilities	1,862			647		
Total current liabilities	108,102			141,951		
Long-term liabilities:						
Fair value of derivative liabilities	1,830			106		
Payable pursuant to tax receivable agreement—affiliates	—			25,917		
Long-term portion of Senior Credit Facility	109,000			129,500		
Subordinated debt—affiliate	10,504			10,000		
Other long-term liabilities	190			212		
Total liabilities	229,626			307,686		
Commitments and contingencies (Note 13)						
Series A Preferred Stock, par value $0.01 per share, 20,000,000 shares authorized, 3,702,756 issued and outstanding at September 30, 2019 and 3,707,256 issued and outstanding at December 31, 2018	90,646			90,758		
Stockholders' equity:						
       Common Stock:						
Class A common stock, par value $0.01 per share, 120,000,000 shares authorized, 14,478,999 issued, and 14,379,553 outstanding at September 30, 2019 and 14,178,284 issued and 14,078,838 outstanding at December 31, 2018	145			142		
Class B common stock, par value $0.01 per share, 60,000,000 shares authorized, 20,800,000 issued and outstanding at September 30, 2019 and December 31, 2018	209			209		
       Additional paid-in capital	53,750			46,157		
       Accumulated other comprehensive (loss) income	(57	)		2		
       Retained earnings	3,849			1,307		
       Treasury stock, at cost, 99,446 shares at September 30, 2019 and December 31, 2018	(2,011	)		(2,011	)	
       Total stockholders' equity	55,885			45,806		
Non-controlling interest in Spark HoldCo, LLC	22,245			44,488		
       Total equity	78,130			90,294		
Total liabilities, Series A Preferred Stock and Stockholders' equity	$	398,402			$	488,738		

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
(in thousands, except per share data)
(unaudited)

																
	Three Months Ended September 30,		Nine Months Ended September 30,	
	2019		2018		2019		2018	
Revenues:								
Retail revenues	$	207,341			$	258,127			$	625,300			$	773,616		
Net asset optimization (expense) revenues	(254	)		348			2,242			3,798		
Total Revenues	207,087			258,475			627,542			777,414		
Operating Expenses:								
Retail cost of revenues	123,867			193,409			477,881			645,954		
General and administrative	27,629			25,695			94,352			83,522		
Depreciation and amortization	9,496			13,917			31,963			39,797		
Total Operating Expenses	160,992			233,021			604,196			769,273		
Operating income	46,095			25,454			23,346			8,141		
Other (expense)/income:								
Interest expense	(2,174	)		(2,762	)		(6,392	)		(7,323	)	
Interest and other income	322			(47	)		1,005			707		
Total other expenses	(1,852	)		(2,809	)		(5,387	)		(6,616	)	
Income before income tax expense	44,243			22,645			17,959			1,525		
Income tax expense	6,567			3,818			3,022			602		
Net income	$	37,676			$	18,827			$	14,937			$	923		
Less: Net income (loss) attributable to non-controlling interests	22,142			12,060			5,736			(3,524	)	
Net income attributable to Spark Energy, Inc. stockholders	$	15,534			$	6,767			$	9,201			$	4,447		
Less: Dividend on Series A Preferred Stock	2,026			2,027			6,080			6,081		
Net income (loss) attributable to stockholders of Class A common stock	$	13,508			$	4,740			$	3,121			$	(1,634	)	
Other comprehensive income (loss), net of tax:								
Currency translation (loss) gain	$	(45	)		$	47			$	(143	)		$	(11	)	
Other comprehensive (loss) income	(45	)		47			(143	)		(11	)	
Comprehensive income	$	37,631			$	18,874			$	14,794			$	912		
Less: Comprehensive income (loss) attributable to non-controlling interests	22,116			12,089			5,652			(3,531	)	
Comprehensive income attributable to Spark Energy, Inc. stockholders	$	15,515			$	6,785			$	9,142			$	4,443		
								
Net income (loss) attributable to Spark Energy, Inc. per share of Class A common stock								
       Basic	$	0.94			$	0.35			$	0.22			$	(0.12	)	
       Diluted	$	0.93			$	0.35			$	0.22			$	(0.12	)	
										
Weighted average shares of Class A common stock outstanding										
       Basic	14,380			13,394			14,254			13,254		
       Diluted	14,514			13,394			14,429			13,254		

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
(in thousands)
(unaudited)

																																		
NINE MONTHS ENDED SEPTEMBER 30, 2019	
 	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, 2018	14,178		20,800		(99	)	$	142		$	209		$	(2,011	)	$	2		$	46,157		$	1,307		$	45,806		$	44,488		$	90,294		
Stock based compensation	—		—		—		—		—		—		—		3,888		—		3,888		—		3,888		
Restricted stock unit vesting	301		—		—		3		—		—		—		(1,107	)	—		(1,104	)	—		(1,104	)	
Consolidated net income	—		—		—		—		—		—		—		—		9,201		9,201		5,736		14,937		
Foreign currency translation adjustment for equity method investee	—		—		—		—		—		—		(59	)	—		—		(59	)	(84	)	(143	)	
Gain on settlement of TRA, net of tax	—		—				—		—				—		12,179		—		12,179		—		12,179		
Distributions paid to non-controlling unit holders	—		—		—		—		—		—		—		—		—		—		(28,108	)	(28,108	)	
Dividends paid to Class A common stockholders ($0.54375 per share)	—		—		—		—		—		—		—		(5,170	)	(2,606	)	(7,776	)	—		(7,776	)	
Changes in ownership interest	—		—		—		—		—		—		—		(223	)	—		(223	)	223		—		
Dividends paid to Preferred Stockholders	—		—		—		—		—		—		—		(2,029	)	(4,053	)	(6,082	)	—		(6,082	)	
Proceeds from disgorgement of stockholder short-swing profits	—		—		—		—		—		—		—		55		—		55		—		55		
Acquisition of Customers from Affiliate	—		—		—		—		—		—		—		—		—		—		(10	)	(10	)	
Balance at September 30, 2019	14,479		20,800		(99	)	$	145		$	209		$	(2,011	)	$	(57	)	$	53,750		$	3,849		$	55,885		$	22,245		$	78,130		

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THREE MONTHS ENDED SEPTEMBER 30, 2019	
 	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 June 30, 2019	14,479		20,800		(99	)	$	145		$	209		$	(2,011	)	$	(38	)	$	42,329		$	(7,053	)	$	33,581		$	18,124		$	51,705		
Stock based compensation	—		—		—		—		—		—		—		1,377		—		1,377		—		1,377		
Consolidated net income	—		—		—		—		—		—		—		—		15,534		15,534		22,142		37,676		
Foreign currency translation adjustment for equity method investee	—		—		—		—		—		—		(19	)	—		—		(19	)	(26	)	(45	)	
Gain on settlement of TRA, net of tax	—		—		—		—		—		—		—		12,179		—		12,179		—		12,179		
Distributions paid to non-controlling unit holders	—		—		—		—		—		—		—		—		—		—		(20,130	)	(20,130	)	
Dividends paid to Class A common stockholders ($0.18125 per share)	—		—		—		—		—		—		—		—		(2,606	)	(2,606	)	—		(2,606	)	
Dividends to Preferred Stockholders	—		—		—		—		—		—		—		—		(2,026	)	(2,026	)	—		(2,026	)	
Changes in ownership interest	—		—		—		—		—		—		—		(2,135	)	—		(2,135	)	2,135		—		
Balance at September 30, 2019	14,479		20,800		(99	)	$	145		$	209		$	(2,011	)	$	(57	)	$	53,750		$	3,849		$	55,885		$	22,245		$	78,130		

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NINE MONTHS ENDED SEPTEMBER 30, 2018	
 	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	)	$	47,811		$	11,399		$	57,536		$	101,559		$	159,095		
Stock based compensation	—		—		—		—		—		—		—		3,596		—		3,596		—		3,596		
Restricted stock unit vesting	258		—		—		3		—		—		—		(715	)	—		(712	)	—		(712	)	
Consolidated net income	—		—		—		—		—		—		—		—		4,447		4,447		(3,524	)	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 ($0.54375 per share)	—		—		—		—		—		—		—		(2,381	)	(4,852	)	(7,233	)	—		(7,233	)	
Dividends to Preferred Stockholders	—		—		—		—		—		—		—		(2,027	)	(4,054	)	(6,081	)	—		(6,081	)	
Acquisition of Customers from Affiliate	—		—		—		—		—		—		—		—		—		—		(7,119	)	(7,119	)	
Changes in ownership interest	—		—		—		—		—		—		—		(3,237	)	—		(3,237	)	3,237		—		
Balance at September 30, 2018	13,493		21,485		(99	)	$	135		$	216		$	(2,011	)	$	(15	)	$	43,047		$	6,940		$	48,312		$	70,445		$	118,757		

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THREE MONTHS ENDED SEPTEMBER 30, 2018	
 	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 June 30, 2018	13,493		21,485		(99	)	$	135		$	216		$	(2,011	)	$	(33	)	$	46,715		$	219		$	45,241		$	63,327		$	108,568		
Stock based compensation	—		—		—		—		—		—		—		950		—		950		—		950		
Restricted stock unit vesting	—		—		—		—		—		—		—		—		—		—		—		—		
Consolidated net income	—		—		—		—		—		—		—		—		6,767		6,767		12,060		18,827		
Foreign currency translation adjustment for equity method investee	—		—		—		—		—		—		18		—		—		18		29		47		
Distributions paid to non-controlling unit holders	—		—		—		—		—		—		—		—		—		—		(4,200	)	(4,200	)	
Dividends paid to Class A common stockholders ($0.18125 per share)	—		—		—		—		—		—		—		(2,381	)	(47	)	(2,428	)	—		(2,428	)	
Dividends to Preferred Stockholders	—		—		—		—		—		—		—		(2,027	)	1		(2,026	)	—		(2,026	)	
Acquisition of Customers from Affiliate	—		—		—		—		—		—		—		—		—		—		(981	)	(981	)	
Changes in ownership interest	—		—		—		—		—		—		—		(210	)	—		(210	)	210		—		
Balance at September 30, 2018	13,493		21,485		(99	)	$	135		$	216		$	(2,011	)	$	(15	)	$	43,047		$	6,940		$	48,312		$	70,445		$	118,757		
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
(in thousands)

9

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(unaudited)

								
  	Nine Months Ended September 30,	
  	2019		2018	
Cash flows from operating activities:				
Net income	$	14,937			$	923		
Adjustments to reconcile net loss to net cash flows provided by operating activities:				
Depreciation and amortization expense	31,965			38,538		
Deferred income taxes	34			(749	)	
Change in TRA liability	—			79		
Stock based compensation	4,053			3,707		
Amortization of deferred financing costs	1,002			1,243		
Excess tax benefit related to restricted stock vesting	—			(101	)	
Change in Fair Value of Earnout liabilities	—			(63	)	
Bad debt expense	9,185			8,480		
Loss on derivatives, net	42,690			1,371		
Current period cash settlements on derivatives, net	(32,593	)		6,189		
Other	(608	)		(489	)	
Changes in assets and liabilities:				
Decrease in accounts receivable	40,008			21,029		
Decrease (increase) in accounts receivable—affiliates	1,139			(390	)	
Decrease in inventory	298			475		
Increase in customer acquisition costs	(13,608	)		(8,949	)	
Decrease (increase) in prepaid and other current assets	9,211			(10,999	)	
Increase in intangible assets—customer acquisitions	—			(86	)	
(Increase) decrease in other assets	(394	)		92		
Decrease in accounts payable and accrued liabilities	(27,721	)		(11,062	)	
Decrease in accounts payable—affiliates	(2,114	)		(1,786	)	
Increase (decrease) in other current liabilities	(374	)		(5,140	)	
Decrease in other non-current liabilities	(25	)		(459	)	
Net cash provided by operating activities	77,085			41,853		
Cash flows from investing activities:				
Purchases of property and equipment	(577	)		(1,097	)	
Verde working capital settlement	—			470		
Acquisition of Starion customers	(5,913	)		—		
Acquisition of HIKO	—			(14,290	)	
Acquisition of Customers from Affiliate	—			(8,776	)	
Net cash used in investing activities	(6,490	)		(23,693	)	
Cash flows from financing activities:				
Proceeds from (buyback) issuance of Series A Preferred Stock, net of issuance costs paid	(111	)		48,490		
Borrowings on notes payable	224,500			277,800		
Payments on notes payable	(245,000	)		(281,050	)	
Net borrowings on subordinated debt facility	504			—		
Payment of the Major Energy Companies Earnout	—			(1,607	)	
Payments on the Verde promissory note	(2,036	)		(6,573	)	
Proceeds from disgorgement of stockholders short-swing profits	55			244		
Restricted stock vesting	(1,348	)		(2,589	)	
Payment of Tax Receivable Agreement liability	(11,239	)		(3,577	)	
Payment of dividends to Class A common stockholders	(7,776	)		(7,233	)	
Payment of distributions to non-controlling unitholders	(28,108	)		(23,701	)	
Payment of Preferred Stock dividends	(6,082	)		(4,987	)	
Payment to affiliates for acquisition of customer book	(10	)		—		
Net cash used in financing activities	(76,651	)		(4,783	)	
(Decrease) increase in Cash, cash equivalents and Restricted cash	(6,056	)		13,377		
Cash, cash equivalents and Restricted cash—beginning of period	49,638			29,419		
Cash, cash equivalents and Restricted cash—end of period	$	43,582			$	42,796		
Supplemental Disclosure of Cash Flow Information:				
Non-cash items:						
        Property and equipment purchase accrual	$	89			$	(123	)	
        Holdback for Verde Note—Indemnified Matters	$	4,900			$	—		
        Write-off of tax benefit related to tax receivable agreement liability — affiliates	$	4,157			$	—		
        Gain on settlement of tax receivable agreement liability—affiliates	$	(16,336	)		$	—		
Cash paid during the period for:				
Interest	$	5,245			$	5,955		
Taxes	$	5,097			$	7,461		
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

We are 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. Spark Energy, Inc. (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 Electricity Maine, Electricity N.H., Major Energy, Provider Power Massachusetts, Respond Power, Spark Energy, and Verde Energy.

Emerging Growth Company Status

The Company qualifies as an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012, or the JOBS Act. An emerging growth company may take advantage of specified reduced reporting and other regulatory requirements. The Company will remain an “emerging growth company” until the last day of 2019.
2. Basis of Presentation and Summary of Significant Accounting Policies
Basis of Presentation
The accompanying interim unaudited condensed consolidated financial 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, 2018 (the “2018 Form 10-K”). 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.
In the opinion of the Company's management, the accompanying condensed consolidated financial statements reflect all adjustments that are necessary to fairly present the financial position, the results of operations, the changes in equity and the cash flows of the Company for the respective periods. Such adjustments are of a normal recurring nature, unless otherwise disclosed.

