Via Renewables, Inc. - Quarter Report: 2019 June (Form 10-Q)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549



		FORM 10-Q

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

For the quarterly period ended June 30, 2019

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

For the transition period from to

Commission File Number: 001-36559

Spark Energy, Inc.

(Exact name of registrant as specified in its charter)




Delaware				46-5453215
(State or other jurisdiction of incorporation or organization)				(I.R.S. Employer Identification No.)

12140 Wickchester Ln, Suite 100

Houston, Texas 77079

(Address of principal executive offices)

(713) 600-2600

(Registrant's telephone number, including area code)

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



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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes x No o

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this Chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

Yes x No o

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

Large accelerated filer o Accelerated filer x

Non-accelerated filer o Smaller reporting company o

Emerging Growth Company x

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No x

There were 14,379,553 shares of outstanding Class A common stock, 20,800,000 shares of Class B common stock and 3,702,756 shares of Series A Preferred Stock outstanding as of August 6, 2019.



SPARK ENERGY, INC.
INDEX TO QUARTERLY REPORT ON FORM 10-Q
For the Quarter Ended June 30, 2019
		Page No.
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS

CONDENSED CONSOLIDATED BALANCE SHEETS AS OF JUNE 30, 2019 AND DECEMBER 31, 2018 (unaudited)		3

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2019 AND 2018 (unaudited)		4

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2019 AND 2018 (unaudited)		5

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE SIX MONTHS ENDED JUNE 30, 2019 AND 2018 (unaudited)		9

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (unaudited)		10

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		42
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		62
ITEM 4. CONTROLS AND PROCEDURES		64
PART II. OTHER INFORMATION		65
ITEM 1. LEGAL PROCEEDINGS		65
ITEM 1A. RISK FACTORS		65
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		66
ITEM 6. EXHIBITS		67
SIGNATURES		69

Table of Contents

Cautionary Note Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q (this “Report”) contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. These forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), can be identified by the use of forward-looking terminology including “may,” “should,” “likely,” “will,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” “plan,” “intend,” “project,” or other similar words. All statements, other than statements of historical fact included in this Report, regarding strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans, objectives and beliefs of management are forward-looking statements. Forward-looking statements appear in a number of places in this Report and may include statements about business strategy and prospects for growth, customer acquisition costs, legal proceedings, ability to pay cash dividends, cash flow generation and liquidity, availability of terms of capital, competition and government regulation and general economic conditions. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we cannot give any assurance that such expectations will prove correct.

The forward-looking statements in this Report are subject to risks and uncertainties. Important factors that could cause actual results to materially differ from those projected in the forward-looking statements include, but are not limited to:


•	changes in commodity prices;


•	the sufficiency of risk management and hedging policies and practices;


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


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


•	our ability to borrow funds and access credit markets;


•	restrictions in our debt agreements and collateral requirements;


•	credit risk with respect to suppliers and customers;


•	changes in costs to acquire customers as well as actual attrition rates;


•	accuracy of billing systems;


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


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


•	competition; and


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

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

Table of Contents

PART I. — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

SPARK ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands, except share counts)

(unaudited)



