UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549	

		FORM 10-Q			
 
☒      QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2021
 
☐         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 ☒	No ☐

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 ☒	No ☐

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 ☐  Accelerated filer ☒  
Non-accelerated filer ☐     Smaller reporting company ☐
Emerging Growth Company ☐

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

There were 15,572,388 shares of Class A common stock, 20,000,000 shares of Class B common stock and 3,567,543 shares of Series A Preferred Stock outstanding as of August 3, 2021.

SPARK ENERGY, INC.			
INDEX TO QUARTERLY REPORT ON FORM 10-Q			
For the Quarter Ended June 30, 2021			
		Page No.	
PART I. FINANCIAL INFORMATION			
ITEM 1. FINANCIAL STATEMENTS			
			
CONDENSED CONSOLIDATED BALANCE SHEETS AS OF JUNE 30, 2021 AND DECEMBER 31, 2020 (unaudited)		5	
			
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2021 AND 2020 (unaudited)		7	
			
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY FOR THREE AND SIX MONTHS ENDED JUNE 30, 2021 AND 2020 (unaudited)		8	
			
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE SIX MONTHS ENDED JUNE 30, 2021 AND 2020 (unaudited)		13	
			
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (unaudited)		14	
			
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		41	
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		59	
ITEM 4. CONTROLS AND PROCEDURES		61	
PART II. OTHER INFORMATION		62	
ITEM 1. LEGAL PROCEEDINGS		62	
ITEM 1A. RISK FACTORS		62	
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		62	
ITEM 6. EXHIBITS		63	
SIGNATURES		65	

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,” “could,” “likely,” “will,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” “plan,” “intend,” “project,” or other similar words. Forward-looking statements appear in a number of places in this Report. All statements, other than statements of historical fact, included in this Report are forward-looking statements. The forward-looking statements include statements regarding the impacts of COVID-19 and the 2021 severe weather event, cash flow generation and liquidity, business strategy, prospects for growth, outcomes of legal proceedings, ability to pay cash dividends, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans, objectives, beliefs of management, availability and terms of capital, competition, governmental 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:

•	evolving risks, uncertainties and impacts relating to COVID-19, including the geographic spread, the severity of the disease, the scope and duration of the COVID-19 outbreak, actions that may be taken by governmental authorities to contain the COVID-19 outbreak or to treat its impact, and the potential for continuing negative impacts of COVID-19 on economies and financial markets;
•	the ultimate impact of the 2021 severe weather event, including resolution of outstanding pricing and volume settlement data from ERCOT; the results of formal disputes regarding pricing and volume settlement data received to date;  and any corrective action by the State of Texas, ERCOT, the Railroad Commission of Texas, or the Public Utility Commission of Texas;
•	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 independent system operators (“ISOs”) in the regions we operate;
•	competition; and
•	the “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2020, and in our other public filings and press releases.

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

PART I. — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

SPARK ENERGY, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands, except share counts)
(unaudited)
	June 30, 2021		December 31, 2020	
Assets				
Current assets:				
Cash and cash equivalents	$	93,035			$	71,684		
Restricted cash		11,505				—		
Accounts receivable, net of allowance for doubtful accounts of $2,381 at June 30, 2021 and $3,942 at December 31, 2020		45,406				70,350		
Accounts receivable—affiliates		4,672				5,053		
Inventory		1,096				1,496		
Fair value of derivative assets		16,528				311		
Customer acquisition costs, net		2,274				5,764		
Customer relationships, net		10,730				12,077		
Deposits		5,546				5,655		
Renewable energy credit asset		11,102				20,666		
Other current assets		14,597				11,818		
Total current assets		216,491				204,874		
Property and equipment, net		3,631				3,354		
Fair value of derivative assets		1,069				—		
Customer acquisition costs, net		239				306		
Customer relationships, net		984				5,691		
Deferred tax assets		23,280				27,960		
Goodwill		120,343				120,343		
Other assets		3,117				4,139		
Total assets	$	369,154			$	366,667		
Liabilities, Series A Preferred Stock and Stockholders' Equity				
Current liabilities:				
Accounts payable	$	26,258			$	27,322		
Accounts payable—affiliates		444				826		
Accrued liabilities		29,240				34,164		
Renewable energy credit liability		12,580				19,549		
Fair value of derivative liabilities		21				7,505		
Other current liabilities		1,227				1,295		
Total current liabilities		69,770				90,661		
Long-term liabilities:				
Fair value of derivative liabilities		—				227		
Long-term portion of Senior Credit Facility		135,000				100,000		
Subordinated debt—affiliates		10,000				—		
Other long-term liabilities		—				30		
Total liabilities		214,770				190,918		
Commitments and contingencies (Note 12)				
Series A Preferred Stock, par value $0.01 per share, 20,000,000 shares authorized, 3,707,256 shares issued and 3,567,543 shares outstanding at June 30, 2021 and December 31, 2020		87,288				87,288		
Stockholders' equity:				
       Common Stock:				
Class A common stock, par value $0.01 per share, 120,000,000 shares authorized, 14,916,982 shares issued and 14,772,388 shares outstanding at June 30, 2021 and 14,771,878 shares issued and 14,627,284 shares outstanding at December 31, 2020		149				148		
Class B common stock, par value $0.01 per share, 60,000,000 shares authorized, 20,800,000 shares issued and outstanding at June 30, 2021 and December 31, 2020		209				209		
       Additional paid-in capital		52,878				55,222		
       Accumulated other comprehensive loss		(40)			(40)	
       Retained earnings 		7,994				11,721		
       Treasury stock, at cost, 144,594 shares at June 30, 2021 and December 31, 2020		(2,406)			(2,406)	
       Total stockholders' equity		58,784				64,854		
Non-controlling interest in Spark HoldCo, LLC		8,312				23,607		
       Total equity		67,096				88,461		
Total liabilities, Series A Preferred Stock and Stockholders' equity	$	369,154			$	366,667		

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

SPARK ENERGY, INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS  
(in thousands, except per share data) 
(unaudited)
	Three Months Ended June 30,		Six Months Ended June 30,	
	2021		2020		2021		2020	
Revenues:								
Retail revenues	$	82,309			$	128,618			$	195,454			$	294,978		
Net asset optimization (expense) revenue		(114)			(82)			(254)			239		
Total Revenues		82,195				128,536				195,200				295,217		
Operating Expenses:								
Retail cost of revenues		36,176				65,605				158,344				184,428		
General and administrative 		10,663				21,331				23,334				47,007		
Depreciation and amortization		5,413				8,010				11,449				16,806		
Total Operating Expenses		52,252				94,946				193,127				248,241		
Operating income		29,943				33,590				2,073				46,976		
Other (expense)/income:								
Interest expense		(1,552)			(1,193)			(2,863)			(2,746)	
Interest and other income 		79				53				165				213		
Total other expenses		(1,473)			(1,140)			(2,698)			(2,533)	
Income (loss) before income tax expense 		28,470				32,450				(625)			44,443		
Income tax expense 		3,674				5,673				2,139				7,598		
Net income (loss)	$	24,796			$	26,777			$	(2,764)		$	36,845		
Less: Net income (loss) attributable to non-controlling interests		14,313				15,618				(5,616)			21,207		
Net income attributable to Spark Energy, Inc. stockholders	$	10,483			$	11,159			$	2,852			$	15,638		
Less: Dividend on Series A Preferred Stock		1,951				2,039				3,902				3,539		
Net income (loss) attributable to stockholders of Class A common stock	$	8,532			$	9,120			$	(1,050)		$	12,099		
								
Net income (loss) attributable to Spark Energy, Inc. per share of Class A common stock 								
       Basic	$	0.58			$	0.63			$	(0.07)		$	0.84		
       Diluted	$	0.58			$	0.62			$	(0.07)		$	0.83		
								
Weighted average shares of Class A common stock outstanding								
       Basic		14,685				14,558				14,656				14,469		
       Diluted		14,821				14,763				14,767				14,569		
								
The accompanying notes are an integral part of the condensed consolidated financial statements.

SPARK ENERGY, INC.
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
(in thousands)
(unaudited)
Six Months Ended June 30, 2021	
	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, 2020		14,772			20,800			(144)		$	148		$	209		$	(2,406)		$	(40)		$	55,222		$	11,721		$	64,854		$	23,607		$	88,461		
Stock based compensation		—			—			—			—			—			—			—			1,402			—			1,402			—			1,402		
Restricted stock unit vesting		145			—			—			1			—			—			—			(588)			—			(587)		—			(587)	
Consolidated net income (loss)		—			—			—			—			—			—			—			—			2,852			2,852			(5,616)		(2,764)	
Distributions paid to non-controlling unit holders		—			—			—			—			—			—			—			—			—			—			(10,186)		(10,186)	
Dividends paid to Class A common stockholders ($0.3625 per share)		—			—			—			—			—			—			—			(2,651)			(2,677)			(5,328)		—			(5,328)	
Dividends paid to Preferred Stockholders		—			—			—			—			—			—			—			—			(3,902)			(3,902)		—			(3,902)	
Changes in ownership interest		—			—			—			—			—			—			—			(507)			—			(507)		507			—		
Balance at June 30, 2021		14,917			20,800			(144)		$	149		$	209		$	(2,406)		$	(40)		$	52,878		$	7,994		$	58,784		$	8,312		$	67,096		

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

Three Months Ended June 30, 2021	
	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 March 31, 2021	14,772	20,800		(144)	$	148		$	209		$	(2,406)	$	(40)	$	52,904		$	2,139		$	52,954		$	(2,717)	$	50,237		
Stock based compensation	—	—	—	—	—	—		—		1,025	—	1,025	—	1,025	
Restricted stock unit vesting	145	—	—	1	—	—	—	(588)	—	(587)	—	(587)	
Consolidated net income		—			—			—			—			—			—			—			—		10,483	10,483	14,313	24,796	
Distributions paid to non-controlling unit holders	—	—	—	—	—	—	—	—	—	—	(3,747)	(3,747)	
Dividends paid to Class A common stockholders ($0.18125 per share)	—	—	—	—	—	—	—	—	(2,677)	(2,677)	—	(2,677)	
Dividends paid to Preferred Stockholders	—	—	—	—	—	—	—	—	(1,951)	(1,951)	—	(1,951)	
Changes in Ownership Interest	—	—	—	—	—	—	—	(463)	—	(463)	463	—	
Balance at June 30, 2021		14,917			20,800			(144)	$	149		$	209		$	(2,406)	$	(40)	$	52,878		$	7,994		$	58,784		$	8,312		$	67,096		

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

Six Months Ended June 30, 2020	
	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, 2019		14,479			20,800			(99)		$	145		$	209		$	(2,011)		$	(40)		$	51,842		$	1,074		$	51,219		$	16,067		$	67,286		
Impact of adoption of ASC 326		—			—			—			—			—			—			—			—			(633)			(633)		—			(633)	
Balance at January 1,2020		14,479			20,800			(99)			145			209			(2,011)			(40)			51,842			441			50,586			16,067			66,653		
Stock based compensation		—			—			—			—			—			—			—			1,772			—			1,772			—			1,772		
Restricted stock unit vesting		293			—			—			3			—			—			—			(915)			—			(912)		—			(912)	
Consolidated net income 		—			—			—			—			—			—			—			—			15,638			15,638			21,207			36,845		
Distributions paid to non-controlling unit holders		—			—			—			—			—			—			—			—			—			—			(13,735)		(13,735)	
Dividends paid to Class A common stockholders ($0.3625 per share)		—			—			—			—			—			—			—			—			(5,265)			(5,265)		—			(5,265)	
Dividends paid to Preferred Stockholders		—			—			—			—			—			—			—			—			(3,539)			(3,539)		—			(3,539)	
Changes in ownership interest		—			—			—			—			—			—			—			710			—			710			(710)		—		
Balance at June 30, 2020		14,772			20,800			(99)		$	148		$	209		$	(2,011)		$	(40)		$	53,409		$	7,275		$	58,990		$	22,829		$	81,819		