Immaterial Corrections to Prior Year Financial Information

The condensed consolidated income statements and our statements of changes in stockholders' equity reflect immaterial adjustments, as disclosed in our 2018 Form 10-K, to the historical balances in additional paid-in capital, non-controlling interest, retained earnings, net (loss) income attributable to non-controlling interest, and earnings per share for the three and nine months ended September 30, 2018. We made these adjustments in accordance with GAAP, to reflect the amounts the owners of our Class A and Class B common stock would receive, respectively, if the assets of our subsidiary, Spark HoldCo, were sold and its liabilities were settled at their recorded book values as of each balance sheet date. In addition, we adjusted income for the three and nine months ended September 30, 2018 to make certain immaterial corrections to the allocation of income between non-controlling interests and

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income available for common shareholders. Our adjustments had no impact on the manner in which distributions were paid during the three and nine months ended September 30, 2018. The Company evaluated the materiality of the errors from quantitative and qualitative perspectives and concluded that the errors were immaterial to the Company’s prior period interim and annual consolidated financial statements. Since the revision was not material to the prior period interim or annual consolidated financial statements, no amendments to previously filed interim or annual periodic reports were required. Consequently, the Company revised the historical condensed consolidated financial information presented herein.

Below are amounts as reported and as adjusted for each period presented (in thousands): 

													
 	 	September 30, 2018	
 	 	As Reported	 	Adjustments	 	As Adjusted	
Additional paid-in capital	 	$	25,387		 	$	17,660		 	$	43,047		
Retained earnings	 	2,885		 	4,055		 	6,940		
Total Stockholders' Equity	 	26,597		 	21,715		 	48,312		
Non-controlling interest in Spark HoldCo, LLC	 	94,368		 	(23,923	)	 	70,445		
Total equity	 	$	120,965		 	$	(2,208	)	 	$	118,757		
 	 	 	 	 	 	 	
 	 	Three Months Ended September 30, 2018	
Net income attributable to stockholders of Class A common stock	 	$	3,582		 	$	1,158		 	$	4,740		
Net income attributable to non-controlling interests	 	13,218		 	(1,158	)	 	12,060		
Net income attributable to Spark Energy, Inc. stockholders	 	$	5,609		 	$	1,158		 	$	6,767		
 	 	 	 	 	 	 	
Net income attributable to Spark Energy, Inc. per share of Class A common stock	 	 	 	 	 	 	
Basic	 	$	0.27		 	$	0.08		 	$	0.35		
Diluted	 	$	0.27		 	$	0.08		 	$	0.35		
 	 	 	 	 	 	 	
 	 	Nine Months Ended September 30, 2018	
Net loss attributable to stockholders of Class A common stock	 	$	(5,298	)	 	$	3,664		 	$	(1,634	)	
Net loss attributable to non-controlling interests	 	140		 	(3,664	)	 	(3,524	)	
Net income attributable to Spark Energy, Inc. stockholders	 	$	783		 	$	3,664		 	$	4,447		
 	 	 	 	 	 	 	
Net loss attributable to Spark Energy, Inc. per share of Class A common stock	 	 	 	 	 	 	
Basic	 	$	(0.40	)	 	$	0.28		 	$	(0.12	)	
Diluted	 	$	(0.40	)	 	$	0.28		 	$	(0.12	)	

Use of Estimates and Assumptions
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.

Relationship with our Founder and Majority Shareholder

W. Keith Maxwell, III (our "Founder") is the owner of a majority of the 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.

New Accounting Standards Recently Adopted

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There have been no changes to our significant accounting policies as disclosed in our 2018 Form 10-K, except as follows:

In January 2017, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("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 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 adopted ASU 2017-04 effective January 1, 2019, and the adoption of this standard did not have a material impact on the Company's 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 adopted ASU 2018-07 effective January 1, 2019, and the adoption of this standard did not have a material impact on the Company's consolidated financial statements.

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) ("ASU 2016-02"). Under this new guidance, lessees are 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. The FASB issued ASU No. 2018-10, Codification Improvements to Topic 842, Leases, ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, and ASU No. 2019-01, Leases (Topic 842): Codification Improvements, to provide additional guidance for the adoption of Topic 842. ASU 2016-02 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. ASU 2016-02 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 elected to use. We evaluated the impact of this new guidance and reviewed lease or possible lease contracts and evaluated contract related processes. We adopted ASU 2016-02 effective January 1, 2019 and recorded right-of-use assets and liabilities for our real estate operating leases of approximately $1.0 million.

Standards Being Evaluated/Standards Not Yet Adopted

The Company considers the applicability and impact of all ASUs. ASUs not listed below were assessed and determined to be either not applicable or are expected to have minimal impact on our consolidated financial statements.

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments ("ASU 2016-13"). ASU 2016-13 requires entities to use a current expected credit loss ("CECL") model, which is a new impairment model based on expected losses rather than incurred losses on financial assets, including accounts receivables, loans, and held-to-maturity debt securities, among others. The model requires financial assets measured at amortized cost to be presented at the net amount expected to be collected. The measurement of expected credit losses is based on relevant information about past events, historical experience, current conditions, and reasonable forecasts. ASU 2016-13 is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. The FASB also issued

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subsequent amendments to the initial guidance: ASU 2019-04, Codification Improvements to Topic 326, Financial Instruments - Credit Losses, Topic 815, Derivatives and Hedging, and Topic 825, Financial Instruments ("ASU 2019-04") in April 2019, and ASU 2019-05, Financial Instruments - Credit Losses (Topic 326), Targeted Transition Relief ("ASU 2019-05") in May 2019. ASU 2019-04 provides clarifications and minor improvements related to these topics. ASU 2019-05 provides entities that have certain instruments with an option to irrevocably elect the fair value option in Subtopic 825-10, Financial Instruments - Overall, applied on an instrument-by-instrument basis for eligible instruments, upon adoption of Topic 326. The Company is currently evaluating the impact of adopting this guidance on its consolidated financial statements. We plan to adopt the new standard and related amendments on January 1, 2020, by recognizing the cumulative effect of initially applying the new standard as an adjustment to the opening balance of retained earnings for any impact to the amount of expected credit losses on our reported accounts receivable balance, net, on our consolidated balance sheet. We do not expect adoption of the new standard to have a material impact to our consolidated statement of operations.

3. Revenues
Our revenues are derived primarily from the sale of natural gas and electricity to customers, including affiliates. Revenue is measured based upon the quantity of gas or power delivered 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).

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 FASB ASC Topic 606, Revenue from Contracts with Customers.

Revenues for electricity and 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. Electricity and natural gas products may be sold as fixed-price or variable-price products. The typical length of a contract to provide electricity and/or natural gas is 12 months. Customers are billed and typically pay at least monthly, based on usage. Electricity and 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, 2019	 	Three Months Ended September 30, 2018	
 	Retail Electricity		Retail Natural Gas		Total Reportable Segments	 	Retail Electricity		Retail Natural Gas		Total Reportable Segments	

Primary markets (a)	 	 	 	 	 	 	 	 	 	 	 	
  New England	$	76,995		 	$	1,631		 	$	78,626		 	$	110,870		 	$	2,163		 	$	113,033		
  Mid-Atlantic	69,763		 	2,940		 	72,703		 	83,846		 	3,762		 	87,608		
  Midwest	23,310		 	2,146		 	25,456		 	20,898		 	2,557		 	23,455		
  Southwest	26,942		 	3,614		 	30,556		 	30,568		 	3,463		 	34,031		
	$	197,010		 	$	10,331		 	$	207,341		 	$	246,182		 	$	11,945		 	$	258,127		
	 	 	 	 		 	 	 	 	 	 	
Customer type	 	 	 	 	 	 	 	 	 	 	 	
  Commercial	$	69,081		 	$	3,378		 	$	72,459		 	$	101,818		 	$	4,650		 	$	106,468		
  Residential	134,763		 	6,696		 	141,459		 	151,918		 	7,068		 	158,986		
  Unbilled revenue (b)	(6,834	)	 	257		 	(6,577	)	 	(7,554	)	 	227		 	(7,327	)	
	$	197,010		 	$	10,331		 	$	207,341		 	$	246,182		 	$	11,945		 	$	258,127		
	 	 	 	 	 	 	 	 	 	 	 	
Customer credit risk	 	 	 	 		 	 	 	 	 	 	
  POR	$	136,683		 	$	4,037		 	$	140,720		 	$	172,198		 	$	5,013		 	$	177,211		
  Non-POR	60,327		 	6,294		 	66,621		 	73,984		 	6,932		 	80,916		
	$	197,010		 	$	10,331		 	$	207,341		 	$	246,182		 	$	11,945		 	$	258,127		

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 	Reportable Segments	
 	Nine Months Ended September 30, 2019	 	Nine Months Ended September 30, 2018	
 	Retail Electricity		Retail Natural Gas		Total Reportable Segments	 	Retail Electricity		Retail Natural Gas		Total Reportable Segments	

Primary markets (a)					 	 	 	 	 	 	 	
  New England	$	221,134			$	13,311			$	234,445		 	$	305,894			$	14,742		 	$	320,636		
  Mid-Atlantic	191,077			29,643			220,720		 	229,329			39,112		 	268,441		
  Midwest	62,890			27,371			90,261		 	56,818			27,243		 	84,061		
  Southwest	64,777			15,097			79,874		 	84,487			15,991		 	100,478		
	$	539,878		 	$	85,422		 	$	625,300		 	$	676,528		 	$	97,088		 	$	773,616		
	 	 	 	 	 	 	 	 	 	 	 	
Customer type					 	 	 	 	 	 	 	
  Commercial	$	196,015			$	32,079			$	228,094		 	$	275,966			$	39,826		 	$	315,792		
  Residential	356,950			64,307			421,257		 	415,022			73,138		 	488,160		
  Unbilled revenue (b)	(13,087	)		(10,964	)		(24,051	)	 	(14,460	)		(15,876	)	 	(30,336	)	
	$	539,878		 	$	85,422		 	$	625,300		 	$	676,528		 	$	97,088		 	$	773,616		
	 	 	 	 	 	 	 	 	 	 	 	
Customer credit risk					 	 	 	 	 	 	 	
  POR	$	375,890			$	45,260			$	421,150		 	$	473,438			$	54,565		 	$	528,003		
  Non-POR	163,988			40,162			204,150		 	203,090			42,523		 	245,613		
	$	539,878		 	$	85,422		 	$	625,300		 	$	676,528		 	$	97,088		 	$	773,616		

(a) The primary markets 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.

We record gross receipts taxes on a gross basis in retail revenues and retail cost of revenues. During the three months ended September 30, 2019 and 2018, our retail revenues included gross receipts taxes of $0.4 million and $0.5 million, respectively, and our retail cost of revenues include gross receipts taxes of $2.2 million and $2.7 million, respectively. During the nine months ended September 30, 2019 and 2018, our retail revenues included gross receipts taxes of $1.1 million and $1.3 million, respectively, and our retail cost of revenues included gross receipts taxes of $6.7 million and $7.8 million, respectively.
4. Acquisitions
Acquisition of HIKO
In March 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

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29,000 RCEs located in 42 markets in seven states. The acquisition was accounted for under the acquisition method. 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 allocation of the purchase consideration is as follows (in thousands):

				
 	Reported as of December 31, 2018	
Cash and restricted cash	$	375		
Intangible assets—customer relationships	6,031		
Net working capital, net of cash acquired	8,465		
Fair value of derivative liabilities	(205	)	
Total	$	14,666		

Acquisition from Related Parties

In March 2018, we entered into an asset purchase agreement with an affiliate pursuant to which we agreed to acquire up to 50,000 RCEs 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 eight states. For the year ended December 31, 2018, we paid $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 our affiliate's historical value at the date of transfer, which was $1.7 million. The transaction resulted in $7.1 million recorded in equity as a net distribution to affiliate as of December 31, 2018. Of the $8.8 million paid to our affiliate, $1.7 million was an investing cash outflow, and the remaining $7.1 million was deemed a distribution to our non-controlling interest and classified as financing activity.

Acquisitions of Customer Books

In October 2018, we entered into an asset purchase agreement pursuant to which we agreed to acquire up to 60,000 RCEs from Starion Energy Inc., Starion Energy NY Inc. and Starion Energy PA Inc. (collectively "Starion") for a cash purchase price of up to a maximum of $10.7 million. These customers began transferring in December 2018, and are located in our existing markets. As of September 30, 2019, a total of $8.0 million was paid under the terms of the purchase agreement for approximately 51,000 RCEs.

As part of the acquisition, we funded an escrow account, the balance of which is reflected as restricted cash in our consolidated balance sheet. As of September 30, 2019 and December 31, 2018, the balance in the escrow account was $1.0 million and $8.6 million, respectively. The balance remaining as of September 30, 2019 represents a holdback of amounts due to the seller for acquired customers that will be released to the seller in April 2020, subject to certain adjustments outlined in the asset purchase agreement.

5. Equity

Non-controlling Interest

We hold an economic interest and are the sole managing member in Spark HoldCo, with affiliates of our Founder and majority shareholder holding the remaining economic interests in Spark HoldCo. As a result, we consolidate the financial position and results of operations of Spark HoldCo, and reflect the economic interests owned by these affiliates as a non-controlling interest. The Company and affiliates owned the following economic interests in Spark HoldCo at December 31, 2018 and September 30, 2019, respectively.

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 	The Company	Affiliated Owners	
December 31, 2018	40.53	%	59.47	%	
September 30, 2019	41.04	%	58.96	%	

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

																
	Three Months Ended September 30,		Nine Months Ended September 30,	
	2019		2018		2019		2018	
 			 				 	
Net income (loss) allocated to non-controlling interest	$	25,003			$	12,752			$	7,108			$	(2,834	)	
Income tax expense allocated to non-controlling interest	2,861			692			1,372			690		
Net income (loss) attributable to non-controlling interest	$	22,142			$	12,060			$	5,736			$	(3,524	)	

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 stockholders 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 a reduction of additional paid in capital to the extent retained earnings are exhausted. During the nine months ended September 30, 2019, we paid $7.8 million in dividends to the holders of the Company's Class A common stock.

In order to pay our stated dividends to holders of our Class A common stock, our subsidiary, Spark HoldCo is required to make corresponding distributions to holders of its units, including those holders that own our Class B common stock (our non-controlling interest holder). As a result, during the nine months ended September 30, 2019, Spark HoldCo made corresponding distributions of $11.3 million to our non-controlling interest holders.

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 interests. Diluted earnings per share is similarly calculated except that the denominator is increased by potentially dilutive securities.

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The following table presents the computation of basic and diluted income (loss) per share for the three and nine months ended September 30, 2019 and 2018 (in thousands, except per share data):

	
																
	Three Months Ended September 30,	 	Nine Months Ended September 30,	
	2019	 	2018	 	2019	 	2018	
Net income attributable to Spark Energy, Inc. stockholders	$	15,534		 	$	6,767		 	$	9,201		 	$	4,447		
Less: Dividend on Series A preferred stock	2,026		 	2,027		 	6,080		 	6,081		
Net income (loss) attributable to stockholders of Class A common stock	$	13,508		 	$	4,740		 	$	3,121		 	$	(1,634	)	
 	 	 	 	 	 	 	 	
Basic weighted average Class A common shares outstanding	14,380		 	13,394		 	14,254		 	13,254		
Basic income (loss) per share attributable to stockholders	$	0.94		 	$	0.35		 	$	0.22		 	$	(0.12	)	
	 	 	 	 	 	 	 	
Net income (loss) attributable to stockholders of Class A common stock	$	13,508		 	$	4,740		 	$	3,121		 	$	(1,634	)	
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	$	13,508		 	$	4,740		 	$	3,121		 	$	(1,634	)	
 	 	 	 	 	 	 	 	
Basic weighted average Class A common shares outstanding	14,380		 	13,394		 	14,254		 	13,254		
Effect of dilutive Class B common stock	—		 	—		 	—		 	—		
Effect of dilutive restricted stock units	134		 	—		 	175		 	—		
Diluted weighted average shares outstanding	14,514		 	13,394		 	14,429		 	13,254		
	 	 	 	 	 	 	 	
Diluted income (loss) per share attributable to stockholders	$	0.93		 	$	0.35		 	$	0.22		 	$	(0.12	)	

The computation of diluted earnings per share for the three and nine months ended September 30, 2019 excludes 20.8 million shares of Class B common stock because the effect of their conversion was antidilutive. 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 that 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 our operating subsidiaries. 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, 2019 and December 31, 2018 (in thousands):

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	September 30, 2019	December 31, 2018	
Assets		 	
Current assets:		 	
   Cash and cash equivalents	$	42,505		$	36,724		
   Accounts receivable	101,672		150,866		
   Other current assets	61,527		92,963		
   Total current assets	205,704		280,553		
Non-current assets:		 	
   Goodwill	120,343		120,343		
   Other assets	40,532		47,159		
   Total non-current assets	160,875		167,502		
   Total Assets	$	366,579		$	448,055		
		 	
Liabilities		 	
Current liabilities:		 	
   Accounts payable and accrued liabilities	$	69,433		$	79,692		
   Contingent consideration	1,328		1,328		
   Other current liabilities	37,312		59,330		
   Total current liabilities	108,073		140,350		
Long-term liabilities:		 	
   Long-term portion of Senior Credit Facility	109,000		129,500		
   Subordinated debt — affiliate	10,504		10,000		
   Other long-term liabilities	2,019		319		
   Total long-term liabilities	121,523		139,819		
   Total Liabilities	$	229,596		$	280,169		

6. Preferred Stock

During the year ended December 31, 2018, we issued an aggregate of 2,917 shares of Series A Preferred Stock under an at-the-market issuance sales agreement (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.

In January 2018, 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. The Company received approximately $48.9 million ($24.45 per share) 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.

In May 2019, we commenced a share repurchase program (the "Repurchase Program") of our Series A Preferred Stock. We may make purchases of our Series A Preferred Stock under the Repurchase Program through May 20, 2020, and there is no dollar limit on the amount of Series A Preferred Stock that may be repurchased, nor does the Repurchase Program obligate the Company to make any repurchases. During the nine months ended September 30, 2019, we repurchased 4,500 shares of Series A Preferred Stock at a weighted-average price of $24.70 per share, for a total cost of approximately $0.1 million.

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

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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 condensed consolidated balance sheet.

During the three and nine months ended September 30, 2019, we paid $2.0 million and $6.1 million, respectively, in dividends to holders of the Series A Preferred Stock. As of September 30, 2019, we had accrued $2.0 million related to dividends to holders of the Series A Preferred Stock. This dividend was paid on October 15, 2019.

A summary of our preferred equity balance for the nine months ended September 30, 2019 is as follows:

					
		(in thousands)	
Balance at December 31, 2018		$	90,758		
Accumulated dividends on Series A Preferred Stock		(3	)	
Repurchase of Series A Preferred Stock		(109	)	
Balance at September 30, 2019		$	90,646		
7. 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 ("RECs"), and capacity charges from independent system operators. 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 also 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 third parties. 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, 2019 and December 31, 2018, we had paid $1.1 million and zero, respectively, in collateral. 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.	

The Company has entered into other energy-related contracts that do not meet the definition of a derivative instrument or for which we made a normal purchase, normal sale election and are therefore not accounted for at fair value including the following:

•	Forward electricity and natural gas purchase contracts for retail customer load;	
		
•	Renewable energy credits; and	
		
•	Natural gas transportation contracts and storage agreements.	

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Volumes Underlying Derivative Transactions
The following table summarizes the net notional volumes of our open derivative financial instruments accounted for at fair value by commodity. Positive amounts represent net buys while bracketed amounts are net sell transactions (in thousands):
Non-trading 

								
Commodity	Notional		September 30, 2019		December 31, 2018	
Natural Gas	MMBtu		7,145			8,176		
Natural Gas Basis	MMBtu		68			115		
Electricity	MWh		6,614			6,781		
Trading

								
Commodity	Notional		September 30, 2019		December 31, 2018	
Natural Gas	MMBtu		136			188		
Natural Gas Basis	MMBtu		310			(380	)	

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,	
  	2019		2018	
Gain on non-trading derivatives, net	$	12,528			$	17,888		
(Loss) gain on trading derivatives, net	(221	)		229		
Gain on derivatives, net	12,307			18,117		
Current period settlements on non-trading derivatives (1)	12,764			1,035		
Current period settlements on trading derivatives	(43	)		(113	)	
Total current period settlements on derivatives	$	12,721			$	922		
(1) Excludes settlements of less than $(0.1) million and $0.1 million, respectively, for the three months ended September 30, 2019 and 2018 related to non-trading derivative liabilities assumed in various acquisitions.

								
	Nine Months Ended September 30,	
  	2019		2018	
Loss on non-trading derivatives, net	$	(42,741	)		$	(2,223	)	
Gain on trading derivatives, net	51			852		
Loss on derivatives, net	(42,690	)		(1,371	)	
Current period settlements on non-trading derivatives (1) (2)	33,677			(5,054	)	
Current period settlements on trading derivatives	(162	)		(769	)	
Total current period settlements on derivatives	$	33,515			$	(5,823	)	
(1) Excludes settlements of less than $0.1 million and $(0.4) million, respectively, for the nine months ended September 30, 2019 and 2018 related to non-trading derivative liabilities assumed in various acquisitions.
(2) Excludes settlements of $(0.9) million and zero, respectively, for the nine months ended September 30, 2019 and 2018 related to power call options.

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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, 2019	
Description	Gross Assets		Gross
Amounts
Offset		Net Assets		Cash
Collateral
Offset		Net Amount
Presented	
Non-trading commodity derivatives	$	12,685			$	(11,574	)		$	1,111			$	—			$	1,111		
Trading commodity derivatives	34			(2	)		32			—			32		
Total Current Derivative Assets	12,719			(11,576	)		1,143			—			1,143		
Non-trading commodity derivatives	488			(394	)		94			—			94		
Trading commodity derivatives	—			—			—			—			—		
Total Non-current Derivative Assets	488			(394	)		94			—			94		
Total Derivative Assets	$	13,207			$	(11,970	)		$	1,237			$	—			$	1,237		

	
																				
	September 30, 2019	
Description	Gross 
Liabilities		Gross
Amounts
Offset		Net
Liabilities		Cash
Collateral
Offset		Net Amount
Presented	
Non-trading commodity derivatives	$	(20,014	)		$	14,636			$	(5,378	)		$	991			$	(4,387	)	
Trading commodity derivatives	(284	)		211			(73	)		—			(73	)	
Total Current Derivative Liabilities	(20,298	)		14,847			(5,451	)		991			(4,460	)	
Non-trading commodity derivatives	(4,073	)		2,171			(1,902	)		72			(1,830	)	
Trading commodity derivatives	(4	)		4			—			—			—		
Total Non-current Derivative Liabilities	(4,077	)		2,175			(1,902	)		72			(1,830	)	
Total Derivative Liabilities	$	(24,375	)		$	17,022			$	(7,353	)		$	1,063			$	(6,290	)	

	
																				
  	December 31, 2018	
Description	Gross Assets		Gross
Amounts
Offset		Net Assets		Cash
Collateral
Offset		Net Amount
Presented	
Non-trading commodity derivatives	$	18,649			$	(12,000	)		$	6,649			$	—			$	6,649		
Trading commodity derivatives	734			(94	)		640			—			640		
Total Current Derivative Assets	19,383			(12,094	)		7,289			—			7,289		
Non-trading commodity derivatives	9,657			(6,381	)		3,276			—			3,276		
Trading commodity derivatives	—			—			—			—			—		
Total Non-current Derivative Assets	9,657			(6,381	)		3,276			—			3,276		
Total Derivative Assets	$	29,040			$	(18,475	)		$	10,565			$	—			$	10,565		

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	December 31, 2018	
Description	Gross 
Liabilities		Gross
Amounts
Offset		Net
Liabilities		Cash
Collateral
Offset		Net Amount
Presented	
Non-trading commodity derivatives	$	(21,391	)		$	15,385			$	(6,006	)		$	—			$	(6,006	)	
Trading commodity derivatives	(491	)		19			(472	)		—			(472	)	
Total Current Derivative Liabilities	(21,882	)		15,404			(6,478	)		—			(6,478	)	
Non-trading commodity derivatives	(71	)		40			(31	)		—			(31	)	
Trading commodity derivatives	(135	)		60			(75	)		—			(75	)	
Total Non-current Derivative Liabilities	(206	)		100			(106	)		—			(106	)	
Total Derivative Liabilities	$	(22,088	)		$	15,504			$	(6,584	)		$	—			$	(6,584	)	

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

										
	Estimated useful
lives (years)	 	September 30, 2019	 	December 31, 2018	
Information technology	2 – 5	 	$	21,632		 	$	34,611		
Building and leasehold improvements	2 – 5	 	—		 	4,836		
Furniture and fixtures	2 – 5	 	1,851		 	1,964		
Total		 	23,483		 	41,411		
Accumulated depreciation		 	(20,228	)	 	(37,045	)	
Property and equipment—net		 	$	3,255		 	$	4,366		
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 each of September 30, 2019 and December 31, 2018, information technology includes $0.2 million and $0.3 million of costs associated with assets not yet placed into service.
Depreciation expense recorded in the condensed consolidated statements of operations was $0.6 million and $1.0 million for the three months ended September 30, 2019 and 2018, respectively, and $1.8 million and $3.1 million for the nine months ended September 30, 2019 and 2018, respectively.

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

								
 	September 30, 2019	 	December 31, 2018	
Goodwill	$	120,343		 	$	120,343		
Customer relationships—Acquired		 		
Cost	$	64,108		 	$	99,402		
Accumulated amortization	(37,713	)	 	(63,208	)	
Customer relationships—Acquired & Non-Compete Agreements, net	$	26,395		 	$	36,194		
Customer relationships—Other		 		
Cost	$	17,056		 	$	16,155		
Accumulated amortization	(8,113	)	 	(9,290	)	
Customer relationships—Other, net	$	8,943		 	$	6,865		
Trademarks		 		
Cost	$	9,348		 	$	9,770		
Accumulated amortization	(3,401	)	 	(2,483	)	
Trademarks, net	$	5,947		 	$	7,287		

Changes in goodwill, customer relationships (including non-compete agreements) and trademarks consisted of the following (in thousands):

																
	Goodwill	 	Customer Relationships— Acquired & Non-Compete Agreements	 	Customer Relationships— Other	 	Trademarks	
Balance at December 31, 2018	$	120,343		 	$	36,194		 	$	6,865		 	$	7,287		
Additions	—		 	—		 	6,913		 	—		
Amortization	—		 	(9,799	)	 	(4,835	)	 	(1,340	)	
Balance at September 30, 2019	$	120,343		 	$	26,395		 	$	8,943		 	$	5,947		

Estimated future amortization expense for customer relationships and trademarks at September 30, 2019 is as follows (in thousands):

				
Year ending December 31,		
2019 (remaining three months)	$	4,203		
2020	14,561		
2021	12,987		
2022	6,038		
2023	450		
> 5 years	3,046		
Total	$	41,285		

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10. Debt
Debt consists of the following amounts as of September 30, 2019 and December 31, 2018 (in thousands):

								
	September 30, 2019	 	December 31, 2018	
Current:	 	 	 	
  Note Payable—Verde Notes	$	—		 	$	6,936		
Total current portion of debt	—		 	6,936		
Long-term debt:	 	 	 	
  Senior Credit Facility (1) (2)	109,000		 	129,500		
  Subordinated Debt	10,504		 	10,000		
Total long-term debt	119,504		 	139,500		
Total debt	$	119,504		 	$	146,436		
(1) As of September 30, 2019 and December 31, 2018, the weighted average interest rate on the Senior Credit Facility was 5.19% and 5.48%, respectively.
(2) As of September 30, 2019 and December 31, 2018, we had $40.3 million and $49.4 million in letters of credit issued, respectively.

Capitalized financing costs associated with our Senior Credit Facility were $1.5 million and $1.4 million as of September 30, 2019 and December 31, 2018, respectively. Of these amounts, $0.9 million and $1.0 million are recorded in other current assets, and $0.6 million and $0.4 million are recorded in other non-current assets in the condensed consolidated balance sheets as of September 30, 2019 and December 31, 2018, respectively.
Interest expense consists of the following components for the periods indicated (in thousands): 

																
	Three Months Ended September 30,	 	Nine Months Ended September 30,	
	2019	 	2018	 	2019	 	2018	
Senior Credit Facility	$	1,120		 	$	1,423		 	$	3,741		 	$	3,895		
Subordinated debt	162		 	13		 	166		 	20		
Note Payable—Verde Notes	—		 	288		 	230		 	978		
Letters of credit fees and commitment fees	395		 	407		 	1,253		 	1,187		
Amortization of deferred financing costs 	497		 	631		 	1,002		 	1,243		
Interest Expense	$	2,174		 	$	2,762		 	$	6,392		 	$	7,323		

Senior Credit Facility

The Company, as guarantor, and Spark HoldCo (the “Borrower” and, together with each subsidiary of Spark HoldCo (“Co-Borrowers”)), maintain a senior secured borrowing base credit facility (as amended, “Senior Credit Facility”) that allows us to borrow on a revolving basis and has a maximum borrowing capacity of $217.5 million as of September 30, 2019. 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 (“Working Capital Loans”), and bridge loans (“Bridge Loans”) for the purpose of partial funding for acquisitions. Borrowings under the Senior Credit Facility may be used to pay fees and expenses in connection with the 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, 2019, we had $109.0 million outstanding under the Senior Credit Facility, as well as $40.3 million of outstanding letters of credit.

The Senior Credit Facility will mature on May 19, 2021, 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, 2019, there were no Bridge Loans outstanding.

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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 certain subordinated debt but including interest in respect of that certain promissory note made by CenStar Energy Corp. ("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. The Senior Credit Facility permits, upon satisfaction of a Step-Down Condition, for the Company to elect to reduce the minimum required Fixed Charge Coverage Ratio from 1.25 to 1.00 to 1.10 to 1.00 for a period of one year. A Step-Down Condition is defined as the consummation by the Company of share buybacks of its Series A Preferred Stock under the Repurchase Program with an aggregate purchase price not less than $10.0 million.	

•	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 under the Senior Credit Facility) plus 50% of the effective amount of letter of credit obligations attributable to performance standby letters of credit to (b) Adjusted EBITDA.	

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. The Senior Credit Facility also contains affirmative covenants that are customary for credit facilities of this type. As of September 30, 2019, we were in compliance with our various covenants under the Senior Credit Facility.