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

Three Months Ended June 30, 2020	
	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 March 31, 2020		14,495			20,800			(99)		$	145		$	209		$	(2,011)		$	(40)		$	52,710		$	814		$	51,827		$	14,906		$	66,733		
Stock based compensation		—			—			—			—			—			—			—			443			—			443			—			443		
Restricted stock unit vesting		277			—			—			3			—			—			—			(876)			—			(873)		—			(873)	
Consolidated net income		—			—			—			—			—			—			—			—			11,159			11,159			15,618			26,777		
Distributions paid to non-controlling unit holders		—			—			—			—			—			—			—			—			—			—			(6,563)		(6,563)	
Dividends paid to Class A common stockholders ($0.18125 per share)		—			—			—			—			—			—			—			—			(2,659)			(2,659)		—			(2,659)	
Dividends paid to Preferred Stockholders		—			—			—			—			—			—			—			—			(2,039)			(2,039)		—			(2,039)	
Changes in ownership interest		—			—			—			—			—			—			—			1,132			—			1,132			(1,132)		—		
Balance at June 30, 2020		14,772			20,800			(99)		$	148		$	209		$	(2,011)		$	(40)		$	53,409		$	7,275		$	58,990		$	22,829		$	81,819		

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

SPARK ENERGY, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(unaudited)
  	Six Months Ended June 30,	
  	2021		2020	
Cash flows from operating activities:				
Net (loss) income 	$	(2,764)		$	36,845		
Adjustments to reconcile net income to net cash flows provided by operating activities:				
Depreciation and amortization expense		11,449				16,806		
Deferred income taxes		4,680				975		
Stock based compensation		1,571				1,814		
Amortization of deferred financing costs		517				490		
Bad debt expense		(113)			3,733		
(Gain) loss on derivatives, net		(25,928)			16,466		
Current period cash settlements on derivatives, net		390				(26,256)	
Changes in assets and liabilities:				
Decrease in accounts receivable		25,057				41,225		
Decrease (increase) in accounts receivable—affiliates		380				(2,116)	
Decrease in inventory		400				1,981		
Increase in customer acquisition costs		(456)			(1,556)	
Decrease in prepaid and other current assets		6,324				10,901		
Decrease in intangible assets—customer acquisition		27				—		
Decrease in other assets		519				459		
Decrease in accounts payable and accrued liabilities		(12,948)			(30,393)	
Decrease in accounts payable—affiliates		(382)			(292)	
Increase in other current liabilities		473				846		
Decrease in other non-current liabilities		(28)			(145)	
Net cash provided by operating activities		9,168				71,783		
Cash flows from investing activities:				
Purchases of property and equipment		(1,063)			(579)	
Net cash used in investing activities		(1,063)			(579)	
Cash flows from financing activities:				
Buyback of Series A Preferred Stock		—				(2,157)	
Borrowings on notes payable		371,000				250,000		
Payments on notes payable		(336,000)			(273,000)	
Net borrowings on subordinated debt facility		10,000				—		
Restricted stock vesting		(833)			(1,107)	
Payment of dividends to Class A common stockholders		(5,328)			(5,265)	
Payment of distributions to non-controlling unitholders		(10,186)			(13,735)	
Payment of Preferred Stock dividends		(3,902)			(3,984)	
Net cash provided (used) in financing activities		24,751				(49,248)	
Increase in Cash, cash equivalents and Restricted cash		32,856				21,956		
Cash, cash equivalents and Restricted cash—beginning of period		71,684				57,668		
Cash, cash equivalents and Restricted cash—end of period	$	104,540			$	79,624		
Supplemental Disclosure of Cash Flow Information:				
Non-cash items:				
        Property and equipment purchase accrual	$	69			$	79		
Cash paid (received) during the period for:				
Interest	$	2,145			$	2,307		
Taxes	$	(5,866)		$	987		

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

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, Spark Energy, and Verde Energy.

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, 2020 (the “2020 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.

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 Company's Chief Executive Officer, a director, and 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

There have been no changes to our significant accounting policies as disclosed in our 2020 Form 10-K, except as follows: 

In December 2019, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2019-12, Income Taxes (Topic 740), Simplifying the Accounting for Income Taxes ("ASU 2019-12"). These amendments simplify the accounting for income taxes by removing certain exceptions to the general principles in Topic 740. For public business entities, the amendments in ASU 2019-12 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020. We adopted ASU 2019-12 effective January 1, 2021 and the adoption did not have a material impact on our consolidated financial statements.

Standards Being Evaluated/Standards Not Yet Adopted 

Below are accounting standards that have been issued by the FASB but have not yet been adopted by the Company at June 30, 2021. 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 March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848), Facilitation of the Effects of Reference Rate Reform on Financial Reporting ("ASU 2020-04"). The amendments in ASU 2020-04 provide optional expedients and exceptions for applying GAAP to contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued because of reference rate reform. In January 2021, the FASB issued ASU 2021-01, Reference Rate Reform ("ASU 2021-01"), which clarifies the scope and application of certain optional expedients and exceptions regarding the original guidance. The amendments in these ASUs were effective upon issuance and can be applied prospectively through December 31, 2022. The Company's Senior Credit Facility is the only agreement that makes reference to a LIBOR rate and the agreement outlines the specific procedures that will be undertaken once an appropriate alternative benchmark is identified. We do not expect adoption of the new standard to have a material impact to our consolidated financial statements.

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 twelve 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).
	Reportable Segments	
	Three Months Ended June 30, 2021		Three Months Ended June 30, 2020	
	Retail Electricity		Retail Natural Gas		Total Reportable Segments		Retail Electricity		Retail Natural Gas		Total Reportable Segments	
												
Primary markets (a)												
New England	$	21,398			$	1,402			$	22,800			$	40,161			$	2,729			$	42,890		
Mid-Atlantic		23,309				3,223				26,532				38,743				5,929				44,672		
Midwest		9,362				2,910				12,272				14,506				4,191				18,697		
Southwest		17,620				3,085				20,705				18,845				3,514				22,359		
	$	71,689			$	10,620			$	82,309			$	112,255			$	16,363			$	128,618		
												
Customer type												
Commercial	$	11,171			$	4,982			$	16,153			$	29,408			$	7,290			$	36,698		
Residential		57,390				9,640				67,030				78,909				14,965				93,874		
Unbilled revenue (b)		3,128				(4,002)			(874)			3,938				(5,892)			(1,954)	
	$	71,689			$	10,620			$	82,309			$	112,255			$	16,363			$	128,618		
												
Customer credit risk												
POR	$	41,404			$	4,980			$	46,384			$	73,694			$	8,376			$	82,070		
Non-POR		30,285				5,640				35,925				38,561				7,987				46,548		
	$	71,689			$	10,620			$	82,309			$	112,255			$	16,363			$	128,618		

	Reportable Segments	
	Six Months Ended June 30, 2021		Six Months Ended June 30, 2020	
	Retail Electricity		Retail Natural Gas		Total Reportable Segments		Retail Electricity		Retail Natural Gas		Total Reportable Segments	

Primary markets (a)												
New England	$	47,639			$	5,779			$	53,418			$	86,754			$	9,783			$	96,537		
Mid-Atlantic		51,859				16,678				68,537				84,585				21,733				106,318		
Midwest		20,421				13,148				33,569				29,495				17,798				47,293		
Southwest		30,525				9,405				39,930				33,189				11,641				44,830		
	$	150,444			$	45,010			$	195,454			$	234,023			$	60,955			$	294,978		
												
Customer type												
Commercial	$	26,387			$	16,498			$	42,885			$	69,423			$	22,807			$	92,230		
Residential		130,662				36,130				166,792				172,137				48,328				220,465		
Unbilled revenue (b)		(6,605)			(7,618)			(14,223)			(7,537)			(10,180)			(17,717)	
	$	150,444			$	45,010			$	195,454			$	234,023			$	60,955			$	294,978		
												
Customer credit risk												
POR	$	92,254			$	24,580			$	116,834			$	158,607			$	31,413			$	190,020		
Non-POR		58,190				20,430				78,620				75,416				29,542				104,958		
	$	150,444			$	45,010			$	195,454			$	234,023			$	60,955			$	294,978		

(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 June 30, 2021 and 2020, our retail revenues included gross receipts taxes of $0.2 million and $0.4 million, respectively, and our retail cost of revenues included gross receipts taxes of $1.0 million and $1.4 million, respectively. During the six months ended June 30, 2021 and 2020, our retail revenues included gross receipts taxes of $0.5 million and $0.7 million, respectively, and our retail cost of revenues included gross receipts taxes of $2.2 million and $3.1 million, respectively.

Accounts receivables and Allowance for Credit Losses

The Company conducts business in many utility service markets where the local regulated utility purchases our receivables, and then becomes responsible for billing the customer and collecting payment from the customer (“POR programs”). These POR programs result in substantially all of the Company’s credit risk being linked to the applicable utility, which generally has an investment-grade rating, and not to the end-use customer. The Company monitors the financial condition of each utility and currently believes its receivables are collectible.
In markets that do not offer POR programs or when the Company chooses to directly bill its customers, certain receivables are billed and collected by the Company. The Company bears the credit risk on these accounts and records an appropriate allowance for doubtful accounts to reflect any losses due to non-payment by customers. The Company’s customers are individually insignificant and geographically dispersed in these markets. The Company writes off customer balances when it believes that amounts are no longer collectible and when it has exhausted all means to collect these receivables.

For trade accounts receivables, the Company accrues an allowance for doubtful accounts by business segment by pooling customer accounts receivables based on similar risk characteristics, such as customer type, geography, aging analysis, payment terms, and related macro-economic factors. Expected credit loss exposure is evaluated for each of our accounts receivables pools. Expected credits losses are established using a model that considers historical collections experience, current information, and reasonable and supportable forecasts. The Company writes off accounts receivable balances against the allowance for doubtful accounts when the accounts receivable is deemed to be uncollectible. 

A rollforward of our allowance for credit losses for the six months ended June 30, 2021 are presented in the table below (in thousands):

Balance at December 31, 2020		$	(3,942)	
Current period bad debt provision			353		
Write-offs			1,521		
Recovery of previous write offs			(313)	
Balance at June 30, 2021		$	(2,381)	

4. Equity 

Non-controlling Interest

We hold an economic interest and are the sole managing member in Spark HoldCo, with affiliates of our Founder 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 June 30, 2021 and December 31, 2020, respectively.
	The Company	Affiliated Owners	
June 30, 2021		41.76	%		58.24	%	
December 31, 2020		41.53	%		58.47	%	

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

	Three Months Ended June 30,		Six Months Ended June 30,	
	2021		2020		2021		2020	
Net income (loss) allocated to non-controlling interest	$	15,246			$	17,723			$	(3,075)		$	23,808		
Income tax expense allocated to non-controlling interest		933				2,105				2,541				2,601		
Net income (loss) attributable to non-controlling interest	$	14,313			$	15,618			$	(5,616)		$	21,207		

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 on Class A Common Stock

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 six months ended June 30, 2021, we paid $5.3 million in dividends to the holders of the Company's Class A common stock. This dividend represented a quarterly rate of $0.18125 per share on each share of 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 six months ended June 30, 2021, Spark HoldCo made corresponding distributions of $7.6 million to our non-controlling interest holders.

Share Repurchase Program

On August 18, 2020, our Board of Directors authorized a share repurchase program of up to $20.0 million of Class A common stock through August 18, 2021. Purchases may be made with available cash balances, our Senior Credit Facility and operating cash flows. 

The shares of Class A common stock may be repurchased from time to time in the open market at prevailing market prices or in privately negotiated transactions based on ongoing assessments of capital needs, the market price of the stock, and other factors, including general market conditions. The repurchase program does not obligate us to acquire any particular amount of Class A common stock, may be modified or suspended at any time, and could be terminated prior to completion.

During the six months ended June 30, 2021, we did not repurchase our Class A common stock. The share repurchase program was suspended in March 2021 pursuant to an agreement with lenders under our Senior Credit Facility.

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.