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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, and actual or asserted failure of any guaranty or security document supporting the Senior Credit Facility to be in full force and effect. 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 June 13, 2019, the Company entered into an Amended and Restated Subordinated Promissory Note in the principal amount of up to $25.0 million (the “Subordinated Debt Facility”), by and among the Company, Spark HoldCo and Retailco. The Subordinated Debt Facility amended and restated the Subordinated Promissory Note, dated as of December 27, 2016, by and among the Company, Spark HoldCo and Retailco, solely to extend the expiration date from July 1, 2020 to December 31, 2021.

The Subordinated Debt Facility allows us to draw advances in increments of no less than $1.0 million per advance up to the maximum principal amount of the Subordinated Debt Facility. 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 Debt Facility. The Subordinated Debt Facility 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 Debt Facility so long as we are in compliance with the covenants under our Senior Credit Facility, are not in default under the Senior Credit Facility and have minimum availability of $5.0 million under the borrowing base under the Senior Credit Facility. Payment of principal and interest under the Subordinated Debt Facility is accelerated upon the occurrence of certain change of control or sale transactions.

As of September 30, 2019, and December 31, 2018, there was $10.5 million and $10.0 million outstanding, respectively, under the Subordinated Debt Facility.

Verde Notes

In connection with the acquisition of the Verde Companies in July 2017, we entered into a promissory note in the aggregate principal amount of $20.0 million (the "Verde Promissory Note"). The Verde Promissory Note required repayment in eighteen monthly installments beginning in August 2017, and accrued interest at 5% per annum from the date of issuance. The Verde Promissory Note, including principal and interest, was unsecured, but was guaranteed by us. In January 2018, in connection with the Earnout Termination Agreement (defined below), we issued to the seller of the Verde Companies an amended and restated promissory note (the “Amended and Restated

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Verde Promissory Note”), which amended and restated the Verde Promissory Note. The Amended and Restated Verde Promissory Note matured in January 2019, and bore interest at a rate of 9% per annum. Principal and interest were payable monthly on the first day of each month, with a portion of each payment going into an escrow account, which serves as security for certain indemnification claims and obligations under the Verde purchase agreement. As of September 30, 2019 and December 31, 2018, there was zero and $1.0 million outstanding, respectively, under the Amended and Restated Verde Promissory Note.

In January 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 matured in June 2019 and bore interest at a rate of 9% per annum. Under the terms of the Verde Earnout Termination Note, we were permitted to withhold amounts otherwise due at maturity related to certain indemnifiable matters. A payment of $1.0 million was made to the seller of the Verde Companies in June 2019, and $4.9 million was withheld (the “Verde Holdback”) to be applied to indemnifiable matters. For three and nine months ended September 30, 2019, approximately zero and $0.2 million, respectively, of the Verde Holdback was applied to costs incurred related to indemnifiable matters. As of September 30, 2019, $4.4 million of the Verde Holdback is classified as accrued liabilities, and $0.3 million is classified as other current liabilities related to indemnifiable matters. Interest was payable monthly on the first day of each month. As of September 30, 2019 and December 31, 2018, there was zero and $5.9 million outstanding under the Verde Earnout Termination Note, respectively.

The Verde Earnout Termination Note, the Verde Promissory Note, and the Amended and Restated Verde Promissory Note are collectively referred to as the "Verde Notes."
11. 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.	

As the fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3), the Company maximizes the use of observable inputs and minimizes the use of unobservable inputs when measuring fair value. These levels can change over time. In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. In these cases, the lowest level

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input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
The following tables present 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, 2019	 		 		 		 	
Non-trading commodity derivative assets	$	63			$	1,142			$	—			$	1,205		
Trading commodity derivative assets	—			32			—			32		
Total commodity derivative assets	$	63			$	1,174			$	—			$	1,237		
Non-trading commodity derivative liabilities	$	(1,063	)		$	(5,154	)		$	—			$	(6,217	)	
Trading commodity derivative liabilities	—			(73	)		—			(73	)	
Total commodity derivative liabilities	$	(1,063	)		$	(5,227	)		$	—			$	(6,290	)	
Contingent payment arrangement	$	—		 	$	—		 	$	(1,328	)	 	$	(1,328	)	

	
																
	Level 1		Level 2		Level 3		Total	
December 31, 2018								
Non-trading commodity derivative assets	$	104			$	9,821			$	—			$	9,925		
Trading commodity derivative assets	44			596			—			640		
Total commodity derivative assets	$	148			$	10,417			$	—			$	10,565		
Non-trading commodity derivative liabilities	$	(352	)		$	(5,685	)		$	—			$	(6,037	)	
Trading commodity derivative liabilities	(75	)		(472	)		—			(547	)	
Total commodity derivative liabilities	$	(427	)		$	(6,157	)		$	—			$	(6,584	)	
Contingent payment arrangement	$	—		 	$	—		 	$	(1,328	)	 	$	(1,328	)	
We had no transfers of assets or liabilities between any of the above levels during the nine months ended September 30, 2019 and the year ended December 31, 2018.
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 our or the counterparty’s historical credit risks. As of September 30, 2019 and December 31, 2018, the credit risk valuation adjustment was less than $0.1 million.

The contingent payment arrangements referred to above reflect estimated earnout obligations incurred in relation to our acquisition of the Major Energy Companies in 2016.
Contingent Payment Arrangements
The following table presents a roll forward of our contingent payment arrangements, which are measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the nine months ended September 30, 2019.

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		Major Earnout and Stock Earnout	
Fair Value at December 31, 2018		$	1,328		
Change in fair value of contingent consideration, net		—		
Accretion of contingent earnout consideration (included within interest expense)		—		
Payments and settlements		—		
Fair Value at September 30, 2019	 	$	1,328		
Other Financial Instruments
The carrying amount of cash and cash equivalents, accounts receivable, accounts payable, 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 recorded in the condensed consolidated balance sheets approximates fair value because of the variable rate nature of interest on the borrowings thereunder, and are considered Level 2 measurements because interest rates charged are similar to other financial instruments with similar terms and maturities.

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 interest 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.

We periodically 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 make 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 utilized, and accordingly have not recorded a valuation allowance on these assets.

As of September 30, 2019, we had a net deferred tax asset of $23.1 million, of which 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. During

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the third quarter of 2019, we reversed the deferred tax asset associated with the Company's Tax Receivable Agreement ("TRA"), resulting in a net decrease to deferred tax assets of $4.2 million and a corresponding charge to additional paid in capital, in connection with the full and complete termination of the TRA. See Note 14 "Transactions with Affiliates" for further discussion of the TRA and TRA termination.

The effective U.S. federal and state income tax rate for the nine months ended September 30, 2019 and 2018 was 16.8% and 39.5%, respectively. The effective tax rate for the nine months ended September 30, 2019 reflects the corporate U.S. federal statutory tax rate of 21%, 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 expense for the nine months ended September 30, 2019 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. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.

Legal Proceedings

Below is a summary of our currently pending material legal proceedings. We are subject to other lawsuits and claims arising in the ordinary course of our business. The following legal proceedings are in various stages and are 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 these legal proceedings 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.

Janet Rolland, et al v. Spark Energy, LLC is a purported class action originally filed on April 19, 2017 in the United States District Court for the District of New Jersey alleging that Spark Energy, LLC charged a variable rate that was higher than permitted by its terms of service, resulting in breach of contract and violation of the duty of good faith and fair dealing. Plaintiffs alleged claims under the New Jersey Consumer Fraud Act and Illinois Consumer Fraud and Deceptive Business Practices Act. Two plaintiffs (one from New Jersey and one from Illinois) seek to certify a putative nationwide class of all Spark variable rate electricity customers from April 19, 2011 to the present. The relief sought includes unspecified actual damages, refunds, treble damages and punitive damages for the putative class, injunctive relief, attorneys’ fees and costs of suit. Spark obtained dismissal with prejudice of the New Jersey Consumer Fraud Act claim and will seek dismissal of the Illinois Consumer Fraud and Deceptive Business Practices Act claim and other claim(s). Discovery is ongoing in this matter. Spark denies the allegations asserted by Plaintiffs and intends to vigorously defend this matter. Given the ongoing discovery and current stage of this matter, we cannot predict the outcome or consequences of the case at this time.

Katherine Veilleux, et. al. 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 ("Electricity Maine"), an entity acquired by Spark Holdco in mid-2016, enrolled and re-enrolled customers through fraudulent and misleading advertising, promotions, and other communications prior to and following the acquisition. Plaintiffs allege claims under RICO, the Maine Unfair Trade Practice Act, civil conspiracy, and unjust enrichment. Plaintiffs seek damages for themselves and the purported

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class, injunctive relief, restitution, and attorneys' fees. Plaintiff’s motion for class certification is currently pending before the court, which Spark HoldCo and Electricity Maine vigorously opposed, including by filing a motion to exclude Plaintiffs’ designated expert witnesses. Electricity Maine and Spark HoldCo have also filed a motion to compel arbitration of certain Plaintiffs’ claims, which is still pending before the court, on the grounds that some of the applicable Terms of Service contain an arbitration provision and class action waiver. The parties are currently in settlement negotiations. In a parallel declaratory judgment action, the Company won a favorable verdict against Zurich, one of Electricity Maine’s insurance carriers, and Zurich has been ordered to pay certain costs associated with this claim that the Company believes will offset any total losses to the Company. The Company also believes indemnity offsets with the former sellers of Electricity Maine will be applicable to any settlement, but the Company may have additional liability beyond the existing indemnity and insurance coverage to resolve this matter. Given the preliminary stage of the settlement discussions, the amount of additional liability of this case remains uncertain at this time, but we do not believe that any potential additional liability will have a material adverse effect on our financial position.

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 but was later removed to the United States District Court for the Eastern District of Pennsylvania. On September 15, 2014, 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 and alleged claims of deceptive conduct in violation of Pennsylvania Unfair Trade Practices and Consumer Protection Act, negligent misrepresentation, fraudulent concealment, and breach of contract and of the covenant of good faith and fair dealing by charging rates above the utility. The amount of damages sought is not specified. By order dated August 31, 2015, the district court denied class certification. Plaintiffs appealed the district court’s denial of class certification to the United States Court of Appeals for the Third Circuit and that court vacated the district court’s denial of class certification and remanded the matter to the district court for further proceedings. On July 16, 2018, the district court granted Respond Power LLC's 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 Third Circuit has declined to hear oral arguments on this matter but has not yet ruled on this appeal. The Company believes it has full indemnity coverage for any actual exposure in this case at this time.

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 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. 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. The parties have reached a class settlement in this matter, in the amount of $6.0 million, which has received preliminary court approval. The Company believes it has full indemnity coverage, net of tax benefit, for any actual exposure in 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 ("TCPA") by placing marketing calls using an automatic telephone dialing system ("ATDS") 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. Following discovery and dispositive motions, the Verde Companies received a favorable ruling on summary judgment with the court agreeing with the Verde Companies that the call system used in this case was not an ATDS as defined by the TCPA. Plaintiffs subsequently amended their petition eliminating their ATDS claim and including a class based on failure to comply with the National Do Not Call registry. 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. The parties reached a confidential settlement in this matter. A hearing on Plaintiffs’ motion for preliminary settlement approval was held on September 23, 2019, at which the Court denied preliminary approval. Negotiations with the Plaintiffs continue in

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an effort to modify the settlement to meet the Court’s concerns. The Plaintiffs’ motion for class certification is due to be filed on or before December 23, 2019. The Company believes it has full indemnity coverage, net of tax benefit, for the settlement exposure in this case.

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., is a lawsuit filed on October 17, 2017 in the United States District Court for the Southern District of New York asserting claims of fraudulent inducement against NG&E, breach of contract against NG&E and Spark, and tortious interference with contract against Spark related to a membership interest purchase agreement, subsequent dropdown, 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. On September 24, 2018, the court granted Defendants’ motion to dismiss in part and dismissed Plaintiffs’ fraudulent inducement claims. NG&E and Spark filed their affirmative defenses and answer to the remaining claims on October 15, 2018. On January 14, 2019, Plaintiffs filed a Motion for Partial Summary Judgment, which was subsequently denied by the Court on May 8, 2019. On March 25, 2019, Spark and NG&E filed a Motion for Sanctions in connection with deletion of electronically stored data by plaintiff Saul Horowitz and co-seller Mark Wiederman after receiving a litigation hold notice, which the Court granted in part on May 8, 2019, including an award of attorneys' fees and costs to Spark and NG&E in connection with the Motion for Sanctions. On June 7, 2019, the parties jointly filed a letter agreement with the Court confirming plaintiff’s payment of fees and costs, including costs associated with forensic analysis, in the amount of less than $0.1 million to Spark and NG&E in connection with the Court’s ruling on their Motion for Sanctions. This case is currently scheduled for mediation on November 7, 2019, set for a final pre-trial conference on January 28, 2020 and for trial to commence on March 2, 2020. Spark and NG&E deny the allegations asserted by Plaintiffs and intend to vigorously defend this matter. Given the ongoing expert discovery and current stage of this matter, we cannot predict the outcome or consequences of this case at this time.

Albrecht v. Oasis Power, LLC is a putative nationwide class action that was filed on February 12, 2018 in the United States District Court for the Northern District of Illinois, alleging that Oasis made illegal prerecorded telemarketing calls, including auto-dialed calls, to consumers’ mobile phones, in violation of the Telephone Consumer Protection Act ("TCPA") and the Illinois Automatic Telephone Dialers Act ("ATDA"). Plaintiff sought an injunction requiring Oasis to cease all unsolicited calling activities, an award of statutory and trebled damages under the TCPA and the ATDA, as well as costs and attorney’s fees. The parties have reached a class settlement on behalf of Oasis and other affiliated brands in the amount of $7.0 million, which has received preliminary court approval. The Company has sought indemnity and insurance coverage from two vendors and their carriers that worked on the telemarketing campaigns at issue.

Regulatory Matters

State of Illinois v. Major Energy Electric Services, LLC is a complaint filed by the Illinois Attorney General for injunctive and other relief 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 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 on April 9, 2018 in the Circuit Court of Cook County, Illinois, County Department, Chancery Division. Major filed its motion to dismiss on July 31, 2018 and the judge denied that motion on October 10, 2018. Major filed a motion for reconsideration on the Court’s ruling on its motion to dismiss, which was denied. The parties resolved the case on August 16, 2019. The court entered a final judgment and consent decree, which included Major paying $2.0 million in refunds to consumers, and $0.1 million as a voluntary contribution to the Illinois Attorney General's Office. The settlement also included a number of injunctive and reporting provisions with which Major must comply. Major will make the refund payments beginning in approximately December 2019.