The following table presents the computation of basic and diluted income (loss) per share for the three and six months ended June 30, 2021 and 2020 (in thousands, except per share data):
	Three Months Ended June 30,		Six Months Ended June 30,	
	2021	2020		2021	2020	
Net income attributable to Spark Energy, Inc. stockholders	$	10,483		$	11,159			$	2,852		$	15,638		
Less: Dividend on Series A Preferred Stock		1,951			2,039				3,902			3,539		
Net income (loss) attributable to stockholders of Class A common stock	$	8,532		$	9,120			$	(1,050)	$	12,099		
						
Basic weighted average Class A common shares outstanding		14,685			14,558				14,656			14,469		
Basic income (loss) per share attributable to stockholders	$	0.58		$	0.63			$	(0.07)	$	0.84		
						
Net income (loss) attributable to stockholders of Class A common stock	$	8,532		$	9,120			$	(1,050)	$	12,099		
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	$	8,532		$	9,120			$	(1,050)	$	12,099		
						
Basic weighted average Class A common shares outstanding		14,685			14,558				14,656			14,469		
Effect of dilutive Class B common stock		—			—				—			—		
Effect of dilutive restricted stock units		136			205				111			100		
Diluted weighted average shares outstanding		14,821			14,763				14,767			14,569		
						
Diluted income (loss) per share attributable to stockholders	$	0.58		$	0.62			$	(0.07)	$	0.83		

The computation of diluted earnings per share for the three and six months ended June 30, 2021 and 2020 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 June 30, 2021 and December 31, 2020 (in thousands):
	June 30, 2021	December 31, 2020	
Assets			
Current assets:			
   Cash and cash equivalents	$	92,669		$	71,442		
   Accounts receivable		45,406			70,350		
   Other current assets		70,736			55,575		
   Total current assets		208,811			197,367		
Non-current assets:			
   Goodwill		120,343			120,343		
   Other assets		11,148			15,259		
   Total non-current assets		131,491			135,602		
   Total Assets	$	340,302		$	332,969		
			
Liabilities			
Current liabilities:			
   Accounts payable and accrued liabilities	$	55,373		$	61,436		
   Other current liabilities		38,425			43,676		
   Total current liabilities		93,798			105,112		
Long-term liabilities:			
   Long-term portion of Senior Credit Facility		135,000			100,000		
   Subordinated debt — affiliate		10,000			—		
   Other long-term liabilities		—			256		
   Total long-term liabilities		145,000			100,256		
   Total Liabilities	$	238,798		$	205,368		

5. Preferred Stock 

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

During the three and six months ended June 30, 2021, we paid $2.0 million and $4.0 million in dividends to holders of the Series A Preferred Stock, respectively. As of June 30, 2021, we had accrued $2.0 million related to dividends to holders of the Series A Preferred Stock. This dividend was paid on July 15, 2021.

A summary of our preferred equity balance for the six months ended June 30, 2021 is as follows:
		(in thousands)	
Balance at December 31, 2020		$	87,288		
Repurchase of Series A Preferred Stock			—		
Accumulated dividends on Series A Preferred Stock			—		
Balance at June 30, 2021		$	87,288		

6. 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 June 30, 2021 and December 31, 2020, we offset $0.5 million and $0.1 million, respectively, in collateral to net against the related derivative asset and liability's fair value. 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.

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		June 30, 2021		December 31, 2020	
Natural Gas	MMBtu			2,048				2,880		
Electricity	MWh			1,656				1,845		
Trading
Commodity	Notional		June 30, 2021		December 31, 2020	
Natural Gas	MMBtu			137				102		

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

	Three Months Ended June 30,	Six Months Ended June 30,	
  	2021		2020	2021		2020	
Gain (Loss) on non-trading derivatives, net	$	18,898			$	7,964		$	25,952			$	(16,569)		
Gain (Loss) on trading derivatives, net		6				157			(24)			103		
Gain (Loss) on derivatives, net		18,904				8,121			25,928				(16,466)		
Current period settlements on non-trading derivatives (1)	$	795			$	10,055		$	(394)		$	26,664		
Current period settlements on trading derivatives		—				(91)		4				(92)		
Total current period settlements on derivatives	$	795			$	9,964		$	(390)		$	26,572		

(1) Excludes settlements of $(0.3) million, for the six months ended June 30, 2020 related to power call options.
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):
  	June 30, 2021	
Description	Gross Assets		Gross
Amounts
Offset		Net Assets		Cash
Collateral
Offset		Net Amount
Presented	
Non-trading commodity derivatives 	$	22,826			$	(5,861)		$	16,965			$	(456)		$	16,509		
Trading commodity derivatives		19				—				19				—				19		
Total Current Derivative Assets		22,845				(5,861)			16,984				(456)			16,528		
Non-trading commodity derivatives		1,319				(250)			1,069				—				1,069		
Trading commodity derivatives		—				—				—				—				—		
Total Non-current Derivative Assets		1,319				(250)			1,069				—				1,069		
Total Derivative Assets	$	24,164			$	(6,111)		$	18,053			$	(456)		$	17,597		

Description	Gross 
Liabilities		Gross
Amounts
Offset		Net
Liabilities		Cash
Collateral
Offset		Net Amount
Presented	
Non-trading commodity derivatives	$	(20)		$	1			$	(19)		$	—			$	(19)	
Trading commodity derivatives		(2)			—				(2)			—				(2)	
Total Current Derivative Liabilities		(22)			1				(21)			—				(21)	
Non-trading commodity derivatives		—				—				—				—				—		
Trading commodity derivatives		—				—				—				—				—		
Total Non-current Derivative Liabilities		—				—				—				—				—		
Total Derivative Liabilities	$	(22)		$	1			$	(21)		$	—			$	(21)	

  	December 31, 2020	
Description	Gross Assets		Gross
Amounts
Offset		Net Assets		Cash
Collateral
Offset		Net Amount
Presented	
Non-trading commodity derivatives	$	308			$	(105)		$	203			$	—			$	203		
Trading commodity derivatives		112				(4)			108				—				108		
Total Current Derivative Assets		420				(109)			311				—				311		
Non-trading commodity derivatives		—				—				—				—				—		
Trading commodity derivatives		—				—				—				—				—		
Total Non-current Derivative Assets		—				—				—				—				—		
Total Derivative Assets	$	420			$	(109)		$	311			$	—			$	311		

Description	Gross 
Liabilities		Gross
Amounts
Offset		Net
Liabilities		Cash
Collateral
Offset		Net Amount
Presented	
Non-trading commodity derivatives	$	(11,139)		$	3,620			$	(7,519)		$	86			$	(7,433)	
Trading commodity derivatives		(74)			2				(72)			—				(72)	
Total Current Derivative Liabilities		(11,213)			3,622				(7,591)			86				(7,505)	
Non-trading commodity derivatives		(838)			611				(227)			—				(227)	
Trading commodity derivatives		—				—				—				—				—		
Total Non-current Derivative Liabilities		(838)			611				(227)			—				(227)	
Total Derivative Liabilities	$	(12,051)		$	4,233			$	(7,818)		$	86			$	(7,732)	

7. Property and Equipment 
Property and equipment consist of the following (in thousands):
	Estimated useful
lives (years)		June 30, 2021		December 31, 2020	
Information technology	2 – 5		$	5,589			$	5,821		
Furniture and fixtures	2 – 5			957				957		
Total				6,546				6,778		
Accumulated depreciation				(2,915)			(3,424)	
Property and equipment—net			$	3,631			$	3,354		
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 June 30, 2021 and December 31, 2020, information technology includes $0.9 million and $0.7 million, respectively, of costs associated with assets not yet placed into service. Depreciation expense recorded in the condensed consolidated statements of operations was $0.5 million and $0.6 million, respectively, for the three months ended June 30, 2021 and 2020 and $0.9 million and $1.2 million for the six months ended June 30, 2021 and 2020, respectively.

8. Intangible Assets 
Goodwill, customer relationships and trademarks consist of the following amounts (in thousands):
	June 30, 2021		December 31, 2020	
Goodwill	$	120,343			$	120,343		
Customer relationships—Acquired 				
Cost	$	58,688			$	58,688		
Accumulated amortization		(48,715)			(44,175)	
Customer relationships—Acquired 	$	9,973			$	14,513		
Customer relationships—Other 				
Cost	$	8,898			$	8,988		
Accumulated amortization		(7,157)			(5,733)	
Customer relationships—Other, net	$	1,741			$	3,255		
Trademarks 				
Cost	$	7,570			$	7,570		
Accumulated amortization		(3,527)			(2,972)	
Trademarks, net	$	4,043			$	4,598		

Changes in goodwill, customer relationships (including non-compete agreements) and trademarks consisted of the following (in thousands):
	Goodwill 		Customer Relationships— Acquired 		Customer Relationships— Other		Trademarks	
Balance at December 31, 2020	$	120,343			$	14,513			$	3,255			$	4,598		
Adjustments 		—				—				(28)			—		
Amortization 		—				(4,540)			(1,486)			(555)	
Balance at June 30, 2021	$	120,343			$	9,973			$	1,741			$	4,043		

Estimated future amortization expense for customer relationships and trademarks at June 30, 2021 is as follows (in thousands):
Year ending December 31,		
2021 (remaining six months)	$	6,534		
2022		6,194		
2023		605		
2024		404		
2025		404		
> 5 years		1,616		
Total	$	15,757		

9. Debt 
Debt consists of the following amounts as of June 30, 2021 and December 31, 2020 (in thousands):
	June 30, 2021		December 31, 2020	
Long-term debt:				
  Senior Credit Facility (1) (2)	$	135,000			$	100,000		
  Subordinated Debt 		10,000				—		
Total long-term debt		145,000				100,000		
Total debt	$	145,000			$	100,000		
(1) As of June 30, 2021 and December 31, 2020, the weighted average interest rate on the Senior Credit Facility was 3.75% and 3.75%, respectively.
(2) As of June 30, 2021 and December 31, 2020, we had $21.4 million and $31.0 million in letters of credit issued, respectively.

Capitalized financing costs associated with our Senior Credit Facility were $1.1 million and $1.6 million as of June 30, 2021 and December 31, 2020, respectively. Of these amounts, $1.0 million and $1.0 million are recorded in other current assets, and $0.1 million and $0.6 million are recorded in other non-current assets in the condensed consolidated balance sheets as of June 30, 2021 and December 31, 2020, respectively.
Interest expense consists of the following components for the periods indicated (in thousands):
	Three Months Ended June 30,		Six Months Ended June 30,	
	2021		2020		2021		2020	
Senior Credit Facility	$	804			$	516			$	1,272			$	1,427		
Letters of credit fees and commitment fees		335				437				737				829		
Amortization of deferred financing costs 		258				240				517				490		
Other		155				—				337				—		
Interest Expense	$	1,552			$	1,193			$	2,863			$	2,746		

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 from time to time, “Senior Credit Facility”) that allows us to borrow on a revolving basis and has a maximum borrowing capacity of $227.5 million as of June 30, 2021.

Subject to applicable sub-limits and terms of the Senior Credit Facility, 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 share buyback loans (“Share Buyback Loans”).

The Senior Credit Facility will mature on July 31, 2022, and all amounts outstanding thereunder will be payable on the maturity date. 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. The Senior Credit Facility provides for Share Buyback Loans of up to $80.0 million, which permit the Company to repurchase up to an aggregate of 8,000,000 shares of Class A common stock or $80.0 million of Series A Preferred Stock, however this provision was suspended in March 2021 pursuant to an agreement with lenders under the Senior Credit Facility.

Pursuant to the Senior Credit Facility, 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 3.25% per annum (based on the prevailing utilization) or an alternate base rate plus an applicable margin of up to 2.25% 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%.

Borrowings under the Senior Credit Facility for Share Buyback Loans, are generally determined by reference to the Eurodollar rate plus an applicable margin of 4.50% per annum or the alternate base rate plus an applicable margin of 3.50% per annum. 

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 Minimum 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, letter of credit fees, commitment fees, acquisition earn-out payments (excluding earnout payments funded with proceeds from newly issued preferred or common equity), distributions, scheduled amortization payments, and payments made on or after the closing of the Fourth Amendment to the Senior Credit Facility (other than such payments made from escrow accounts which were funded in connection with a permitted acquisition) related to the settlement of civil and regulatory matters if not included in the calculation of Adjusted EBITDA. Our Minimum Fixed Charge Coverage Ratio as of June 30, 2021 was 1.53 to 1.00.

•	Maximum Total Leverage Ratio. We must maintain a ratio of (x) the sum of total indebtedness (excluding eligible subordinated debt and letter of credit obligations), plus (y) gross amounts reserved for civil and regulatory liabilities identified in SEC filings, to Adjusted EBITDA of no more than 2.50 to 1.00. Our Maximum Total Leverage Ratio as of June 30, 2021 was 1.59 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) to (b) Adjusted EBITDA. Our Maximum Senior Secured Leverage Ratio as of June 30, 2021 was 1.36 to 1.00.

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 June 30, 2021, we were in compliance with our various covenants under the Senior Credit Facility.

The Senior Credit Facility is secured by pledges of the equity of the portion of Spark HoldCo owned by us, the equity of Spark HoldCo’s subsidiaries, the Co-Borrowers’ present and future subsidiaries, and substantially all of the Co-Borrowers’ and their subsidiaries’ present and future property and assets, including accounts receivable, inventory and liquid investments, and control agreements relating to bank accounts.

We are entitled to pay cash dividends to the holders of the Series A Preferred Stock and Class A common stock and will be entitled to repurchase up to an aggregate amount of 10,000,000 shares of our Class A common stock, and up to $92.7 million of Series A Preferred Stock through one or more normal course open market purchases through NASDAQ so long as: (a) no default exists or would result therefrom; (b) the Co-Borrowers are in pro forma compliance with all financial covenants before and after giving effect thereto; and (c) the outstanding amount of all loans and letters of credit does not exceed the borrowing base limits. The share repurchase program was suspended in March 2021 pursuant to an agreement with lenders under our Senior Credit Facility.

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

The Company maintains 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 matures on January 31, 2023. 

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 June 30, 2021, and December 31, 2020, there were $10.0 million and zero outstanding borrowings under the Subordinated Debt Facility.

10. Fair Value Measurements 
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. Fair values are based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. This includes the credit standing of counterparties involved and the impact of credit enhancements.
We apply fair value measurements to our commodity derivative instruments 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.

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 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	
June 30, 2021	 		 		 		 	
Non-trading commodity derivative assets	$	301			$	17,277			$	—			$	17,578		
Trading commodity derivative assets		—				19				—				19		
Total commodity derivative assets	$	301			$	17,296			$	—			$	17,597		
Non-trading commodity derivative liabilities	$	—			$	(19)		$	—			$	(19)	
Trading commodity derivative liabilities		—				(2)			—				(2)	
Total commodity derivative liabilities	$	—			$	(21)		$	—			$	(21)	

	Level 1		Level 2		Level 3		Total	
December 31, 2020								
Non-trading commodity derivative assets	$	104			$	99			$	—			$	203		
Trading commodity derivative assets		—				108				—				108		
Total commodity derivative assets	$	104			$	207			$	—			$	311		
Non-trading commodity derivative liabilities	$	(5)		$	(7,655)		$	—			$	(7,660)	
Trading commodity derivative liabilities		—				(72)			—				(72)	
Total commodity derivative liabilities	$	(5)		$	(7,727)		$	—			$	(7,732)	
We had no transfers of assets or liabilities between any of the above levels during the six months ended June 30, 2021 and the year ended December 31, 2020.
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 June 30, 2021 and December 31, 2020, the credit risk valuation adjustment was a reduction of derivative assets and liabilities, respectively, net of $0.1 million and $0.2 million.

11. 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 asset and liability 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 June 30, 2021, we had a net deferred tax asset of $23.3 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.

The effective U.S. federal and state income tax rate for the three months ended June 30, 2021 and 2020 was 12.9% and 17.5%, respectively. The effective U.S. federal and state income tax rate for the six months ended June 30, 2021 and 2020 was (342.2)% and 17.1%, respectively. Although the Company has generated a year to date loss, it is forecasting income tax expense for the year. The recognition of a portion of that income tax expense against the year to date loss produces the effective tax rate of (342.2)%. The effective tax rate for the three and six months ended June 30, 2021 differed from the U.S. federal statutory tax rate of 21% primarily due to state taxes and the benefit provided from Spark HoldCo operating as a limited liability company, which is 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 holders' taxable income.

12. 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 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, unless otherwise specifically noted, we cannot currently predict the manner and timing of the resolutions 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.

Consumer Lawsuits

Similar to other energy service companies (“ESCOs”) operating in the industry, from time-to-time, the Company is subject to class action lawsuits in various jurisdictions where the Company sells natural gas and electricity.

Variable Rate Cases

In the cases referred to as Variable Rate Cases, such actions involve consumers alleging they paid higher rates than they would have if they stayed with their default utility. The underlying claims of each case are similar; however, because numerous cases have been brought in several different jurisdictions, the varying applicable case law, the varying facts and stages of each case, the Company agreed to mediate to avoid duplicative defense costs in numerous jurisdictions.  The Company continues to deny the allegations asserted by Plaintiffs and intends to vigorously defend these matters.  

In August 2020, the Company participated in mediation which covered three Spark brand matters: (1) Janet Rolland et al v. Spark Energy, LLC (D.N.J Apr. 2017); (2) Burger v. Spark Energy Gas, LLC (N.D. Ill. Dec. 2019); and (3) Local 901 v. Spark Energy, LLC (Sup. Ct. Allen County, Indiana Aug. 2019). The Company is working with the mediator to find a resolution to these cases, but is also simultaneously continuing to defend the cases in the respective courts. Given the ongoing mediation, discovery, and current stage of these matters, we cannot predict the outcome of these cases at this time. 

In December of 2020, the Company participated in mediation which covered several Verde brand matters: (1) Marshall. Verde Energy USA, Inc. (D.N.J. Jan. 2018); (2) Mercado v. Verde Energy USA, Inc. (N.D. Ill. Mar. 2018); (3) Davis v. Verde Energy USA, Inc., et al. (D. Mass. Apr. 2019); (4) Panzer v. Verde Energy, USA Inc. and Oasis Power, LLC (E.D. Pa Aug. 2019); (5) LaQua v. Verde Energy USA New York, LLC (E.D.N Y. Jan. 2020); and (6) Abbate v. Verde Energy USA Ohio, LLC (S.D. Ohio Jun. 2020). The parties have agreed to a global settlement that would resolve all of these Verde cases.  A class action settlement agreement was filed for preliminary approval in the United States District Court for the Northern District of Illinois Eastern Division, and an Amended Class Action Settlement Agreement was filed early July 2021 and is pending preliminary approval.

On January 14, 2021, Glikin, et. all v. Major Energy Electric Services, LLC, a purported variable rate class action was filed in the United States District Court, Southern District of New York, attempting to represent a class of all Major Energy customers (including customers of companies Major Energy acts as a successor to) in the United States charged a variable rate for electricity or gas by Major Energy during the applicable statute of limitations period up to and including the date of judgment. The Company believes there is no merit to this case and plans to vigorously defend this matter; however, given the current early stage of this matter, we cannot predict the outcome of this case at this time.

Corporate Matter Lawsuits

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 related to the Company's purchase of Major Energy and structure of the earn-out in connection therewith ("Major Earn-Out Case") 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. This case went to trial during the first two weeks of March 2020 and all material has been submitted to the Judge for his decision. Given the trial was in Manhattan, New York, which was previously under a shelter-in-place order and is currently re-opening, we are not able to predict when we receive a final decision on the Major Earn-Out Case. Spark and NG&E deny the allegations asserted by Plaintiffs and have vigorously defended this matter. 

In addition, several smaller, related cases to the Major Earn-Out Case involving the same facts are pending in the United States District Court for the Southern District of New York. One case is regarding the Major Energy escrowed indemnification monies ("Major Energy Indemnification Case"). The other three cases are regarding Major Energy executive compensation agreements ("Major Energy Compensation Cases"). As to the Major Indemnification Case, this matter was resolved and dismissed with prejudice in favor of the Company in early June 2021. The former owners of Major Energy released certain escrowed monies to the Company. As to the Major Energy Compensation Cases, the Company believes there is no merit to these cases and is vigorously defending these matters; however, we cannot predict the outcome of these cases at this time.

In addition to the matters disclosed above, the Company may from time to time be subject to legal proceedings that arise in the ordinary course of business. Although there can be no assurance in this regard, the Company does not expect any of those legal proceedings to have a material adverse effect on the Company’s results of operations, cash flows or financial condition.

Regulatory Matters

Many state regulators have increased scrutiny on retail energy providers, across all industry providers. We are subject to regular regulatory inquiries, license renewal reviews, and preliminary investigations in the ordinary course of our business. Below is a summary of our currently pending material state regulatory matters. The following state regulatory matters 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 state regulatory matters or estimate a range of possible losses or a minimum loss that could result from an adverse action. Management does not currently expect that any currently pending state regulatory matters will have a material adverse effect on our financial position or results of operations.

Connecticut. In 2019, PURA initiated review of two of the Company's brands in Connecticut, Spark and Verde, focusing on marketing, billing and enrollment practices. The Company has and is cooperating with PURA's requests to review Spark and Verde practices in Connecticut.

Illinois. Spark Energy, LLC received a verbal inquiry from the Illinois Commerce Commission (“ICC”) and the Illinois Attorney General ("IAG") on January 1, 2020 seeking to understand an increase in complaints from Illinois consumers. The Company met with the ICC and the IAG in February 2020 and plan to discuss a compliance plan to ensure its sales are in compliance with Illinois regulations. The parties also discussed possible restitution payments to any customers impacted by sales not in compliance with Illinois regulations.

New York. Prior to the purchase of Major Energy by the Company, in 2015, Major Energy Services, LLC and Major Energy Electric Services were contacted by the Attorney General, Bureau of Consumer Frauds & Protection for State of New York relating to their marketing practices. Major Energy has exchanged information in response to various requests from the Attorney General and recently agreed to respond to additional questions via remote proceedings in October of 2020. The parties are in settlement negotiations at this time; however, no agreement has been met by parties.

Pennsylvania. Verde Energy USA, Inc. (“Verde”) was the subject of a formal investigation by the Pennsylvania Public Utility Commission, Bureau of Investigation and Enforcement (“PPUC”) initiated on January 30, 2020. The investigation asserted that Verde may have violated Pennsylvania retail energy supplier regulations. The Company met with the PPUC in February 2020 to discuss the matter and to work with the PPUC cooperatively. Verde reached a settlement, which included payment of a civil penalty of $1.0 million and a $0.1 million contribution to the PPL hardship fund. On June 30, 2020, Verde and PPUC Bureau of Investigation and Enforcement filed a Joint Petition for Approval of Settlement and Statements in Support of that Joint Petition with the Commission. Verde is currently awaiting final approval of this settlement.

In addition to the matters disclosed above, in the ordinary course of business, the Company may from time to time be subject to regulators initiating informal reviews or issuing subpoenas for information as means to evaluate the Company and its subsidiaries’ compliance with applicable laws, rule, regulations and practices. Although there can be no assurance in this regard, the Company does not expect any of those regulatory reviews to have a material adverse effect on the Company’s results of operations, cash flows or financial condition.

Indirect Tax Audits

We are undergoing various types of indirect tax audits spanning from years 2014 to 2020 for which additional liabilities may arise. At the time of filing these consolidated financial statements, these indirect tax audits are at an early stage and subject to substantial uncertainties concerning the outcome of audit findings and corresponding responses.

As of June 30, 2021 and December 31, 2020, we had accrued $22.8 million and $26.6 million, respectively, related to litigation and regulatory matters and $1.7 million and $1.2 million, respectively, related to indirect tax audits. The outcome of each of these may result in additional expense.

13. 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 and pay an affiliate to perform telemarketing activities. 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.