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PURA Investigations. Spark Energy, LLC ("SE LLC") is the subject of two current investigations by the Connecticut Public Utilities Regulatory Authority ("PURA"). The first investigation constitutes a notice of violation ("NOV") and assessment of a proposed civil penalty in the amount of $0.9 million primarily for SE LLC's alleged failure to comply with requirements implemented in 2016 that customer bills include any changes to existing rates effective for the next billing cycle. After a hearing process was concluded and SE LLC filed a brief challenging the legal authority of PURA to enforce the NOV and impose civil penalties for the alleged violations, PURA suspended the proceeding and opened a proceeding offering amnesty to ESCOs that self-report violations and offer to voluntarily remit refunds to customers. Spark has remitted its report of potential customers who would be eligible for refunds under the amnesty program and submitted its confidential settlement proposal along with SE LLC’s commitment, subject to certain conditions. SE LLC is awaiting PURA’s completion of a review and audit process after which SE LLC expects PURA to issue a final decision on SE LLC’s offer of amnesty. The second investigation involves an NOV alleging improper marketing practices of one of SE 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. On July 17, 2019, PURA issued a final decision, which upheld the proposed civil penalty amount of $0.8 million. The final decision also refers the matter to the Connecticut Department of Consumer Protection and the Connecticut Office of the Attorney General for possible further investigation, the outcome of which we are unable to predict. On August 30, 2019, SE LLC filed an administrative appeal of the final decision to the Connecticut Superior Court and the action remains pending.

PUCO Investigation. Verde Energy USA Ohio, LLC (“Verde Ohio”) is the subject of a formal investigation by the Public Utilities Commission of Ohio (“PUCO”) initiated on April 16, 2019. The investigation asserts that Verde Ohio engaged in misleading and deceptive practices to market and enroll customers as well as allegations of violating several requirements of Ohio’s retail energy supplier regulations. On May 3, 2019, Verde Ohio filed a Motion to Temporarily Suspend the Procedural Schedule and Stay Discovery Pending Negotiation of a Stipulation between the parties. In its Motion, Verde Ohio agreed to a thirty (30) day voluntary marketing and customer enrollment stay in Ohio. Although the Motion was not granted by PUCO, Verde Ohio has continued its voluntary marketing and customer enrollment stay in Ohio in furtherance of settlement negotiations with PUCO Staff. Also on May 3, 2019, PUCO Staff issued a report of its findings following their investigation of Verde Ohio, and filed a corrected version on May 29, 2019, as contemplated in PUCO’s procedural schedule set forth in the April 17th, 2019 PUCO entry in the matter. On August 5, 2019, PUCO suspended the procedural schedule in the investigation in light of settlement negotiations between Verde Ohio and PUCO Staff. On September 6, 2019, Verde Ohio and PUCO Staff executed and filed with PUCO a Joint Stipulation and Recommendation for PUCO’s review and approval which sets forth agreed settlement terms. If approved by PUCO, the Joint Stipulation and Recommendation would resolve all of the issues raised in the investigation. While investigations of this nature may be resolved in a manner that allows the retail energy supplier to continue operating in Ohio with stipulations, there can be no assurances that PUCO will not take more severe action.

Maine PUC Investigation. In early 2018, Staff of the Maine Public Utilities Commission (“Maine PUC”) issued letters to Electricity Maine seeking information about customer complaints principally associated with door-to-door (“D2D”) sales practices. In late July 2018, the Maine PUC issued an Order to Show Cause to which Electricity Maine filed a detailed response in mid-August 2018. After a lengthy period of inactivity, the Commission scheduled a procedural conference in early 2019 that resulted in no intervenors other than participation as a party by the Maine Office of Public Advocate. At the conference, the parties agreed on a procedural schedule, including a one-day evidentiary hearing. Following post-hearing discovery, Initial and Reply Briefs were filed on August 30, 2019 and September 10, 2019, respectively. The parties are awaiting a proposed ruling from the Maine PUC hearing examiner, after which point the parties can either accept the ruling or take exception and argue the merits before the Maine PUC Commissioners. While investigations of this nature may be resolved in a manner that allows the retail energy supplier to continue operating in Maine with stipulations, there can be no assurances that Maine PUC will not take more severe action.

Indirect Tax Audits

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We are undergoing various types of indirect tax audits spanning from years 2013 to 2018 for which we may have additional liabilities arise. 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, 2019 and December 31, 2018, we had accrued $18.1 million and $0.9 million, respectively, related to litigation and regulatory matters and $0.4 million and $0.6 million, respectively, related to indirect tax audits. The outcome of each of these may result in additional expense.
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. Affiliated transactions include certain services to the affiliated companies associated with employee benefits provided through our benefit plans, insurance plans, leased office space, administrative salaries, due diligence work, recurring management consulting, and accounting, tax, legal, or technology services. Amounts billed are based on the 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 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 are recorded in the condensed consolidated balance sheets.

Master Service Agreement with Retailco Services, LLC

Prior to April 1, 2018, we were a party to a Master Service Agreement with an affiliated company 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 service, and information technology infrastructure and application support services. Effective April 1, 2018, we terminated the agreement, and these operational support services were transferred back to us.
Cost Allocations

Where costs incurred on behalf of the affiliate or us cannot be determined by specific identification for direct billing, the costs are 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 (to)/from affiliates was $(0.5) million and $0.3 million, respectively, for the three months ended September 30, 2019 and 2018, respectively. The total net amount direct billed and allocated (to)/from affiliates was $(0.1) million and $8.7 million, respectively, for the nine months ended September 30, 2019 and 2018, respectively.

Of the amounts directly billed and allocated from affiliates, we recorded general and administrative expense of zero and less than $0.1 million for the three months ended September 30, 2019 and 2018, respectively, and we recorded general and administrative expense of zero and $5.8 million for the nine months ended September 30, 2019 and 2018, respectively, in the condensed consolidated statement of operations. Additionally, we capitalized zero of property and equipment for the application, development and implementation of various systems during the three months ended September 30, 2019 and 2018, and we capitalized zero and $0.5 million of property and equipment

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for the application, development and implementation of various systems during the nine months ended September 30, 2019 and 2018, respectively.

Accounts Receivable and Payable—Affiliates
As of September 30, 2019 and December 31, 2018, we had current accounts receivable—affiliates of $1.4 million and $2.6 million, respectively, and current accounts payable—affiliates of $0.4 million and $2.5 million, respectively.
Revenues and Cost of Revenues—Affiliates
Revenues recorded in net asset optimization revenues in the condensed consolidated statements of operations for the three months ended September 30, 2019 and 2018 related to affiliated sales were $0.3 million and $0.3 million, respectively. Revenues recorded in net asset optimization revenues in the condensed consolidated statements of operations for the nine months ended September 30, 2019 and 2018 related to affiliated sales were $2.1 million and $1.3 million, respectively.
Cost of revenues recorded in net asset optimization revenues in the condensed consolidated statements of operations for the three months ended September 30, 2019 and 2018 related to affiliated purchases were less than $0.1 million. Cost of revenues recorded in net asset optimization revenues in the condensed consolidated statements of operations for the nine months ended September 30, 2019 and 2018 related to affiliated purchases were $0.1 million. These amounts are presented as net on the Consolidated Statements of Operations.

Acquisitions from Related Parties
In March 2018, we entered into an asset purchase agreement with an affiliate to acquire up to 50,000 RCEs for a cash purchase price of $250 for each RCE, or up to $12.5 million in the aggregate. A total of $8.8 million was paid in 2018 under the terms of the purchase agreement for approximately 35,000 RCEs, and no further material payments are anticipated. 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 less than $0.1 million and $7.1 million recorded in equity as a net distribution to affiliate as of September 30, 2019 and December 31, 2018, respectively.

Distributions to and Contributions from Affiliates

During the nine months ended September 30, 2019 and 2018, we made distributions to affiliates of our Founder of $11.3 million and $11.7 million, respectively, for payments of quarterly distributions on their respective Spark HoldCo units. During the nine months ended September 30, 2019 and 2018, we also made distributions to these affiliates for gross-up distributions of $16.8 million and $12.0 million, respectively, in connection with distributions made between Spark HoldCo and Spark Energy, Inc. for payment of income taxes incurred by us and settlement of the TRA.

Proceeds from Disgorgement of Stockholder Short-swing Profits

During the three and nine months ended September 30, 2019, we received zero and $0.1 million, respectively, cash for the disgorgement of stockholder short-swing profits under Section 16(b) under the Exchange Act. The amount was recorded as an increase to additional paid-in capital in our consolidated balance sheet as of September 30, 2019.

During the three and nine months ended September 30, 2018, the Company received zero and $0.2 million, respectively, cash 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.

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Subordinated Debt Facility

On June 13, 2019, we and Spark HoldCo entered into a Subordinated Debt Facility with an affiliate owned by our Founder, which allows the Company to borrow up to $25.0 million. The Subordinated Debt Facility allows us to draw advances in increments of no less than $1.0 million per advance up to the maximum principal amount of the Subordinated Debt Facility. Advances thereunder accrue interest at 5% per annum from the date of the advance. As of September 30, 2019 and December 31, 2018, there was $10.5 million and $10.0 million in outstanding borrowings, respectively, under the Subordinated Debt Facility. See Note 10 "Debt" for a further description of terms and conditions of the Subordinated Debt Facility.

Tax Receivable Agreement

Prior to July 11, 2019, we were party to a TRA with affiliates. Effective July 11, 2019, the Company entered into a TRA Termination and Release Agreement (the “Release Agreement”), which provided for a full and complete termination of any further payment, reimbursement or performance obligation of the Company, Retailco and NuDevco Retail under the TRA, whether past, accrued or yet to arise. Pursuant to the Release Agreement, the Company made a cash payment of approximately $11.2 million on July 15, 2019 to Retailco and NuDevco Retail. In connection with the termination of the TRA, Spark HoldCo made a distribution of approximately $16.3 million on July 15, 2019 to Retailco and NuDevco Retail under the Spark HoldCo Third Amended and Restated Limited Liability Company Agreement, as amended. The total amount of the distribution made to Retailco and NuDevco Retail in connection with the TRA settlement was subsequently loaned back to Spark HoldCo under the Subordinated Debt Facility on July 16, 2019.

The TRA generally provided 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 realized or would realize (or were 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 entities owned by our Founder, (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 made under the TRA. We retained the benefit of the remaining 15% of these tax savings. See Note 12 "Income Taxes" for further discussion.

In certain circumstances, we could defer or partially defer any payment due (a “TRA Payment”) to the holders of rights under the TRA for a five year period that would end September 30, 2019. Deferral of payment was required to the extent that Spark HoldCo did not generate sufficient Cash Available for Distribution (as defined below) during the four-quarter period ending September 30th of the applicable year in which the TRA Payment was to be made in an amount that equaled or exceeded 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” was 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” were defined as the aggregate distributions necessary to cause us to receive distributions of cash equal to (i) the targeted quarterly distribution we intended to pay to holders of our 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.	

At the end of the deferral period, we were obligated to pay any outstanding deferred TRA Payments to the extent such deferred TRA Payments did 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

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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 TRA, was $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 (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 had or reasonably determined it would 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 would no longer be payable.

For the four-quarter periods ending September 30, 2016, 2017, and 2018, we met the threshold coverage ratio required to fund the payments required under the TRA. Our affiliates, however, granted us the right to defer the TRA Payment related to the four-quarter period ending September 30, 2016 until May 2018. In April, May, and December of 2018, we paid a total of $6.2 million related to our obligations under the TRA for the 2015, 2016, and 2017 tax years.

As of September 30, 2019 and December 31, 2018, we had a total liability related to the TRA of zero and $27.6 million, of which zero and $1.7 million was classified as current liabilities at September 30, 2019 and December 31, 2018, respectively.

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 electricity and retail natural gas. The retail electricity segment consists of electricity sales and transmission to residential and commercial customers. The retail natural gas segment consists of natural gas sales to, and natural gas transportation and distribution for, residential and commercial customers. Corporate and other consists of expenses and assets of the retail electricity and natural gas segments that are managed at a consolidated level such as general and administrative expenses. Asset optimization activities are also included in Corporate and other.
For the three months ended September 30, 2019 and 2018, we recorded asset optimization revenues of $14.6 million and $28.3 million and asset optimization cost of revenues of $14.9 million and $28.0 million, respectively, which are presented on a net basis in asset optimization (expense) revenues. For the nine months ended September 30, 2019 and 2018, we recorded asset optimization revenues of $50.7 million and $139.2 million and asset optimization cost of revenues of $48.5 million and $135.4 million, respectively, which are presented on a net basis in asset optimization revenues.
The acquisitions 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 (loss) income plus (i) depreciation and amortization expenses and (ii) general and administrative expenses, less (i) net asset optimization (expenses) revenues, (ii) net (losses) gains on non-trading derivative instruments, and (iii) net current period cash settlements on non-trading derivative instruments. We deduct net (losses) gains 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 these 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):

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  	Three Months Ended September 30,	 	Nine Months Ended September 30,	
  	2019		2018	 	2019		2018	
Reconciliation of Retail Gross Margin to Income before taxes				 				
Income before income tax expense	$	44,243			$	22,645		 	$	17,959			$	1,525		
Interest and other income	(322	)		47		 	(1,005	)		(707	)	
Interest expense	2,174			2,762		 	6,392			7,323		
Operating income	46,095			25,454		 	23,346			8,141		
Depreciation and amortization	9,496			13,917		 	31,963			39,797		
General and administrative	27,629			25,695		 	94,352			83,522		
Less:				 				
Net asset optimization (expense) revenues	(254	)		348		 	2,242			3,798		
Net, gain (loss) on non-trading derivative instruments	12,528			17,888		 	(42,741	)		(2,223	)	
Net, Cash settlements on non-trading derivative instruments	12,764			1,035		 	33,677			(5,054	)	
Retail Gross Margin	$	58,182			$	45,795		 	$	156,483			$	134,939		

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

	
																				
Three Months Ended September 30, 2019	
 	Retail
Electricity		Retail
Natural Gas		Corporate
and Other		Eliminations		Consolidated	
Total Revenues	$	197,010		 	$	10,331		 	$	(254	)	 	$	—		 	$	207,087		
Retail cost of revenues	119,100		 	4,767		 	—		 	—		 	123,867		
Less:	 	 	 	 	 	 	 	 	 	
Net asset optimization expenses	—		 	—		 	(254	)	 	—		 	(254	)	
Net, gain (loss) on non-trading derivative instruments	12,652		 	(124	)	 	—		 	—		 	12,528		
Current period settlements on non-trading derivatives	12,115		 	649		 	—		 	—		 	12,764		
Retail Gross Margin	$	53,143		 	$	5,039		 	$	—		 	$	—		 	$	58,182		
Total Assets at September 30, 2019	$	2,370,994			$	764,432			$	348,401			$	(3,085,425	)		$	398,402		
Goodwill at September 30, 2019	$	117,813			$	2,530			$	—			$	—			$	120,343		

	
																				
Three Months Ended September 30, 2018	
 	Retail
Electricity	 	Retail
Natural Gas	 	Corporate
and Other	 	Eliminations	 	Consolidated	
Total revenues	$	246,182		 	$	11,945		 	$	348		 	$	—		 	$	258,475		
Retail cost of revenues	186,449		 	6,960		 	—		 	—		 	193,409		
Less:		 		 		 		 		
Net asset optimization revenues	—		 	—		 	348		 	—		 	348		
Net, gain (loss) on non-trading derivative instruments	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 December 31, 2018	$	1,857,790			$	649,969			$	361,697			$	(2,380,718	)		$	488,738		
Goodwill at December 31, 2018	$	117,813			$	2,530			$	—			$	—			$	120,343		

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Nine Months Ended September 30, 2019	
 	Retail
Electricity		Retail
Natural Gas		Corporate
and Other		Eliminations		Consolidated	
Total revenues	$	539,878			$	85,422			$	2,242			$	—			$	627,542		
Retail cost of revenues	433,175			44,706			—			—			477,881		
Less:										
Net asset optimization revenues	—			—			2,242			—			2,242		
Net, (loss) gain on non-trading derivatives	(42,984	)		243			—			—			(42,741	)	
Current period settlements on non-trading derivatives	32,957			720			—			—			33,677		
Retail Gross Margin	$	116,730			$	39,753			$	—			$	—			$	156,483		
Total Assets at September 30, 2019	$	2,370,994			$	764,432			$	348,401			$	(3,085,425	)		$	398,402		
Goodwill at September 30, 2019	$	117,813			$	2,530			$	—			$	—			$	120,343		

																				
Nine Months Ended September 30, 2018	
 	Retail
Electricity		Retail
Natural Gas		Corporate
and Other		Eliminations		Consolidated	
Total revenues	$	676,528			$	97,088			$	3,798			$	—			$	777,414		
Retail cost of revenues	587,949			58,005			—			—			645,954		
Less:										
Net asset optimization revenues	—			—			3,798			—			3,798		
Net, gain (loss) 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 December 31, 2018	$	1,857,790			$	649,969			$	361,697			$	(2,380,718	)		$	488,738		
Goodwill at December 31, 2018	$	117,813			$	2,530			$	—			$	—			$	120,343		

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16. Subsequent Events

Declaration of Dividends

On October 21, 2019, we declared a quarterly dividend of $0.18125 per share to holders of record of our Class A common stock on December 2, 2019, which will be paid on December 16, 2019.

We also declared a quarterly cash dividend in the amount of $0.546875 per share to holders of record of the Series A Preferred Stock on January 1, 2020 of our Series A Preferred Stock. The dividend will be paid on January 15, 2020.

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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 consolidated financial statements and notes thereto and management's discussion and analysis of financial condition and results of operations included in our 2018 Form 10-K filed with the Securities and Exchange Commission (“SEC”) on March 4, 2019. Results of operations and cash flows for the three and nine months ended September 30, 2019 are not necessarily indicative of results to be attained for any other period. See "Cautionary Note Regarding Forward-Looking Statements."
Overview

We are 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, 2019, 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. In this segment, we purchase electricity supply through physical and financial transactions with market counterparties 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, 2019 and 2018, approximately 95% and 95%, respectively, of our retail revenues were derived from the sale of electricity.	

•	Retail Natural Gas Segment. In this segment, we purchase natural gas supply through physical and financial transactions with market counterparties and supply natural gas to residential and commercial consumers pursuant to fixed-price and variable-price contracts. For the three months ended September 30, 2019 and 2018, approximately 5% and 5%, respectively, of our retail revenues were derived from the sale of natural gas.	

Recent Developments

Termination of Tax Receivable Agreement

Effective July 11, 2019, the Company entered into a TRA Termination and Release Agreement (the “Release Agreement”), which provided for a full and complete termination of any further payment, reimbursement or performance obligation of the Company and Retailco and NuDevco Retail under the Tax Receivable Agreement (“TRA”), whether past, accrued or yet to arise. Pursuant to the Release Agreement, the Company made a cash payment of approximately $11.2 million to Retailco and NuDevco Retail. In connection with the termination of the TRA, Spark HoldCo made a distribution of approximately $16.3 million to Retailco and NuDevco Retail that was subsequently loaned back to Spark HoldCo under the Subordinated Debt Facility.

Appointment of Director

On August 27, 2019, the Board of Directors appointed Amanda E. Bush to serve as a Class III independent director. Ms. Bush has been appointed to the Audit Committee, the Compensation Committee, and the Nominating and Corporate Governance Committee, and she will serve as the Chair of the Audit Committee. The Audit Committee now consists of Ms. Bush, Kenneth M. Hartwick, and Nick W. Evans, Jr.

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Residential Customer Equivalents

We measure our number of customers using residential customer equivalents ("RCEs"). The following table shows our RCEs by segment during the three and nine months ended September 30, 2019:

						
RCEs:	 	 	 	 	 	
(In thousands)	June 30, 2019	Additions	Attrition	September 30, 2019	% Increase (Decrease)	
Retail Electricity	673	41	(80)	634	(6)%	
Retail Natural Gas	145	9	(16)	138	(5)%	
Total Retail	818	50	(96)	772	(6)%	

	
						
RCEs:	 	 	 	 	 	
(In thousands)	December 31, 2018	Additions	Attrition	September 30, 2019	% Increase (Decrease)	
Retail Electricity	754	157	(277)	634	(16)%	
Retail Natural Gas	154	43	(59)	138	(10)%	
Total Retail	908	200	(336)	772	(15)%	

The following table details our count of RCEs by geographical location as of September 30, 2019:

							
RCEs by Geographic Location:	 	 	 	 	 	 	
(In thousands)	Electricity	 % of Total	Natural Gas	 % of Total	Total	 % of Total	
New England	286	45%	28	20%	314	41%	
Mid-Atlantic	224	35%	47	34%	271	35%	
Midwest	60	10%	43	31%	103	13%	
Southwest	64	10%	20	15%	84	11%	
Total	634	100%	138	100%	772	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 have operated under a number of different retail brands. During 2018, we began consolidating brands and billing systems. Through the remainder of 2019, we expect to further consolidate our brands and systems as we simplify our business.

Drivers of our Business

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

Customer Growth

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Customer growth is a key driver of our operations. Our ability to acquire customers organically or by acquisition is important to our success as we experience ongoing customer attrition. Our customer growth strategy includes growing organically through traditional sales channels complemented by customer portfolio and business acquisitions.

Organic Sales

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. Our marketing team continuously evaluates the effectiveness of each customer acquisition channel and makes adjustments in order to achieve desired targets. During the third quarter of 2019, we added approximately 50,000 RCEs through our various organic sales channels.

Acquisitions

We acquire companies and portfolios of customers through both external and affiliated channels. During the nine months ended September 30, 2019, we added approximately 33,000 RCEs as part of our customer portfolio acquisition from Starion Energy, which closed during 2018.

Our ability to realize returns from acquisitions that are acceptable to us is dependent on our ability to successfully identify, negotiate, finance and integrate acquisitions.

Customer Acquisition Costs

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 our estimate of the expected average length of a customer relationship. We factor in the recovery of customer acquisition costs in determining which markets we enter and the pricing of our products in those markets. Accordingly, our results are significantly influenced by our customer acquisition costs. Changes in customer acquisition costs from period to period reflect our focus on growing organically versus growth through acquisitions. We are currently focused on growing through organic sales channels; however, we continue to evaluate opportunities to acquire customers through acquisitions and pursue such acquisitions when it makes sense economically or strategically for the Company.

Customer Attrition

Customer attrition occurs primarily as a result of: (i) customer initiated switches; (ii) residential moves and (iii) disconnection resulting from customer payment defaults. Average monthly customer attrition for the three months ended September 30, 2019 and 2018 was 4.0% and 4.0%, respectively, and average monthly customer attrition for the nine months ended September 30, 2019 and 2018 was 4.4% and 4.0%, respectively. Consistent with our previously communicated strategy to shrink our C&I customer book, our customer attrition was slightly higher than the prior year because of our pro-active non-renewal of some of our large commercial contracts.

Customer Credit Risk

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Our bad debt expense for the three months ended September 30, 2019 and 2018 was 2.7% and 2.8%, respectively, and our bad debt expense for the nine months ended September 30, 2019 and 2018 was 3.4% and 3.2%, respectively, of non-purchase of receivable market ("non-POR") revenues. We experienced higher bad debt expense in third quarter of 2019, compared with the 2018 period, as a result of accounts receivable adjustments subsequent to our brand consolidations. In addition, as our geographic and acquisition channel mix has changed, our bad debt expense has increased. In order to manage this exposure in 2019, we have increased our focus on: collection efforts, timely billing, and credit monitoring 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. We are particularly sensitive to this variability in our residential customer segment where energy usage is highly sensitive to weather conditions that impact heating and cooling demand.

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 protection through hedging from time to time to protect us from potential volatility in markets where we have historically experienced higher exposure to extreme weather conditions. Because we attempt to match commodity purchases to anticipated demand, unanticipated changes in weather patterns can have a significant impact on our operating results and cash flows from period to period.

During the third quarter of 2019, we experienced warmer than normal weather across many of our markets, which increased demand for electricity from our customer base. In anticipation of increased demand and volatility in ERCOT, we purchased additional power to mitigate the volatility risk observed in late August and early September of 2019. These factors had a positive impact on our electricity unit margins in the third quarter of 2019.

Asset Optimization

Our asset optimization opportunities primarily arise during the winter heating season when demand for natural gas is typically at its highest. Given the opportunistic nature of these activities and because we account for these activities using the mark to market method of accounting, we experience variability in our earnings from our asset optimization activities from year to year.

Net asset optimization resulted in a loss of $0.3 million and a gain of $0.3 million for the three months ended September 30, 2019 and 2018, respectively.

Non-GAAP Performance Measures

We use the non-GAAP performance measures of Adjusted EBITDA and Retail Gross Margin to evaluate and measure our operating results as follows:

																
 	Three Months Ended September 30,	 	Nine Months Ended September 30,	
(in thousands)	2019		2018	 	2019		2018	
Adjusted EBITDA	$	28,084			$	18,611		 	$	66,742			$	50,597		
Retail Gross Margin	$	58,182			$	45,795		 	$	156,483			$	134,939		

Adjusted EBITDA. We define “Adjusted EBITDA” as EBITDA less (i) customer acquisition costs incurred in the current period, plus or minus (ii) net (loss) gain 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-

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recurring operating items. EBITDA is defined as net income (loss) before the 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. 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 (losses) gains 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 these instruments. We also deduct non-cash compensation expense that results from the issuance of restricted stock units under our long-term incentive plan due to the non-cash nature of the expense. Finally, we also adjust from time to time other non-cash or unusual and/or infrequent charges due to either their non-cash nature or their infrequency.

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;	
		
•	our ability to fund capital expenditures (including customer acquisition costs) and incur and service debt; and	
		
•	our compliance with financial debt covenants. (Refer to Note 10 "Debt" to Part I, Item 1 of this Report for discussion of the material terms of our Senior Credit Facility, including the covenant requirements for our Minimum Fixed Charge Coverage Ratio, Maximum Total Leverage Ratio, and Maximum Senior Secured Leverage Ratio.)	

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

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  	Three Months Ended September 30,		Nine Months Ended September 30,	
(in thousands)	2019		2018		2019		2018	
Reconciliation of Adjusted EBITDA to Net income:								
Net income	$	37,676			$	18,827			$	14,937			$	923		
Depreciation and amortization	9,496			13,917			31,963			39,797		
Interest expense	2,174			2,762			6,392			7,323		
Income tax expense	6,567			3,818			3,022			602		
EBITDA 	55,913			39,324			56,314			48,645		
Less:								
Net, gain (loss) on derivative instruments	12,307			18,117			(42,690	)		(1,371	)	
Net cash settlements on derivative instruments	12,721			922			33,515			(5,823	)	
Customer acquisition costs	4,423			2,695			13,608			8,949		
       Plus:												
       Non-cash compensation expense	1,622			1,021			4,054			3,707		
Non-recurring legal and regulatory settlements	—			—			10,807			—		
Adjusted EBITDA	$	28,084			$	18,611			$	66,742			$	50,597		

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)	2019		2018		2019		2018	
Reconciliation of Adjusted EBITDA to net cash provided by operating activities:								
Net cash provided by operating activities	$	26,056			$	5,443			$	77,085			$	41,853		
Amortization of deferred financing costs	(497	)		(631	)		(1,002	)		(1,243	)	
Bad debt expense	(3,170	)		(2,755	)		(9,185	)		(8,480	)	
Interest expense	2,174			2,762			6,392			7,323		
Income tax expense	6,567			3,818			3,022			602		
Changes in operating working capital								
Accounts receivable, prepaids, current assets	1,034			16,248			(50,358	)		(9,640	)	
Inventory	1,560			2,218			(298	)		(475	)	
Accounts payable and accrued liabilities	(963	)		(5,946	)		30,209			17,988		
Other	(4,677	)		(2,546	)		10,877			2,669		
Adjusted EBITDA	$	28,084			$	18,611			$	66,742			$	50,597		
Cash Flow Data:								
Cash flows provided by operating activities	$	26,056			$	5,443			$	77,085			$	41,853		
Cash flows (used in) provided by investing activities	$	(117	)		$	307			$	(6,490	)		$	(23,693	)	
Cash flows (used in) provided by financing activities	$	(10,937	)		$	1,344			$	(76,651	)		$	(4,783	)	

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Retail Gross Margin. We define retail gross margin as operating income (loss) plus (i) depreciation and amortization expenses and (ii) general and administrative expenses, less (iii) net asset optimization (expenses) 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 segments. As an indicator of our retail energy business’s operating performance, retail gross margin should not be considered an alternative to, or more meaningful than, operating income (loss), 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 (loss). The following table presents a reconciliation of Retail Gross Margin to operating income (loss) for each of the periods indicated.

																
  	Three Months Ended September 30,		Nine Months Ended September 30,	
(in thousands)	2019		2018		2019		2018	
Reconciliation of Retail Gross Margin to Operating income:								
Operating income	$	46,095			$	25,454			$	23,346			$	8,141		
Plus:												
Depreciation and amortization	9,496			13,917			31,963			39,797		
General and administrative expense	27,629			25,695			94,352			83,522		
Less:								
Net asset optimization (expenses) revenues	(254	)		348			2,242			3,798		
Net, gain (loss) on non-trading derivative instruments	12,528			17,888			(42,741	)		(2,223	)	
Net, cash settlements on non-trading derivative instruments	12,764			1,035			33,677			(5,054	)	
Retail Gross Margin	$	58,182			$	45,795			$	156,483			$	134,939		
Retail Gross Margin - Retail Electricity Segment	$	53,143			$	40,252			$	116,730			$	92,613		
Retail Gross Margin - Retail Natural Gas Segment	$	5,039			$	5,543			$	39,753			$	42,326		

Our non-GAAP financial measures of Adjusted EBITDA and Retail Gross Margin should not be considered as alternatives to net income (loss), net cash provided by (used in) operating activities, or operating income (loss). Adjusted EBITDA and Retail Gross Margin are not presentations made in accordance with GAAP and have 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 (loss), net cash provided by operating activities, and operating income (loss), 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.