The following tables presents asset and liability balances with affiliates (in thousands):

	June 30, 2021		December 31, 2020	
Assets				
Accounts Receivable - affiliates	$	4,672			$	5,053		
Total Assets - affiliates	$	4,672			$	5,053		

	June 30, 2021		December 31, 2020	
Liabilities				
Accounts Payable - affiliates	$	444			$	826		
Subordinated Debt - affiliates (1)		10,000				—		
Total Liabilities - affiliates	$	10,444			$	826		
(1) 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. See Note 9 "Debt" for a further description of terms and conditions of the Subordinated Debt Facility.

The following table presents revenues and cost of revenues recorded in net asset optimization revenue associated with affiliates for the periods indicated (in thousands):
	Three Months Ended June 30,		Six Months Ended June 30,	
	2021		2020		2021		2020	
Revenue NAO - affiliates 	$	224			$	181			$	569			$	737		
Cost of Revenue NAO - affiliates 		5				96				5				270		
Net NAO - affiliates	$	229			$	277			$	574			$	1,007		

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 affiliates was $1.2 million and $0.2 million for the three months ended June 30, 2021 and 2020, respectively. The total net amount direct billed and allocated to/(from) affiliates was $0.4 million and less than $(0.1) million for the six months ended June 30, 2021 and 2020, respectively.

General and administrative costs of less than $0.1 million and $0.1 million were recorded for the three months ended June 30, 2021 and 2020, respectively, and $0.1 million and $0.1 million for the six months ended June 30, 2021 and 2020, respectively. The general and administrative costs relate to telemarketing activities performed by an affiliate. 

Distributions to and Contributions from Affiliates

During three months ended June 30, 2021 and 2020, Spark HoldCo made distributions to affiliates of our Founder of $3.8 million and $3.8 million, respectively, for the payments of quarterly distribution on their respective Spark HoldCo units. During the three months ended June 30, 2021 and 2020, Spark HoldCo also made distributions to these affiliates for gross-up distributions of zero and $2.8 million, respectively, in connection with distributions made between Spark HoldCo and Spark Energy, Inc. for payment of income taxes incurred by us.

During each of the six months ended June 30, 2021 and 2020, Spark HoldCo made distributions to affiliates of our Founder of $7.6 million, for payments of quarterly distributions on their respective Spark HoldCo units. During the six months ended June 30, 2021 and 2020, Spark HoldCo also made distributions to these affiliates for gross-up distributions of $2.7 million and $6.2 million, respectively, in connection with distributions made between Spark HoldCo and Spark Energy, Inc. for payment of income taxes incurred by us.

14. 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 June 30, 2021 and 2020, we recorded asset optimization revenues of $7.8 million and $3.9 million and asset optimization cost of revenues of $7.9 million and $4.0 million, respectively, and for the six months ended June 30, 2021 and 2020, we recorded asset optimization revenues of $33.5 million and $10.3 million and asset optimization cost of revenues of $33.8 million and $10.1 million, respectively, which are presented on a net basis in asset optimization revenues.
We use retail gross margin to assess the performance of our operating segments. We have historically defined retail gross margin 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.
Based on the events described below related to the February 2021 North American winter storm referred to as Winter Storm Uri ("Winter Storm Uri"), and to ensure Retail Gross Margin reflects repeatable operating performance that is not distorted by non-recurring events or extreme market volatility, we have revised the definition of Retail Gross Margin in this Report to include gains (losses) from non-recurring events (including non-recurring market volatility). 
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):

  	Three Months Ended June 30,		Six Months Ended June 30,	
  	2021		2020		2021		2020	
Reconciliation of Retail Gross Margin to income (loss) before taxes								
Income (loss) before income tax expense 	$	28,470			$	32,450			$	(625)		$	44,443		
Interest and other income		(79)			(53)			(165)			(213)	
Interest expense		1,552				1,193				2,863				2,746		
Operating income 		29,943				33,590				2,073				46,976		
Depreciation and amortization		5,413				8,010				11,449				16,806		
General and administrative		10,663				21,331				23,334				47,007		
Less:								
Net asset optimization (expense) revenue 		(114)			(82)			(254)			239		
Net, gain (loss) on non-trading derivative instruments		18,898				7,964				25,952				(16,569)	
Net, Cash settlements on non-trading derivative instruments		795				10,055				(394)			26,664		
Non-recurring event - Winter Storm Uri		—				—				(64,900)			—		
Retail Gross Margin	$	26,440			$	44,994			$	76,452			$	100,455		

Financial data for business segments are as follows (in thousands):
Three Months Ended June 30, 2021	
	Retail
Electricity		Retail
Natural Gas		Corporate
and Other		Eliminations		Consolidated	
Total Revenues	$	71,689			$	10,620			$	(114)		$	—			$	82,195		
Retail cost of revenues		31,203				4,973				—				—				36,176		
Less:										
Net asset optimization expense		—				—				(114)			—				(114)	
Net, gain on non-trading derivative instruments		17,694				1,204				—				—				18,898		
Current period settlements on non-trading derivatives		1,141				(346)			—				—				795		
Retail Gross Margin	$	21,651			$	4,789			$	—			$	—			$	26,440		
Total Assets at June 30, 2021	$	3,051,393			$	978,072			$	336,135			$	(3,996,446)		$	369,154		
Goodwill at June 30, 2021	$	117,813			$	2,530			$	—			$	—			$	120,343		

Three Months Ended June 30, 2020	
	Retail
Electricity		Retail
Natural Gas		Corporate
and Other		Eliminations		Consolidated	
Total revenues	$	112,255			$	16,363			$	(82)		$	—			$	128,536		
Retail cost of revenues		59,268				6,337				—				—				65,605		
Less:										
Net asset optimization expense		—				—				(82)			—				(82)	
Net, gain (loss) on non-trading derivative instruments		8,047				(83)			—				—				7,964		
Current period settlements on non-trading derivatives		9,367				688				—				—				10,055		
Retail Gross Margin	$	35,573			$	9,421			$	—			$	—			$	44,994		
Total Assets at December 31, 2020	$	2,906,139			$	941,569			$	318,865			$	(3,799,906)		$	366,667		
Goodwill at December 31, 2020	$	117,813			$	2,530			$	—			$	—			$	120,343		

Six Months Ended June 30, 2021	
	Retail
Electricity		Retail
Natural Gas		Corporate
and Other		Eliminations		Consolidated	
Total revenues	$	150,444			$	45,010			$	(254)		$	—			$	195,200		
Retail cost of revenues		138,727				19,617				—				—				158,344		
Less:										
Net asset optimization expense		—				—				(254)			—				(254)	
Net gain on non-trading derivatives		24,399				1,553				—				—				25,952		
Current period settlements on non-trading derivatives		(47)			(347)			—				—				(394)	
Non-recurring event - Winter Storm Uri		(64,900)			—				—				—				(64,900)	
Retail Gross Margin	$	52,265			$	24,187			$	—			$	—			$	76,452		
Total Assets at June 30, 2021	$	3,051,393			$	978,072			$	336,135			$	(3,996,446)		$	369,154		
Goodwill at June 30, 2021	$	117,813			$	2,530			$	—			$	—			$	120,343		

Six Months Ended June 30, 2020	
	Retail
Electricity		Retail
Natural Gas		Corporate
and Other		Eliminations		Consolidated	
Total revenues	$	234,023			$	60,955			$	239			$	—			$	295,217		
Retail cost of revenues		159,651				24,777				—				—				184,428		
Less:										
Net asset optimization revenues		—				—				239				—				239		
Net loss on non-trading derivatives		(16,339)			(230)			—				—				(16,569)	
Current period settlements on non-trading derivatives		24,332				2,332				—				—				26,664		
Retail Gross Margin	$	66,379			$	34,076			$	—			$	—			$	100,455		
Total Assets at December 31, 2020	$	2,906,139			$	941,569			$	318,865			$	(3,799,906)		$	366,667		
Goodwill at December 31, 2020	$	117,813			$	2,530			$	—			$	—			$	120,343		

15. Customer Acquisitions 
Acquisition of Customer Books 

In May 2021, we entered into a series of asset purchase agreements and agreed to acquire up to approximately 56,900 RCEs for a cash purchase price of up to a maximum of $11.5 million. These customers began transferring in August 2021, and are located in our existing markets. 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 we acquire customers, we make payments to the seller from the escrow account. As of June 30, 2021, the balance in the escrow account was $11.5 million, and these funds are expected to be released to the seller as acquired customers transfer from the seller to the Company in accordance with the asset purchase agreement, and any unallocated balance will be returned to the Company once the acquisition is complete.

16. Subsequent Events

Declaration of Dividends

On July 21, 2021, we declared a quarterly dividend of $0.18125 per share to holders of record of our Class A common stock on September 1, 2021, which will be paid on September 15, 2021.

On July 21, 2021, 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 October 1, 2021. The dividend will be paid on October 15, 2021.

Conversion of Class B Common Stock to Class A Common Stock

In July 2021, holders of Class B common stock exchanged 800,000 of their Spark HoldCo units (together with a corresponding number of shares of Class B common stock) for shares of Class A common stock at an exchange ratio of one share of Class A common stock for each Spark HoldCo unit (and corresponding share of Class B common stock) exchanged.

Acquisition of Customer Books 

In July 2021, we entered into an agreement to acquire up to approximately 50,000 RCEs under a five-year contingent fee structure based on RCEs on flow after the acquisition date. These customers will begin transferring in the third quarter of 2021, and are located in our existing markets.

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 2020 Form 10-K filed with the Securities and Exchange Commission (“SEC”) on March 4, 2021. Results of operations and cash flows for the three and six months ended June 30, 2021 are not necessarily indicative of results to be attained for any other period. See "Cautionary Note Regarding Forward-Looking Statements" and "Risk Factors."

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 natural gas and electricity. We purchase our natural gas and electricity supply from a variety of wholesale providers and bill our customers monthly for the delivery of natural gas and electricity based on their consumption at either a fixed or variable price. Natural gas and electricity are then distributed to our customers by local regulated utility companies through their existing infrastructure. As of June 30, 2021, we operated in 100 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 June 30, 2021 and 2020, approximately 87% and 87%, 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 June 30, 2021 and 2020, approximately 13% and 13%, respectively, of our retail revenues were derived from the sale of natural gas.

Recent Developments

Company's Name Change Proposal

The Board of Directors unanimously approved a proposal to amend the Company's certificate of incorporation to change the name of the Company from Spark Energy, Inc. to "Via Renewables, Inc." subject to shareholder approval at the special meeting of shareholders on August 6, 2021.

Acquisition of Customer Books

In May 2021, the Company executed four separate agreements to acquire a total of approximately 56,900 RCEs for a total purchase price of $11.5 million, consisting of approximately 15,700 RCEs in Connecticut's Eversource territory, 4,700 RCEs in Connecticut's United Illuminated territory, 17,500 RCEs in Massachusetts, and 19,000 RCEs in the Mid-Atlantic and Midwest regions. The completion of these transactions is subject to customary closing conditions, including regulatory approvals. We believe these acquisitions will drive long-term, sustainable growth and value for our shareholders. The customers will begin coming on flow during the third quarter of 2021.

In July 2021, we entered into an agreement to acquire up to approximately 50,000 RCEs under a five-year contingent fee structure based on RCEs on flow after the acquisition date. These customers will begin transferring in third quarter of 2021, and are located in our existing markets.

COVID-19

The outbreak of the novel coronavirus ("COVID-19") adversely impacted economic activity and conditions worldwide. In response to the COVID-19 pandemic, we deployed a remote working strategy in March 2020 that enabled our employees to work from home, provided timely communication to team members, implemented protocols for team members' safety, and initiated strategies for monitoring and responding to local COVID-19 impacts. Our preparedness efforts, coupled with quick and decisive plan implementation, resulted in minimal impacts to our workforce. Our workforce resumed normal work schedules at our corporate headquarters in May 2021.

A slower than planned ramp-up of our door-to-door sales channels as COVID-19 restrictions have lifted has had the most significant adverse impact to our business, financial condition and results of operations during the quarter ended June 30, 2021. We are continuing to monitor developments involving customers and suppliers and the impact on our operations, business, financial condition, liquidity and results of operations for future periods.