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Consolidated Results of Operations

Three Months Ended September 30, 2019 Compared to Three Months Ended September 30, 2018

	
								
(In Thousands)	Three Months Ended September 30,	
	2019	 	2018	
Revenues:		 		
Retail revenues	$	207,341		 	$	258,127		
Net asset optimization (expense) revenues	(254	)	 	348		
Total Revenues	207,087		 	258,475		
Operating Expenses:			 			
Retail cost of revenues	123,867		 	193,409		
General and administrative expense	27,629		 	25,695		
Depreciation and amortization	9,496		 	13,917		
Total Operating Expenses	160,992		 	233,021		
Operating income	46,095		 	25,454		
Other (expense)/income:			 			
Interest expense	(2,174	)	 	(2,762	)	
Interest and other income	322		 	(47	)	
Total other expense	(1,852	)	 	(2,809	)	
Income before income tax expense	44,243		 	22,645		
Income tax expense	6,567		 	3,818		
Net income	$	37,676		 	$	18,827		
Other Performance Metrics:	 	 	 	
  Adjusted EBITDA (1)	$	28,084		 	$	18,611		
  Retail Gross Margin (1)	$	58,182		 	$	45,795		
  Customer Acquisition Costs	$	4,423		 	$	2,695		
  RCE Attrition	4.0	%	 	4.0	%	
(1) Adjusted EBITDA and Retail Gross Margin are non-GAAP financial measures. See " — Non-GAAP 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, 2019 were approximately $207.1 million, a decrease of approximately $51.4 million, or 20%, from approximately $258.5 million for the three months ended September 30, 2018, as indicated in the table below (in millions). This decrease was primarily due to a decrease in electricity and natural gas volumes as a result of a smaller C&I customer book in the third quarter of 2019 as compared to the third quarter of 2018, partially offset by an increase in electricity unit revenue per MWh.

				
Change in electricity volumes sold	$	(63.2	)	
Change in natural gas volumes sold	(2.4	)	
Change in electricity unit revenue per MWh	14.0		
Change in natural gas unit revenue per MMBtu	0.8		
Change in net asset optimization revenue	(0.6	)	
Change in total revenues	$	(51.4	)	

Retail Cost of Revenues. Total retail cost of revenues for the three months ended September 30, 2019 was approximately $123.9 million, a decrease of approximately $69.5 million, or 36%, from approximately $193.4 million for the three months ended September 30, 2018, as indicated in the table below (in millions). This decrease

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was primarily due to a decrease in electricity and natural gas volumes as a result of a smaller C&I customer book in 2019, a decrease in electricity unit cost per MWh and a change in the fair value of our retail derivative portfolio.

	
				
Change in electricity volumes sold	$	(52.8	)	
Change in natural gas volumes sold	(1.3	)	
Change in electricity unit cost per MWh	(9.2	)	
Change in natural gas unit cost per MMBtu	0.2		
Change in value of retail derivative portfolio	(6.4	)	
Change in retail cost of revenues	$	(69.5	)	

General and Administrative Expense. General and administrative expense for the three months ended September 30, 2019 was approximately $27.6 million, an increase of approximately $1.9 million, or 7%, as compared to $25.7 million for the three months ended September 30, 2018. This increase was primarily attributable to increased litigation expense in third quarter of 2019.

Depreciation and Amortization Expense. Depreciation and amortization expense for the three months ended September 30, 2019 was approximately $9.5 million, a decrease of approximately $4.4 million, or 32%, from approximately $13.9 million for the three months ended September 30, 2018. This decrease was primarily due to the decreased amortization expense associated with customer intangibles.

Customer Acquisition Cost. Customer acquisition cost for the three months ended September 30, 2019 was approximately $4.4 million, an increase of approximately $1.7 million, or 64%, from approximately $2.7 million for the three months ended September 30, 2018. This increase was primarily due to an increase in the number of organic sales in 2019 as compared to 2018, as we had slowed our organic sales in 2018 to concentrate on acquisitions of companies and portfolios of customers.

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Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018

	
								
(In Thousands)	Nine Months Ended September 30,	
	2019		2018	
Revenues:				
Retail revenues	$	625,300			$	773,616		
Net asset optimization revenues	2,242			3,798		
Total Revenues	627,542			777,414		
Operating Expenses:						
Retail cost of revenues	477,881			645,954		
General and administrative	94,352			83,522		
Depreciation and amortization	31,963			39,797		
Total Operating Expenses	604,196			769,273		
Operating income	23,346			8,141		
Other (expense)/income:						
Interest expense	(6,392	)		(7,323	)	
Interest and other income	1,005			707		
Total other expense	(5,387	)		(6,616	)	
Income before income tax expense	17,959			1,525		
Income tax expense	3,022			602		
Net income	$	14,937			$	923		
Other Performance Metrics:	 	 	 	
Adjusted EBITDA (1)	$	66,742			$	50,597		
Retail Gross Margin (1)	$	156,483			$	134,939		
Customer Acquisition Costs	$	13,608			$	8,949		
RCE Attrition	4.4	%		4.0	%	
(1) Adjusted EBITDA and Retail Gross Margin are non GAAP financial measures. See " — Non-GAAP Performance Measures" for a reconciliation of Adjusted EBITDA and Retail Gross Margin to their most directly comparable financial measures presented in accordance with GAAP.

Total Revenues. Total revenues for the nine months ended September 30, 2019 were approximately $627.5 million, a decrease of approximately $149.9 million, or 19%, from approximately $777.4 million for the nine months ended September 30, 2018, as indicated in the table below (in millions). This decrease was primarily due to a decrease in electricity and natural gas volumes as a result of a smaller C&I customer book in 2019 as compared to 2018, partially offset by an increase in electricity unit revenue per MWh.

				
Change in electricity volumes sold	$	(172.7	)	
Change in natural gas volumes sold	(14.6	)	
Change in electricity unit revenue per MWh	36.1		
Change in natural gas unit revenue per MMBtu	2.9		
Change in net asset optimization revenue (expense)	(1.6	)	
Change in total revenues	$	(149.9	)	

Retail Cost of Revenues. Total retail cost of revenues for the nine months ended September 30, 2019 was approximately $477.9 million, a decrease of approximately $168.1 million, or 26%, from approximately $646.0 million for the nine months ended September 30, 2018, as indicated in the table below (in millions). This decrease was primarily due to a decrease in electricity and natural gas volumes as a result of a smaller C&I customer book in

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2019 and, a decrease in electricity unit cost per MWh, partially offset by a change in fair value of our retail derivative portfolio.

	
				
Change in electricity volumes sold	$	(149.1	)	
Change in natural gas volumes sold	(8.2	)	
Change in electricity unit cost per MWh	(11.6	)	
Change in natural gas unit cost per MMBtu	(0.9	)	
Change in value of retail derivative portfolio	1.7		
Change in retail cost of revenues	$	(168.1	)	

General and Administrative Expense. General and administrative expense for the nine months ended September 30, 2019 was approximately $94.3 million, an increase of approximately $10.8 million, or 13%, as compared to $83.5 million for the nine months ended September 30, 2018. This increase was primarily attributable to non-recurring legal and regulatory settlements and increased litigation expense in the second quarter of 2019.

Depreciation and Amortization Expense. Depreciation and amortization expense for the nine months ended September 30, 2019 was approximately $32.0 million, a decrease of approximately $7.8 million, or 20%, from approximately $39.8 million for the nine months ended September 30, 2018. This decrease was primarily due to the decreased amortization expense associated with customer relationship intangibles.

Customer Acquisition Cost. Customer acquisition cost for the nine months ended September 30, 2019 was approximately $13.6 million, an increase of approximately $4.7 million, or 52%, from approximately $8.9 million for the nine months ended September 30, 2018. This increase was primarily due to an increase in the number of organic sales in 2019 as compared to 2018, as we had slowed our organic sales in 2018 to concentrate on acquisitions of companies and portfolios of customers.

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Operating Segment Results

																
 	Three Months Ended 
 September 30,		Nine Months Ended 
 September 30,	
  	2019		2018		2019		2018	
 	(in thousands, except volume and per unit operating data)	
Retail Electricity Segment								
Total Revenues	$	197,010			$	246,182			$	539,878			$	676,528		
Retail Cost of Revenues	119,100			186,449			433,175			587,949		
Less: Net gain (loss) on non-trading derivatives, net of cash settlements	24,767			19,481			(10,027	)		(4,034	)	
Retail Gross Margin (1)  — Electricity	$	53,143			$	40,252			$	116,730			$	92,613		
Volumes — Electricity (MWhs)	1,808,276			2,432,314			5,052,498			6,784,345		
Retail Gross Margin (2) — Electricity per MWh	$	29.39			$	16.55			$	23.10			$	13.65		
								
Retail Natural Gas Segment								
Total Revenues	$	10,331			$	11,945			$	85,422			$	97,088		
Retail Cost of Revenues	4,767			6,960			44,706			58,005		
Less: Net gain (loss) on non-trading derivatives, net of cash settlements	525			(558	)		963			(3,243	)	
Retail Gross Margin (1) — Gas	$	5,039			$	5,543			$	39,753			$	42,326		
Volumes — Gas (MMBtus)	1,119,126			1,395,377			10,127,857			11,913,180		
Retail Gross Margin (2) — Gas per MMBtu	$	4.50			$	3.97			$	3.93			$	3.55		

(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 " —Non-GAAP Performance Measures" for a reconciliation of Retail Gross Margin to most directly comparable financial measures 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, 2019 Compared to Three Months Ended September 30, 2018
Retail Electricity Segment
Total revenues for the Retail Electricity Segment for the three months ended September 30, 2019 were approximately $197.0 million, a decrease of approximately $49.2 million, or 20%, from approximately $246.2 million for the three months ended September 30, 2018. This decrease was largely due to lower volumes sold, resulting in a decrease of $63.2 million as a result of a smaller C&I customer book in 2019. This decrease was partially offset by higher electricity prices as a result of the decrease of C&I RCEs as a total percentage of our customer book, which resulted in an increase of $14.0 million.
Retail cost of revenues for the Retail Electricity Segment for the three months ended September 30, 2019 were approximately $119.1 million, a decrease of approximately $67.3 million, or 36%, from approximately $186.4 million for the three months ended September 30, 2018. This decrease was primarily due to fewer C&I customers, resulting in a decrease of $52.8 million, a decrease in supply costs of $9.2 million, and a change in the value of our retail derivative portfolio used for hedging, which resulted in a decrease of $5.3 million.
Retail gross margin for the Retail Electricity Segment for the three months ended September 30, 2019 was approximately $53.1 million, an increase of approximately $12.8 million, or 32%, from approximately $40.3 million for the three months ended September 30, 2018, as indicated in the table below (in millions).

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Change in volumes sold	$	(10.3	)	
Change in unit margin per MWh	23.1		
Change in retail electricity segment retail gross margin	$	12.8		
Retail Natural Gas Segment
Total revenues for the Retail Natural Gas Segment for the three months ended September 30, 2019 were approximately $10.3 million, a decrease of approximately $1.6 million, or 14%, from approximately $11.9 million for the three months ended September 30, 2018. This decrease was primarily attributable to lower volumes sold, which decreased total revenues by $2.4 million, offset by an increase in natural gas rates, which resulted in an increase in total revenues of $0.8 million.
Retail cost of revenues for the Retail Natural Gas Segment for the three months ended September 30, 2019 were approximately $4.8 million, a decrease of $2.2 million, or 32%, from approximately $7.0 million for the three months ended September 30, 2018. This decrease was primarily due to lower volumes resulting in a decrease of $1.3 million, a change in the value of our derivative portfolio used for hedging, which resulted in a decrease of $1.1 million, offset by higher natural gas prices, which resulted in an increase of $0.2 million.
Retail gross margin for the Retail Natural Gas Segment for the three months ended September 30, 2019 was approximately $5.0 million, a decrease of approximately $0.5 million, or 9%, from approximately $5.5 million for the three months ended September 30, 2018, as indicated in the table below (in millions).

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

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Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018
Retail Electricity Segment
Total revenues for the Retail Electricity Segment for the nine months ended September 30, 2019 were approximately $539.9 million, a decrease of approximately $136.6 million, or 20%, from approximately $676.5 million for the nine months ended September 30, 2018. This decrease was largely due to a decrease in volumes, resulting in a decrease of $172.7 million. This was partially offset by higher weighted average revenue rates, due to our customer mix shifting away from large commercial customers, which resulted in an increase of $36.1 million.
Retail cost of revenues for the Retail Electricity Segment for the nine months ended September 30, 2019 was approximately $433.2 million, a decrease of approximately $154.7 million, or 26%, from approximately $587.9 million for the nine months ended September 30, 2018. This decrease was primarily due to a decrease in volumes, resulting in a decrease of $149.1 million. This decrease was further impacted by decreased electricity prices, which resulted in a decrease in retail cost of revenues of $11.6 million. These decreases were partially offset by an increase of $6.0 million due to a change in the value of our retail derivative portfolio used for hedging.
Retail gross margin for the Retail Electricity Segment for the nine months ended September 30, 2019 was approximately $116.7 million, an increase of approximately $24.1 million, or 26%, from approximately $92.6 million for the nine months ended September 30, 2018, as indicated in the table below (in millions).

				
Change in volumes sold	$	(23.6	)	
Change in unit margin per MWh	47.7		
Change in retail electricity segment retail gross margin	$	24.1		
Retail Natural Gas Segment
Total revenues for the Retail Natural Gas Segment for the nine months ended September 30, 2019 were approximately $85.4 million, a decrease of approximately $11.7 million, or 12%, from approximately $97.1 million for the nine months ended September 30, 2018. This decrease was primarily attributable to a decrease in volumes of $14.6 million, partially offset by higher rates, which resulted in an increase in total revenues of $2.9 million.
Retail cost of revenues for the Retail Natural Gas Segment for the nine months ended September 30, 2019 was approximately $44.7 million, a decrease of approximately $13.3 million, or 23%, from approximately $58.0 million for the nine months ended September 30, 2018. This decrease was due to decreased supply costs of $0.9 million, a decrease of $8.2 million related to decreased volumes, and a $4.2 million change in the fair value of our retail derivative portfolio used for hedging.
Retail gross margin for the Retail Natural Gas Segment for the nine months ended September 30, 2019 was approximately $39.8 million, a decrease of approximately $2.5 million, or 6%, from approximately $42.3 million for the nine months ended September 30, 2018, as indicated in the table below (in millions).

				
Change in volumes sold	$	(6.3	)	
Change in unit margin per MMBtu	3.8		
Change in retail natural gas segment retail gross margin	$	(2.5	)	

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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 level of customer acquisition costs, acquisitions, collateral posting requirements on our derivative instruments portfolio, distributions, the effects of the timing between the settlement of payables and receivables, including the effect of bad debts, 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. Estimating our liquidity requirements is highly dependent on then-current market conditions, including weather events, forward prices for natural gas and electricity, market volatility and our then existing capital structure and requirements.

We believe that the financing of any additional growth through acquisitions and/or the need for more liquidity in fourth quarter 2019 and first half of 2020 may require further equity or debt financing and/or further expansion of our Senior Credit Facility.

Liquidity Position

The following table details our available liquidity as of September 30, 2019:

				
($ in thousands)	September 30, 2019	
Cash and cash equivalents	$	42,580		
Senior Credit Facility Availability (1)	63,113		
Subordinated Debt Facility Availability (2)	14,496		
Total Liquidity	$	120,189		
(1) Reflects amount of Letters of Credit that could be issued based on existing covenants as of September 30, 2019.
(2) The availability of the Subordinated Facility is dependent on our Founder's willingness and ability to lend. See "—Sources of Liquidity— 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.

For further discussion of our Senior Credit Facility and the Subordinated Debt Facility, see Note 10 "Debt."

Cash Flows

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

												
  	Nine Months Ended September 30,			
  	2019		2018		Change	
Net cash provided by operating activities	$	77,085			$	41,853			$	35,232		
Net cash used in investing activities	$	(6,490	)		$	(23,693	)		$	17,203		
Net cash used in financing activities	$	(76,651	)		$	(4,783	)		$	(71,868	)	

Nine Months Ended September 30, 2019 Compared to the Nine Months Ended September 30, 2018

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Cash Flows Provided by Operating Activities. Cash flows provided by operating activities for the nine months ended September 30, 2019 increased by $35.2 million compared to the nine months ended September 30, 2018. The increase was primarily the result of higher net income in 2019, coupled with a decrease in the changes in working capital for the nine months ended September 30, 2019 primarily due to declines in accounts receivable and accounts payable attributable to lower sales and cost of sales during the 2019 period.

Cash Flows Used in Investing Activities. Cash flows used in investing activities decreased by $17.2 million for the nine months ended September 30, 2019. The decrease was primarily the result of the amount paid for acquisitions during the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018.

Cash Flows Used in Financing Activities. Cash flows used in financing activities increased by $71.9 million for the nine months ended September 30, 2019. Cash flows used in financing activities increased primarily due to an increased net paydown of our Senior Credit Facility of $17.3 million for the nine months ended September 30, 2019 as well as an increase in payment of TRA liability of $7.6 million and distributions to non-controlling interest holders of $4.4 million, primarily due to the settlement of the TRA liability in July 2019. In addition, for the nine months ended September 30, 2018, we received proceeds from the issuance of Series A Preferred Stock of approximately $48.5 million, which did not reoccur during the nine months ended September 30, 2019.

Sources of Liquidity and Capital Resources

Senior Credit Facility

As of September 30, 2019, our Senior Credit Facility had total commitments of $217.5 million, of which $149.3 million was outstanding, including $40.3 million of outstanding letters of credit. Under the Senior Credit Facility, we have various limits on advances for Working Capital Loans, Letters of Credit and Bridge Loans. The Senior Credit Facility matures on May 19, 2021. 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 10 "Debt" in the notes to our condensed consolidated financial statements. As of September 30, 2019, we were in compliance with the covenants under our Senior Credit Facility.

Amended and Restated Subordinated Debt Facility

Our Subordinated Debt Facility allows us to draw advances in increments of no less than $1.0 million per advance up to $25.0 million. Although we may use the Subordinated Debt Facility from time to time to enhance short term liquidity, we do not view the Subordinated Debt Facility as a material source of liquidity. See Note 10 "Debt" for additional details. As of September 30, 2019, there was $10.5 million outstanding borrowings under the Subordinated Debt Facility.

Uses of Liquidity and Capital Resources

Repayment of Current Portion of Senior Credit Facility

Our Senior Credit Facility matures in 2021, and thus, no amounts are due currently. However, due to the revolving nature of the facility, excess cash available is generally used to reduce the balance outstanding, which at September 30, 2019 was $109.0 million. The current variable interest rate on the facility at September 30, 2019 was 5.19%.

Customer Acquisitions

Our customer acquisition strategy consists of customer growth obtained through organic customer additions as well as opportunistic acquisitions. During the three months ended September 30, 2019 and 2018, we spent a total of $4.4 million and $2.7 million, respectively, on organic customer acquisitions. During the nine months ended September

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30, 2019 and 2018, we spent a total of $13.6 million and $8.9 million, respectively, on organic customer acquisitions.

Capital Expenditures

Our capital requirements each year are relatively low and generally consist of minor purchases of equipment or information system upgrades and improvements. Capital expenditures for the nine months ended September 30, 2019 included $0.6 million related to information systems improvements.

Dividends and Distributions

During the nine months ended September 30, 2019, we paid dividends to holders of our Class A common stock for the quarter ended December 31, 2018, March 31, 2019, and June 30, 2019 of approximately $0.18125 per share for each dividend declaration or $7.8 million in the aggregate. In order to pay our stated dividends to holders of our Class A common stock, our subsidiary, Spark HoldCo is required to make corresponding distributions to holders of its units, including those holders that own our Class B common stock (our non-controlling interest holder). As a result, during the nine months ended September 30, 2019, Spark HoldCo made corresponding distributions of $11.3 million to our non-controlling interest holders.

For the nine months ended September 30, 2019, we paid $6.1 million related to dividends to holders of Series A Preferred Stock. As of September 30, 2019, we had accrued $2.0 million related to dividends to holders of our Series A Preferred Stock, which was paid on October 15, 2019. For the full year ended December 31, 2019, 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, 2019.

On October 21, 2019, our Board of Directors declared a quarterly dividend of $0.18125 per share of the Class A common stock and $0.546875 for the Series A Preferred Stock for the third quarter of 2019. Dividend on Class A common stock will be paid on December 16, 2019 to the holders of record as of December 2, 2019, and Series A Preferred Stock dividends will be paid on January 15, 2020 to the holders of record as of January 1, 2020.

Our ability to pay dividends in the future will depend on many factors, including the performance of our business and restrictions under our Senior Credit Facility. If our business does not generate sufficient cash for Spark HoldCo to make distributions to us to fund our Class A common stock and Series A Preferred Stock dividends, we may have to borrow to pay such amounts. Further, even if our business generates cash in excess of our current annual dividend (of $0.725 per share on our Class A common stock), we may reinvest such excess cash flows in 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 the results of our operations, our financial condition, capital requirements and investment opportunities.

Tax Receivable Agreement

Prior to July 11, 2019, we were party to a TRA with affiliates. The TRA was terminated on July 11, 2019. See "— Recent Developments" above. The TRA generally provided for the payment by the Company of 85% of the net cash savings, if any, in U.S. federal, state and local income tax or franchise tax that the Company actually realized (or was deemed to have realized in certain circumstances) in future periods. The Company retained the benefit of the remaining 15% of these tax savings.
As of each of September 30, 2019 and December 31, 2018, we had a total liability related to the TRA on our balance sheet of zero and $27.6 million, respectively. In July 2019, we terminated the TRA and paid $11.2 million to settle all obligations related to the TRA. See "— Recent Developments" above for details of the Release Agreement.

Verde Promissory Note

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In January 2018, we issued an amended and restated promissory note to the sellers of the Verde Companies (the "Verde Promissory Note”). As of December 31, 2018, there was $1.0 million outstanding under the Verde Promissory Note, all of which was paid in January 2019. The note bore interest at 9% per annum, and we made monthly payments of principal and associated interest, a portion of which was deposited into an escrow account to provide security for certain indemnification claims and obligations under the Verde purchase agreement. As of September 30, 2019 and December 31, 2018, a total of $5.3 million and $7.6 million, respectively, was held in escrow for such claims.

Verde Earnout Termination Note

In January 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 matured in June 2019 and bore interest at a rate of 9% per annum. Under the terms of the Verde Earnout Termination Note, we were permitted to withhold amounts otherwise due at maturity related to certain indemnifiable matters. A payment of $1.0 million was made to the seller of the Verde Companies in June 2019, and $4.9 million was withheld (the “Verde Holdback”) to be applied to indemnifiable matters. For the nine months ended September 30, 2019, approximately $0.2 million of the Verde Holdback was applied to costs incurred related to indemnifiable matters. As of September 30, 2019, $4.4 million of the Verde Holdback was classified as accrued liabilities, and $0.3 million was classified as other current liabilities related to indemnifiable matters. Interest was payable monthly on the first day of each month. As of September 30, 2019 and December 31, 2018, there was zero and $5.9 million outstanding under the Verde Earnout Termination Note, respectively.

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Off-Balance Sheet Arrangements
As of September 30, 2019, we had no material "off-balance sheet arrangements."

Related Party Transactions

For a discussion of related party transactions, see Note 14 "Transactions with Affiliates" to Part I, Item 1 of this Report.
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 2018 Form 10-K. There have been no changes to these policies and estimates since the date of our 2018 Form 10-K.

Refer to Note 2 "Basis of Presentation and Summary of Significant Accounting Policies" to Part I, Item 1 of this Report 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" to Part I, Item 1 of this Report, as of September 30, 2019, management did 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 legal and regulatory matters, see Note 13 "Commitments and Contingencies" to Part I, Item 1 of this Report.

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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 risk management policies and procedures to manage, measure, and limit 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. Generally, any such instruments that are entered into to support our retail electricity and natural gas business are categorized as having been entered into for non-trading purposes, and instruments entered into for any other purpose are categorized as having been entered into for trading purposes.

Our net gain (loss) on our non-trading derivative instruments, net of cash settlements, was $25.3 million and $18.9 million for the three months ended September 30, 2019 and 2018, respectively, and $(9.1) million and $(7.3) million for the nine months ended September 30, 2019 and 2018, 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 2018 Form 10-K.

We measure the commodity risk of our non-trading energy derivatives using a sensitivity analysis on our net open position. As of September 30, 2019, our Gas Non-Trading Fixed Price Open Position (hedges net of retail load) was a short position of 33,366 MMBtu. An increase of 10% in the market prices (NYMEX) from their September 30, 2019 levels would have increased the fair market value of our net non-trading energy portfolio by less than $0.1 million. Likewise, a decrease of 10% in the market prices (NYMEX) from their September 30, 2019 levels would have decreased the fair market value of our non-trading energy derivatives by less than $0.1 million. As of September 30, 2019, our Electricity Non-Trading Fixed Price Open Position (hedges net of retail load) was a long position of 30,147 MWhs. An increase of 10% in the forward market prices from their September 30, 2019 levels would have increased the fair market value of our net non-trading energy portfolio by $0.7 million. Likewise, a decrease of 10% in the forward market prices from their September 30, 2019 levels would have decreased the fair market value of our non-trading energy derivatives by $0.7 million.

Credit Risk

In many of the utility services territories where we conduct business, Purchase of Receivables ("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 with the utility and not to our end-use customer in these territories. Approximately 68% and 69% of our retail revenues were derived from territories in which substantially all of our credit risk was with local regulated utility companies for the three months ended September 30, 2019 and 2018, respectively, and 67% and 68% for the nine months ended September 30, 2019 and 2018, respectively, all of which had investment grade ratings as of such date. We paid these local regulated utilities a weighted average discount of approximately 0.9% and 0.9% for the

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three months ended September 30, 2019 and 2018, respectively, and 0.9% and 1.0% for the nine months ended September 30, 2019 and 2018, 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.

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 months ended September 30, 2019 and 2018 was approximately 2.7% and 2.8% of non-POR market retail revenues, respectively, and our bad debt expense for the nine months ended September 30, 2019 and 2018 was approximately 3.4% and 3.2% of non-POR market retail revenues, respectively. See “Management's Discussion and Analysis of Financial Condition and Results of Operations—Drivers of Our Business—Customer Credit Risk” for an analysis of our bad debt expense related to non-POR markets during the nine months ended September 30, 2019.
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, 2019, approximately $0.4 million of our total exposure of $2.7 million was either with a non-investment grade counterparty or otherwise not secured with collateral or a guarantee. The credit worthiness of the remaining exposure with other customers was evaluated with no material allowance recorded at September 30, 2019.
Interest Rate Risk
We are exposed to fluctuations in interest rates under our variable-price debt obligations. At September 30, 2019, we were co-borrowers under the Senior Credit Facility, under which $109.0 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, 2019, a 1% increase in interest rates would have resulted in additional annual interest expense of approximately $1.1 million. During 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, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2019 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, 2019 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 Note 13 "Commitments and Contingencies" to Part I, Item 1 of this Report, which is incorporated by reference into this Part II, Item 1, for a description of certain ligation, legal proceedings, and regulatory matters.

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 2018 Form 10-K and that certain risk factor in our Quarterly Report on Form 10-Q for the second quarter of 2019 that states: "We cannot guarantee that our Repurchase Program will enhance shareholder value and purchases if any, could increase the volatility of the price of our Series A Preferred Stock," which are incorporated herein by reference. There has been no material change in our risk factors from those described in the 2018 Form 10-K and our Quarterly Report on Form 10-Q for the second quarter of 2019. 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.

There were no unregistered sales of equity securities during the three months ended September 30, 2019.

The following table sets forth information regarding purchases of our Series A Preferred Stock by us during the three months ended September 30, 2019 pursuant to our Repurchase Program.

	
															
Period	(a) Total Number of Shares Purchased	 	(b) Average Price Paid per Share	 	(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (1)	 	(d) Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs	
July 1 - July 31, 2019	—		 	$	—		 	$	—		 	—		
August 1 - August 31, 2019	—		 	—		 	—		 	—		
September 1 - September 30, 2019	—		 	—		 	—		 	—		
Total	—		 	$	—		 	—		 	$	—		
(1) On May 22, 2019, the Company announced that the Board of Directors authorized the Repurchase Program to purchase shares of Series A Preferred Stock through May 20, 2020. There is no dollar limit on the amount of Series A Preferred Stock that may be purchased. The Repurchase Program does not obligate us to make any repurchases and may be suspended for periods or discontinued at any time.

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Item 6. Exhibits	

The exhibits required to be filed by Item 6 are set forth in the Exhibit Index included below.

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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 Menchaca.		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	 	 	TRA Termination and Release Agreement, dated July 11, 2019, by and among Spark Energy, Inc., Spark HoldCo, LLC, Retailco, LLC, NuDevco Retail, LLC and W. Keith Maxwell III.	 	8-K	 	10.1	7/17/2019	001-36559	
10.2 †	 	 	Indemnification Agreement, dated August 29, 2019, by and among Spark Energy, Inc. and Amanda Bush	 	8-K	 	10.1†	8/30/2019	001-36559	
10.3	 	 	Transition and Resignation Agreement and Mutual Release of Claims, by and between Spark Energy, Inc. and Jason Garrett, dated September 25, 2019	 	8-K	 	10.1	9/27/2019	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 6, 2019	 	 	/s/ James G. Jones II	
 	 	 	James G. Jones II	
 	 	 	Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)	

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EXHIBIT 31.1
CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A) OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED
I, Nathan Kroeker, certify that:

1. I have reviewed this Quarterly Report (the “report”) on Form 10-Q of Spark Energy, Inc. (the “registrant”);
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 6, 2019
 
/s/ Nathan Kroeker
Nathan Kroeker
President and Chief Executive Officer
(Principal Executive Officer)

EXHIBIT 31.2
CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A) OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED
I, James G. Jones II, certify that:
1. I have reviewed this Quarterly Report (the “report”) on Form 10-Q of Spark Energy, Inc. (the “registrant”);
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 6, 2019
 
/s/ James G. Jones II
James G. Jones II
Chief Financial Officer
(Principal Accounting and Financial Officer)

EXHIBIT 32

Certification by the Principal Executive Officer and Principal Financial Officer
Pursuant to 18 U.S.C. Section 1350,
Adopted Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002

          In connection with the Quarterly Report on Form 10-Q for the quarter ended September 30, 2019 (the “Report”) of Spark Energy, Inc., a Delaware corporation (the “Company”), as filed with the Securities and Exchange Commission on the date hereof, Nathan Kroeker, Principal Executive Officer of the Company and James G. Jones II, Principal Financial Officer of the Company, each certify, pursuant 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:

		
1.	This Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and	

2.	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.	

Date: November 6, 2019

/s/ Nathan Kroeker
Nathan Kroeker
President and Chief Executive Officer
             (Principal Executive Officer)

/s/ James G. Jones II
James G. Jones II
Chief Financial Officer
(Principal Accounting and Financial Officer)