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 six months ended June 30, 2021:

RCEs:						
(In thousands)	March 31, 2021	Additions	Attrition	June 30, 2021	% Increase (Decrease)	
Retail Electricity	279	15	(24)	270	(3)%	
Retail Natural Gas	88	—	(11)	77	(13)%	
Total Retail	367	15	(35)	347	(5)%	

RCEs:						
(In thousands)	December 31, 2020	Additions	Attrition	June 30, 2021	% Increase (Decrease)	
Retail Electricity	303	29	(62)	270	(11)%	
Retail Natural Gas	97	1	(21)	77	(21)%	
Total Retail	400	30	(83)	347	(13)%	
June 30, 2021:
						
The following table details our count of RCEs by geographical location as of 
RCEs by Geographic Location:							
(In thousands)	Electricity	 % of Total	Natural Gas	 % of Total	Total	 % of Total	
New England	79	30%	14	18%	93	27%	
Mid-Atlantic	90	33%	24	32%	114	33%	
Midwest	31	10%	23	29%	54	16%	
Southwest	70	27%	16	21%	86	24%	
Total	270	100%	77	100%	347	100%	

The geographical locations 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. We currently operate under six retail brands. During 2020 and 2019, we consolidated certain brands and billing systems in an effort to simplify our business operations where practical.

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

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.

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. 

Due to the COVID-19 pandemic, certain public utility commissions, regulatory agencies, and other governmental authorities in most of our markets maintained orders prohibiting energy services companies from door-to-door marketing and in some cases telemarketing during the pandemic, which restricted some of the sales channels we have historically used to market for organic sales. In response, we focused on development of products and channels, partners for web sales, as well as accelerating our telemarketing sales quality programs. In November 2020, we began active door-to-door marketing activities as COVID-19 restrictions were lifted.

During the three months ended June 30, 2021, we added approximately 15,000 RCEs primarily through our various organic sales channels. This amount was significantly lower than historical periods not impacted by the COVID-19 pandemic primarily due to a slower than expected ramp-up of our door-to-door marketing activities. We expect to acquire customers organically in future periods but it will be slower in the near term. This may cause our customer book to decrease.

We acquire companies and portfolios of customers through both external and affiliated channels. For instance, in May 2021, we entered into a series of asset purchase agreements to acquire approximately 56,900 RCEs as previously discussed under "Recent Developments-Acquisition of Customer Books." 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. We will continue to evaluate potential acquisitions during the remainder of 2021. 

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 strive 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.

As described above, during the COVID-19 pandemic certain public utility commissions, regulatory agencies, and other governmental authorities in all of our markets issued orders that impacted the way we have historically acquired customers prior to the COVID-19 pandemic, such as door to door marketing. Our gradual increase of marketing efforts as restrictions have been lifted resulted in reduced marketing and significantly reduced customer acquisition costs during the three months ended June 30, 2021 compared to historical amounts. We are incurring costs related to other manners of marketing, such as online marketing.

Customer Attrition

Customer attrition occurs primarily as a result of: (i) customer initiated switches; (ii) residential moves; (iii) disconnection resulting from customer payment defaults; and (iv) proactive non-renewal of contracts. Average monthly customer attrition for the three months ended June 30, 2021 and 2020 was 3.3% and 3.5%, respectively. 

Our customer attrition was slightly lower than the prior year because of our pro-active non-renewal of some of the larger C&I customers in prior year which did not re-occur in 2021. Although customer attrition was slightly lower during the second quarter of 2021, we are unable to predict the ultimate impact on overall customer attrition over the next six months, at this time.

Customer Credit Risk

Our bad debt expense for the three months ended June 30, 2021 and 2020 was 0.3% and 1.5%, respectively, and our bad debt expense for the six months ended June 30, 2021 and 2020 was (0.4)% and 2.5% respectively, for non-purchase of receivable market ("non-POR") revenues. An increased focus on collection efforts, timely billing and credit monitoring for new enrollments in non-POR markets beginning in late 2020 have led to an improvement in the bad debt expense over the past several months, including the three months ended June 30, 2021. We have also been able to collect on debts that were previously written off, which has further reduced our bad debt expense during the three and six months ended June 30, 2021.

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.

Winter Storm Uri 

During the first quarter of 2021, the U.S. experienced Winter Storm Uri, an unprecedented storm bringing extreme cold temperatures to the central U.S., including Texas. As a result of increased power demand for customers across the state of Texas and power generation disruptions during the weather event, power and ancillary costs in the ERCOT service area reached or exceeded maximum allowed clearing prices. As of June 30, 2021, we recorded a net loss of approximately $64.9 million as a direct result of Winter Storm Uri. Although our hedge position was 120% of our forecasted demand in Texas for the month of February, we were still required to purchase power at unprecedented prices for an extended period of time during the storm. These price caps imposed by ERCOT for the duration of the storm and beyond have never been experienced in any deregulated market in which we serve. The policies imposed on the electricity markets by ERCOT related to pricing resulted in overall negative impact on our electricity unit margin for 2021.

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 $0.1 million and $0.1 million for the three months ended June 30, 2021 and 2020, 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 June 30,		Six Months Ended June 30,	
(in thousands)	2021		2020		2021		2020	
Adjusted EBITDA (1)	$	14,372			$	23,848			$	47,039			$	54,148		
Retail Gross Margin (2)	$	26,440			$	44,994			$	76,452			$	100,455		
(1) Adjusted EBITDA for the six months ended June 30, 2021 includes a $60.0 million add back related to Winter Storm Uri. See discussion below. Adjusted 	 EBITDA for three and six months ended June 30, 2021 includes a deduction of $2.2 million non-recurring legal settlement related to an add back in 2019.
(2) Retail Gross Margin for the six months ended June 30, 2021 includes a $64.9 million add back related to Winter Storm Uri. See discussion below. 

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-recurring operating items. EBITDA is defined as net income (loss) before the provision for income taxes, interest expense and depreciation and amortization. This conforms to the calculation of Adjusted EBITDA in our Senior Credit Facility.

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 gains (losses) on derivative instruments, excluding current period cash settlements, from the Adjusted EBITDA calculation in order to remove the non-cash impact of net gains and losses on 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.

We 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 have historically included the financial impact of weather variability in the calculation of Adjusted EBITDA. We will continue this historical approach, but during the first quarter of 2021 we incurred a net pre-tax financial loss of $64.9 million due to Winter Storm Uri, as described above. This loss was incurred due to uncharacteristic extended sub-freezing temperatures across Texas combined with the impact of the pricing caps ordered by ERCOT. We believe this event is unusual, infrequent, and non-recurring in nature. 

Our lenders under the Company's Senior Credit Facility allowed $60.0 million of the $64.9 million pre-tax storm loss to be added back as a non-recurring item in the calculation of Adjusted EBITDA for the Company's Debt Covenant Calculations. As our Senior Credit Facility is considered a material agreement and Adjusted EBITDA is a key component of our material covenants, we consider our covenant compliance to be material to the understanding of the Company's financial condition and/or liquidity.

We believe that the presentation of Adjusted EBITDA provides information useful to investors in assessing our performance and results of operations and that Adjusted EBITDA is also useful for an understanding of our financial condition and/or liquidity due to its use in covenants in our Senior Credit Facility. Adjusted EBITDA is a supplemental financial measure that management and external users of our 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, historical cost basis and specific items not reflective of ongoing operations;
•	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 9 "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 income (loss) 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.
  	Three Months Ended June 30,		Six Months Ended June 30,	
(in thousands)	2021		2020		2021		2020	
Reconciliation of Adjusted EBITDA to net income (loss):								
Net income (loss)	$	24,796			$	26,777			$	(2,764)		$	36,845		
Depreciation and amortization		5,413				8,010				11,449				16,806		
Interest expense		1,552				1,193				2,863				2,746		
Income tax expense 		3,674				5,673				2,139				7,598		
EBITDA 		35,435				41,653				13,687				63,995		
Less:								
Net, gain (loss) on derivative instruments		18,904				8,121				25,928				(16,466)	
Net cash settlements on derivative instruments		795				9,964				(390)			26,572		
Customer acquisition costs		243				210				456				1,555		
       Plus:								
       Non-cash compensation expense		1,104				490				1,571				1,814		
Non-recurring event - Winter Storm Uri		—				—				60,000				—		
Non-recurring legal settlement 		(2,225)			—				(2,225)			—		
Adjusted EBITDA	$	14,372			$	23,848			$	47,039			$	54,148		
 
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 June 30,		Six Months Ended June 30,	
(in thousands)	2021		2020		2021		2020	
Reconciliation of Adjusted EBITDA to net cash provided in operating activities:								
Net cash provided by operating activities	$	32,800			$	32,394			$	9,168			$	71,783		
Amortization of deferred financing costs		(258)			(240)			(517)			(490)	
Bad debt expense		(134)			(1,378)			113				(3,733)	
Interest expense		1,552				1,193				2,863				2,746		
Income tax expense 		3,674				5,673				2,139				7,598		
Non-recurring event - Winter Storm Uri		—				—				60,000				—		
Non-recurring legal settlement		(2,225)			—				(2,225)			—		
Changes in operating working capital								
Accounts receivable, prepaids, current assets		(20,058)			(32,035)			(31,761)			(50,010)	
Inventory		965				709				(400)			(1,981)	
Accounts payable and accrued liabilities		8,059				19,021				12,857				29,839		
Other		(10,003)			(1,489)			(5,198)			(1,604)	
Adjusted EBITDA	$	14,372			$	23,848			$	47,039			$	54,148		
Cash Flow Data:								
Net cash provided by operating activities	$	32,800			$	32,394			$	9,168			$	71,783		
Net cash used in investing activities	$	(543)		$	(43)		$	(1,063)		$	(579)	
Net cash (used in) provided by financing activities	$	(9,208)		$	(8,198)		$	24,751			$	(49,248)	

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 revenues (expenses), (iv) net gains (losses) on non-trading derivative instruments, (v) net current period cash settlements on non-trading derivative instruments and (vi) gains (losses) from non-recurring events (including non-recurring market volatility. 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 a result of recurring operations. 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. 

We have historically included the financial impact of weather variability in the calculation of Retail Gross Margin. We will continue this historical approach, but during the first quarter of 2021 we added back the $64.9 million net financial loss incurred related to Winter Storm Uri, as described above, in the calculation of Retail Gross Margin because the extremity of the Texas storm combined with the impact of unprecedented pricing mechanisms ordered by ERCOT is considered unusual, infrequent, and non-recurring in nature. 

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 June 30,		Six Months Ended June 30,	
(in thousands)	2021		2020		2021		2020	
Reconciliation of Retail Gross Margin to Operating income:								
Operating income	$	29,943			$	33,590			$	2,073			$	46,976		
Plus:								
Depreciation and amortization		5,413				8,010				11,449				16,806		
General and administrative expense		10,663				21,331				23,334				47,007		
Less:								
Net asset optimization (expense) revenue		(114)			(82)			(254)			239		
Gain (loss) on non-trading derivative instruments		18,898				7,964				25,952				(16,569)	
Cash settlements on non-trading derivative instruments		795				10,055				(394)			26,664		
Non-recurring event - Winter Storm Uri		—				—				(64,900)			—		
Retail Gross Margin	$	26,440			$	44,994			$	76,452			$	100,455		
Retail Gross Margin - Retail Electricity Segment (1)	$	21,651			$	35,573			$	52,265			$	66,379		
Retail Gross Margin - Retail Natural Gas Segment	$	4,789			$	9,421			$	24,187			$	34,076		
(1) Retail Gross Margin - Retail Electricity Segment for the six months ended June 30, 2021 includes a $64.9 million add back related to winter storm Uri. 

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.

 Consolidated Results of Operations

Three and Six Months Ended June 30, 2021 Compared to Three and Six Months Ended June 30, 2020 
(In Thousands)	Three Months Ended June 30,		Six Months Ended June 30,	
	2021		2020		2021		2020	
Revenues:								
Retail revenues	$	82,309			$	128,618			$	195,454			$	294,978		
Net asset optimization (expense) revenue		(114)				(82)				(254)				239		
Total Revenues		82,195				128,536				195,200				295,217		
Operating Expenses:								
Retail cost of revenues		36,176				65,605				158,344				184,428		
General and administrative expense		10,663				21,331				23,334				47,007		
Depreciation and amortization		5,413				8,010				11,449				16,806		
Total Operating Expenses		52,252				94,946				193,127				248,241		
Operating income		29,943				33,590				2,073				46,976		
Other (expense)/income:								
Interest expense		(1,552)				(1,193)				(2,863)				(2,746)		
Interest and other income		79				53				165				213		
Total other expense		(1,473)				(1,140)				(2,698)				(2,533)		
Income (loss) before income tax expense 		28,470				32,450				(625)				44,443		
Income tax expense 		3,674				5,673				2,139				7,598		
Net income (loss)	$	24,796			$	26,777			$	(2,764)			$	36,845		
Other Performance Metrics:								
  Adjusted EBITDA (1) (2)	$	14,372			$	23,848			$	47,039			$	54,148		
  Retail Gross Margin (1) (3)	$	26,440			$	44,994			$	76,452			$	100,455		
  Customer Acquisition Costs	$	243			$	210			$	456			$	1,555		
  Average Monthly RCE Attrition		3.3	%			3.5	%			3.7	%			4.6	%	
 
(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.
(2) Adjusted EBITDA for the six months ended June 30, 2021 includes a $60.0 million add back related to Winter Storm Uri and Adjusted EBITDA for three and six months ended June 30, 2021 includes a deduction of $2.2 million non-recurring legal settlement related to an add back in 2019.
(3) Retail Gross Margin for the six months ended June 30, 2021 includes a $64.9 million add back related to Winter Storm Uri. 

Three Months Ended June 30, 2021 Compared to Three Months Ended June 30, 2020

Total Revenues. Total revenues for the three months ended June 30, 2021 were approximately $82.2 million, a decrease of approximately $46.3 million, or 36%, from approximately $128.5 million for the three months ended June 30, 2020, 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 smaller customer book in the second quarter of 2021 as compared to the second quarter of 2020.
Change in electricity volumes sold	$	(41.8)	
Change in natural gas volumes sold		(5.8)	
Change in electricity unit revenue per MWh		1.2		
Change in natural gas unit revenue per MMBtu		0.1		
Change in total revenues	$	(46.3)	

Retail Cost of Revenues. Total retail cost of revenues for the three months ended June 30, 2021 was approximately $36.2 million, a decrease of approximately $29.4 million, or 45%, from approximately $65.6 million for the three months ended June 30, 2020, 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 customer book in 2021 and a change in the fair value of our retail derivative portfolio.
Change in electricity volumes sold	$	(28.6)	
Change in natural gas volumes sold		(2.5)	
Change in electricity unit cost per MWh		2.0		
Change in natural gas unit cost per MMBtu		1.4		
Change in value of retail derivative portfolio		(1.7)	
Change in retail cost of revenues	$	(29.4)	

General and Administrative Expense. General and administrative expense for the three months ended June 30, 2021 was approximately $10.7 million, a decrease of approximately $10.6 million, or 50%, as compared to $21.3 million for the three months ended June 30, 2020. This decrease was primarily attributable to lower employee costs, lower bad debt expense due to improved collection efforts and lower legal fees in the second quarter of 2021.

Depreciation and Amortization Expense. Depreciation and amortization expense for the three months ended June 30, 2021 was approximately $5.4 million, a decrease of approximately $2.6 million, or 33%, from approximately $8.0 million for the three months ended June 30, 2020. 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 June 30, 2021 was approximately $0.2 million, an increase of less than $0.1 million, or 16%, from approximately $0.2 million for the three months ended June 30, 2020. The lower customer acquisition cost in both periods was primarily due to limitation on our ability to use door-to-door marketing as a result of COVID-19 and a reduction in targeted organic customer acquisitions as we focus our efforts to improve our organic sales channels, including vendor selection and sales quality.

Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020

Total Revenues. Total revenues for the six months ended June 30, 2021 were approximately $195.2 million, a decrease of approximately $100.0 million, or 34%, from approximately $295.2 million for the six months ended June 30, 2020, as indicated in the table below (in millions). This decrease was primarily due to a decrease in electricity and natural gas volumes due to a smaller customer book in 2021 as compared to 2020, partially offset by an increase in electricity unit revenue per MWh.
Change in electricity volumes sold	$	(94.3)	
Change in natural gas volumes sold		(18.1)	
Change in electricity unit revenue per MWh		9.7		
Change in electricity unit revenue per MMBtu - Winter Storm Uri		0.9		
Change in natural gas unit revenue per MMBtu		2.2		
Change in net asset optimization revenue (expense)		(0.4)	
Change in total revenues	$	(100.0)	

Retail Cost of Revenues. Total retail cost of revenues for the six months ended June 30, 2021 was approximately $158.3 million, a decrease of approximately $26.1 million, or 14%, from approximately $184.4 million for the six months ended June 30, 2020, 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 customer book in 2021, a decrease in electricity and natural gas unit cost, a decrease due to change in fair value of our retail derivative portfolio, offset by an increase in electricity supply costs due to Winter Storm Uri in the first quarter of 2021.
Change in electricity volumes sold	$	(67.5)	
Change in natural gas volumes sold		(8.0)	
Change in electricity unit cost per MWh		(2.8)	
Change in electricity unit cost per MWh - Winter Storm Uri		65.8		
Change in natural gas unit cost per MMBtu		1.9		
Change in value of retail derivative portfolio		(15.5)	
Change in retail cost of revenues	$	(26.1)	

General and Administrative Expense. General and administrative expense for the six months ended June 30, 2021 was approximately $23.3 million, a decrease of approximately $23.7 million, or 50%, as compared to $47.0 million for the six months ended June 30, 2020. This decrease was primarily attributable to lower employee costs, lower bad debt expense in 2021 due to improved collection efforts and lower legal costs.

Depreciation and Amortization Expense. Depreciation and amortization expense for the six months ended June 30, 2021 was approximately $11.4 million, a decrease of approximately $5.4 million, or 32%, from approximately $16.8 million for the six months ended June 30, 2020. This decrease was primarily due to the decreased amortization expense associated with customer relationship intangibles.

Customer Acquisition Cost. Customer acquisition cost for the six months ended June 30, 2021 was approximately $0.5 million, a decrease of approximately $1.1 million, or 71%, from approximately $1.6 million for the six months ended June 30, 2020. This decrease was primarily due to limitation on our ability to use door-to-door marketing as a result of COVID-19 and a reduction in targeted organic customer acquisitions as we focus our efforts to improve our organic sales channels, including vendor selection and sales quality.

Operating Segment Results
(in thousands, except volume and per unit operating data)	Three Months Ended  
June 30,		Six Months Ended  
June 30,	
  	2021		2020		2021		2020	
								
Retail Electricity Segment								
Total Revenues	$	71,689			$	112,255			$	150,444			$	234,023		
Retail Cost of Revenues		31,203				59,268				138,727				159,651		
Less: Net gain on non-trading derivatives, net of cash settlements		18,835				17,414				24,352				7,993		
Non-recurring event - Winter Storm Uri		—				—				(64,900)			—		
Retail Gross Margin (1)  — Electricity	$	21,651			$	35,573			$	52,265			$	66,379		
Volumes — Electricity (MWhs) (3)		614,000				978,297				1,236,127				2,069,722		
Retail Gross Margin (2) (4) — Electricity per MWh	$	35.26			$	36.36			$	42.28			$	32.07		
								
Retail Natural Gas Segment								
Total Revenues	$	10,620			$	16,363			$	45,010			$	60,955		
Retail Cost of Revenues		4,973				6,337				19,617				24,777		
Less: Net gain on non-trading derivatives, net of cash settlements		858				605				1,206				2,102		
Retail Gross Margin (1) — Gas	$	4,789			$	9,421			$	24,187			$	34,076		
Volumes — Gas (MMBtus)		1,268,051				1,967,439				5,097,525				7,249,738		
Retail Gross Margin (2) — Gas per MMBtu	$	3.78			$	4.79			$	4.75			$	4.70		

(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.
(3) Excludes volumes (8,402 MWhs) related to Winter Storm Uri impact for the six months ended June 30, 2021.
(4) Retail Gross Margin - Electricity per MWh excludes Winter Storm Uri impact.

Three Months Ended June 30, 2021 Compared to Three Months Ended June 30, 2020
Retail Electricity Segment
Total revenues for the Retail Electricity Segment for the three months ended June 30, 2021 were approximately $71.7 million, a decrease of approximately $40.6 million, or 36%, from approximately $112.3 million for the three months ended June 30, 2020. This decrease was largely due to lower volumes sold, resulting in a decrease of $41.8 million as a result of smaller customer book in 2021 offset by higher retail electricity prices which resulted in an increase of $1.2 million.
Retail cost of revenues for the Retail Electricity Segment for the three months ended June 30, 2021 were approximately $31.2 million, a decrease of approximately $28.1 million, or 47%, from approximately $59.3 million for the three months ended June 30, 2020. This decrease was primarily due to fewer customers, resulting in a decrease of $28.6 million, an increase in supply costs of $2.0 million, and a change in the value of our retail derivative portfolio used for hedging, which resulted in a decrease of $1.5 million. 
Retail gross margin for the Retail Electricity Segment for the three months ended June 30, 2021 was approximately $21.7 million, a decrease of approximately $13.9 million, or 39%, from approximately $35.6 million for the three months ended June 30, 2020, as indicated in the table below (in millions).
Change in volumes sold	$	(13.3)	
Change in unit margin per MWh		(0.6)	
Change in retail electricity segment retail gross margin	$	(13.9)	
Retail Natural Gas Segment
Total revenues for the Retail Natural Gas Segment for the three months ended June 30, 2021 were approximately $10.6 million, a decrease of approximately $5.8 million, or 35%, from approximately $16.4 million for the three months ended June 30, 2020. This decrease was primarily attributable to lower volumes sold, which decreased total revenues by $5.8 million offset by an increase of less than $0.1 million related to higher natural gas rates.
Retail cost of revenues for the Retail Natural Gas Segment for the three months ended June 30, 2021 were approximately $5.0 million, a decrease of $1.3 million, or 21%, from approximately $6.3 million for the three months ended June 30, 2020. This decrease was primarily due to lower volumes resulting in a decrease of $2.5 million, higher natural gas costs, which resulted in an increase of $1.4 million, and a change in the value of our derivative portfolio used for hedging, which resulted in a decrease of $0.2 million.
Retail gross margin for the Retail Natural Gas Segment for the three months ended June 30, 2021 was approximately $4.8 million, a decrease of approximately $4.6 million, or 49%, from approximately $9.4 million for the three months ended June 30, 2020, as indicated in the table below (in millions).
Change in volumes sold	$	(3.3)	
Change in unit margin per MMBtu		(1.3)	
Change in retail natural gas segment retail gross margin	$	(4.6)	

Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020
Retail Electricity Segment
Total revenues for the Retail Electricity Segment for the six months ended June 30, 2021 were approximately $150.4 million, a decrease of approximately $83.6 million, or 36%, from approximately $234.0 million for the six months ended June 30, 2020. This decrease was largely due to a decrease in volumes, resulting in a decrease of $94.3 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 $9.7 million and an increase of $0.9 million related to electricity revenue due to Winter Storm Uri.
Retail cost of revenues for the Retail Electricity Segment for the six months ended June 30, 2021 was approximately $138.7 million, a decrease of approximately $21.0 million, or 13%, from approximately $159.7 million for the six months ended June 30, 2020. This decrease was primarily due to a decrease in volumes, resulting in a decrease of $67.5 million. This decrease was further impacted by decreased electricity prices, which resulted in a decrease in retail cost of revenues of $2.8 million and a decrease of $16.5 million due to a change in the value of our retail derivative portfolio used for hedging. This was offset by an increase in supply cost of $65.8 million related to Winter Storm Uri.
Retail gross margin for the Retail Electricity Segment for the six months ended June 30, 2021 was approximately $52.3 million, a decrease of approximately $14.1 million, or 21%, from approximately $66.4 million for the six months ended June 30, 2020, as indicated in the table below (in millions).
Change in volumes sold	$	(26.7)	
Change in gross margin - Winter Storm Uri		64.9		
Change in unit margin per MWh		(52.3)	
Change in retail electricity segment retail gross margin	$	(14.1)	
Retail Natural Gas Segment
Total revenues for the Retail Natural Gas Segment for the six months ended June 30, 2021 were approximately $45.0 million, a decrease of approximately $16.0 million, or 26%, from approximately $61.0 million for the six months ended June 30, 2020. This decrease was primarily attributable to a decrease in volumes of $18.1 million, partially offset by higher rates, which resulted in an increase in total revenues of $2.2 million.
Retail cost of revenues for the Retail Natural Gas Segment for the six months ended June 30, 2021 was approximately $19.6 million, a decrease of approximately $5.2 million, or 21%, from approximately $24.8 million for the six months ended June 30, 2020. The decrease of $8.0 million was related to lower volumes, offset by increased supply costs of $1.9 million, and a $1.0 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 six months ended June 30, 2021 was approximately $24.2 million, a decrease of approximately $9.9 million, or 29%, from approximately $34.1 million for the six months ended June 30, 2020, as indicated in the table below (in millions).
Change in volumes sold	$	(10.2)	
Change in unit margin per MMBtu		0.3		
Change in retail natural gas segment retail gross margin	$	(9.9)	

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 impacts of the COVID-19 pandemic, Winter Storm Uri, forward prices for natural gas and electricity, market volatility and our then existing capital structure and requirements.

Liquidity Position 

The following table details our available liquidity as of June 30, 2021:
($ in thousands)	June 30, 2021	
Cash and cash equivalents	$	93,035		
Senior Credit Facility Availability (1)		43,739		
Subordinated Debt Facility Availability (2) 		15,000		
Total Liquidity	$	151,774		
(1) Reflects amount of Letters of Credit that could be issued based on existing covenants as of June 30, 2021.
(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.

Cash Flows 

Our cash flows were as follows for the respective periods (in thousands):
  	Six Months Ended June 30,	
  	2021		2020	
Net cash provided by operating activities	$	9,168			$	71,783		
Net cash used in investing activities	$	(1,063)		$	(579)	
Net cash provided (used) in financing activities	$	24,751			$	(49,248)	

Six Months Ended June 30, 2021 Compared to the Six Months Ended June 30, 2020

Cash Flows Provided by Operating Activities. Cash flows provided by operating activities for the six months ended June 30, 2021 decreased by $62.6 million compared to the six months ended June 30, 2020. The decrease was primarily the result of the non-recurring Winter Storm Uri related costs of $64.9 million for the six months ended June 30, 2021.

Cash Flows Used in Investing Activities. Cash flows used in investing activities increased by $0.5 million for the six months ended June 30, 2021. The increase was primarily the result of increased capital spending during six months ended June 30, 2021.

Cash Flows Provided by Financing Activities. Cash flows provided by financing activities increased by $74.0 million for the six months ended June 30, 2021, primarily due to an increase in net borrowings under our Senior Credit Facility of $58.0 million and an increase in sub-debt borrowing of $10.0 million during the six months ended June 30, 2021.

Sources of Liquidity and Capital Resources

Senior Credit Facility

As of June 30, 2021, we had total commitments of $227.5 million under the Senior Credit Facility, of which $156.4 million was outstanding, including $21.4 million of outstanding letters of credit, with a maturity date of July 31, 2022. We are currently in the process of amending and extending the current maturity date of our Senior Credit Facility and expect it to extend in the third quarter of 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 9 "Debt" in the notes to our condensed consolidated financial statements.

As of June 30, 2021, we were in compliance with the covenants under our Senior Credit Facility. Based upon existing covenants as of June 30, 2021, we had availability to borrow up to $43.7 million under the 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 9 "Debt" for additional details. As of June 30, 2021, there was $10.0 million outstanding borrowings under the Subordinated Debt Facility, and availability to borrow up to $15.0 million 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 July 2022, 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 June 30, 2021 was $135.0 million. The current variable interest rate on the facility at June 30, 2021 was 3.75%.

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 June 30, 2021 and 2020, we spent a total of $0.2 million and $0.2 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 six months ended June 30, 2021 and 2020 included $1.1 million and $0.6 million, respectively, related to information systems improvements.

Dividends and Distributions

During the six months ended June 30, 2021, we paid dividends to holders of our Class A common stock for the quarter ended December 31, 2020 of $0.18125 per share or $5.3 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 Class B common stock (our non-controlling interest holders). As a result, during the six months ended June 30, 2021, Spark HoldCo made distributions of $7.6 million to our non-controlling interest holders related to the dividend payments to holders of our Class A common stock.

For the six months ended June 30, 2021, we paid $2.0 million of dividends to holders of our Series A Preferred Stock, and as of June 30, 2021, we had accrued $2.0 million related to dividends to holders of our Series A Preferred Stock, which we paid on July 15, 2021. For the full year ended December 31, 2021, at the stated dividend rate of the Series A Preferred Stock of $2.1875 per share, we would be required to pay dividends of $7.9 million in the aggregate based on the Series A Preferred Stock outstanding as of June 30, 2021.

On July 21, 2021, our Board of Directors declared a quarterly cash dividend in the amount of $0.18125 per share to holders of our Class A common stock and $0.546875 per share for the Series A Preferred Stock for the second quarter of 2021. Dividends on Class A common stock will be paid on September 15, 2021 to holders of record on September 1, 2021, and Series A Preferred Stock dividends will be paid on October 15, 2021 to holders of record on October 1, 2021.

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.

Share Repurchase Program

On August 18, 2020, our Board of Directors authorized a share repurchase program of up to $20.0 million of Class A common stock through August 18, 2021. The share repurchase program was suspended in March 2021 pursuant to an agreement with lenders under our Senior Credit Facility. During the six months ended June 30, 2021, we did not repurchase our Class A common stock.

Collateral Posting Requirements

Our contractual agreements with certain local regulated utilities and our supplier counterparties require us to maintain restricted cash balances or letters of credit as collateral for credit risk or the performance risk associated with the future delivery of natural gas or electricity. Due to the COVID-19 pandemic, certain local regulated utilities and our supplier counterparties have contacted us inquiring about our financial condition and the impact the pandemic is having on our operations. These inquiries may lead to additional requests for cash or letters of credit in an effort to mitigate the risk of default in paying our obligations related to the future delivery of natural gas or electricity. As of June 30, 2021, we had not been required to post additional collateral as a result of COVID-19. 

As discussed above, during the Winter Storm Uri event, we were required to post a significant amount of collateral with ERCOT. Despite these posting requirements, we consistently maintained, and continue to maintain, sufficient liquidity to conduct our operations in the ordinary course. As of June 30, 2021, we had not been required to post additional collateral as a result of the Winter Storm Uri.

Off-Balance Sheet Arrangements
As of June 30, 2021, we had no material "off-balance sheet arrangements."

Related Party Transactions

For a discussion of related party transactions, see Note 13 "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 2020 Form 10-K. There have been no changes to these policies and estimates since the date of our 2020 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 12 "Commitments and Contingencies" to Part I, Item 1 of this Report, as of June 30, 2021, 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 12 "Commitments and Contingencies" to Part I, Item 1 of this Report.

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 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 $19.7 million and $18.0 million for the three months ended June 30, 2021 and $25.6 million and $10.1 million for the six months ended June 30, 2021 and 2020, 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 2020 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 June 30, 2021, our Gas Non-Trading Fixed Price Open Position (hedges net of retail load) was a short position of 79,173 MMBtu. An increase of 10% in the market prices (NYMEX) from their June 30, 2021 levels would have decreased 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 June 30, 2021 levels would have increased the fair market value of our non-trading energy derivatives by less than $0.1 million. As of June 30, 2021, our Electricity Non-Trading Fixed Price Open Position (hedges net of retail load) was a short position of 176,063 MWhs. An increase of 10% in the forward market prices from their June 30, 2021 levels would have decreased the fair market value of our net non-trading energy portfolio by less than $0.1 million. Likewise, a decrease of 10% in the forward market prices from their June 30, 2021 levels would have increased the fair market value of our non-trading energy derivatives by less than $0.1 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. These POR programs result in substantially all of our credit risk being with the utility and not to our end-use customers in these territories. Approximately 56% and 64% 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 June 30, 2021 and 2020 and 60% and 64% for the six months ended June 30, 2021 and 2020, respectively, all of which had investment grade ratings as of such date. We paid these local regulated utilities a weighted average discount of  0.9% and 1.0%, for the three months ended June 30, 2021 and 2020, respectively, and 0.8% and 0.7% for the six months ended June 30, 2021 and 2020, 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 to the extent the ability to terminate service has not been limited as a result of COVID-19. 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 as 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 (including impacts from COVID-19) 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 June 30, 2021 and 2020 was approximately 0.3% and 1.5% of non-POR market retail revenues, respectively, and our bad debt expense for the six months ended June 30, 2021 and 2020 was approximately (0.4%) and 2.5% 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 six months ended June 30, 2021.
The current COVID-19 pandemic has caused regulatory agencies and other governmental authorities to take, and potentially continue to take, emergency or other actions in light of the pandemic that may impact our customer credit risk, including prohibiting the termination of service for non-payment during the current COVID-19 pandemic, requiring deferred payment plans for certain customers unable to pay their bill, and utilities increasing POR fees they charge us in an effort to recoup their bad debts losses. Please see “Item 1A—Risk Factors” in our 2020 Form 10-K.
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 June 30, 2021, approximately $3.0 million of our total exposure of $13.6 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 June 30, 2021.
Interest Rate Risk
We are exposed to fluctuations in interest rates under our variable-price debt obligations. At June 30, 2021, we were co-borrowers under the Senior Credit Facility, under which $135.0 million of variable rate indebtedness was outstanding. Based on the average amount of our variable rate indebtedness outstanding during the three months ended June 30, 2021, a 1% increase in interest rates would have resulted in additional annual interest expense of approximately $1.4 million. 

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our Chief Executive Officer and our Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10-Q. The term “disclosure controls and procedures,” as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to our management, including our principal executive and principal financial officers or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving their objectives, and management necessarily applies its judgment in evaluating the cost benefit relationship of possible controls and procedures. Based on this evaluation, management concluded that our disclosure controls and procedures were effective as of June 30, 2021 at the 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 June 30, 2021 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

See Note 12 "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 2020 Form 10-K. There has been no material change in our risk factors from those described in the 2020 Form 10-K, except as described below. 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 June 30, 2021.

Item 6. Exhibits	

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

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	
2.9	First Amendment to Asset Purchase Agreement, by and between Spark HoldCo, LLC, Starion Energy Inc., Starion Energy NY Inc., and Starion Energy PA, Inc., effective May 1, 2020.	10-Q	2.9	8/5/2020	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	
4.2	Class A Common Stock Certificate	S-1	4.1	6/30/2014	333-196375	
10.1#	Transition and Resignation Agreement and Mutual Release of Claims, dated April 2, 2021, between Spark Energy, Inc. and Kevin McMinn 	8-K	10.1	4/8/2021	001-36559	
31.1*	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.					
31.2*	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.					
32**	Certifications pursuant to 18 U.S.C. Section 1350.					
101.INS*	XBRL Instance Document – the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL					
101.SCH*	Inline XBRL Taxonomy Extension Schema Document.					
101.CAL*	Inline XBRL Taxonomy Extension Calculation Linkbase Document.					
101.LAB*	Inline XBRL Taxonomy Extension Label Linkbase Document.					
101.PRE*	Inline XBRL Taxonomy Extension Presentation Linkbase Document.					
101.DEF*	Inline XBRL Taxonomy Extension Definition Linkbase Document.					
104* 	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101.INS)					

* Filed herewith
** Furnished herewith
# Certain schedules, exhibits and annexes have been omitted in reliance on Item 601 (a)(5) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted schedule, exhibit or annex 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.	

August 5, 2021			/s/ James G. Jones II	
			James G. Jones II	
			Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)