	June 30, 2019			December 31, 2018
Assets
Current assets:
Cash and cash equivalents	$	27,579		$	41,002
Restricted cash	1,001			8,636
Accounts receivable, net of allowance for doubtful accounts of $3,720 at June 30, 2019 and $3,353 at December 31, 2018	103,680			150,866
Accounts receivable—affiliates	3,882			2,558
Inventory	2,020			3,878
Fair value of derivative assets	52			7,289
Customer acquisition costs, net	13,004			14,431
Customer relationships, net	15,467			16,630
Deposits	9,331			9,226
Renewable energy credit asset	11,664			25,717
Other current assets	14,810			11,747
Total current assets	202,490			291,980
Property and equipment, net	3,575			4,366
Fair value of derivative assets	—			3,276
Customer acquisition costs, net	4,856			3,893
Customer relationships, net	23,810			26,429
Deferred tax assets	31,847			27,321
Goodwill	120,343			120,343
Other assets	10,163			11,130
Total assets	$	397,084		$	488,738
Liabilities, Series A Preferred Stock and Stockholders' Equity
Current liabilities:
Accounts payable	$	48,985		$	68,790
Accounts payable—affiliates	2,475			2,464
Accrued liabilities	23,165			10,845
Renewable energy credit liability	25,384			42,805
Fair value of derivative liabilities	25,848			6,478
Current payable pursuant to tax receivable agreement—affiliates	11,239			1,658
Current contingent consideration for acquisitions	1,328			1,328
Current portion of Note Payable	—			6,936
Other current liabilities	1,132			647
Total current liabilities	139,556			141,951
Long-term liabilities:
Fair value of derivative liabilities	4,578			106
Payable pursuant to tax receivable agreement—affiliates	16,336			25,917
Long-term portion of Senior Credit Facility	94,000			129,500
Subordinated debt—affiliate	—			10,000
Other long-term liabilities	260			212
Total liabilities	254,730			307,686
Commitments and contingencies (Note 13)
Series A Preferred Stock, par value $0.01 per share, 20,000,000 shares authorized, 3,707,256 issued and 3,702,756 outstanding at June 30, 2019 and 3,707,256 issued and outstanding at December 31, 2018	90,649			90,758
Stockholders' equity:
Common Stock:
Class A common stock, par value $0.01 per share, 120,000,000 shares authorized, 14,478,999 issued, and 14,379,553 outstanding at June 30, 2019 and 14,178,284 issued and 14,078,838 outstanding at December 31, 2018	145			142
Class B common stock, par value $0.01 per share, 60,000,000 shares authorized, 20,800,000 issued and outstanding at June 30, 2019 and December 31, 2018	209			209
Additional paid-in capital	42,329			46,157
Accumulated other comprehensive (loss) income	(38		)	2
Retained (deficit) earnings	(7,053		)	1,307
Treasury stock, at cost, 99,446 shares at June 30, 2019 and December 31, 2018	(2,011		)	(2,011		)
Total stockholders' equity	33,581			45,806
Non-controlling interest in Spark HoldCo, LLC	18,124			44,488
Total equity	51,705			90,294
Total liabilities, Series A Preferred Stock and Stockholders' equity	$	397,084		$	488,738

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

Table of Contents

SPARK ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(in thousands, except per share data)

(unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Revenues:
Retail revenues	$	177,805		$	231,488		$	417,959		$	515,489
Net asset optimization (expense) revenues	(56		)	763			2,496			3,450
Total Revenues	177,749			232,251			420,455			518,939
Operating Expenses:
Retail cost of revenues	158,759			162,669			354,014			452,545
General and administrative	37,247			27,780			66,723			57,827
Depreciation and amortization	10,312			12,861			22,467			25,880
Total Operating Expenses	206,318			203,310			443,204			536,252
Operating (loss) income	(28,569		)	28,941			(22,749		)	(17,313		)
Other (expense)/income:
Interest expense	(1,995		)	(2,316		)	(4,218		)	(4,561		)
Interest and other income	494			553			683			754
Total other expenses	(1,501		)	(1,763		)	(3,535		)	(3,807		)
(Loss) income before income tax (benefit) expense	(30,070		)	27,178			(26,284		)	(21,120		)
Income tax (benefit) expense	(4,586		)	3,251			(3,545		)	(3,216		)
Net (loss) income	$	(25,484	)	$	23,927		$	(22,739	)	$	(17,904	)
Less: Net (loss) income attributable to non-controlling interests	(18,369		)	15,142			(16,406		)	(15,584		)
Net (loss) income attributable to Spark Energy, Inc. stockholders	$	(7,115	)	$	8,785		$	(6,333	)	$	(2,320	)
Less: Dividend on Series A Preferred Stock	2,027			2,027			4,054			4,054
Net (loss) income attributable to stockholders of Class A common stock	$	(9,142	)	$	6,758		$	(10,387	)	$	(6,374	)
Other comprehensive (loss) income, net of tax:
Currency translation (loss) gain	$	(63	)	$	25		$	(98	)	$	(58	)
Other comprehensive (loss) income	(63		)	25			(98		)	(58		)
Comprehensive (loss) income	$	(25,547	)	$	23,952		$	(22,837	)	$	(17,962	)
Less: Comprehensive (loss) income attributable to non-controlling interests	(18,407		)	15,157			(16,464		)	(15,620		)
Comprehensive (loss) income attributable to Spark Energy, Inc. stockholders	$	(7,140	)	$	8,795		$	(6,373	)	$	(2,342	)

Net (loss) income attributable to Spark Energy, Inc. per share of Class A common stock
Basic	$	(0.64	)	$	0.51		$	(0.73	)	$	(0.48	)
Diluted	$	(0.73	)	$	0.51		$	(0.73	)	$	(0.52	)

Weighted average shares of Class A common stock outstanding
Basic	14,246			13,229			14,191			13,183
Diluted	35,046			13,246			34,991			34,668

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

Table of Contents

SPARK ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(in thousands)

(unaudited)



SIX MONTHS ENDED JUNE 30, 2019
	Issued Shares of Class A Common Stock	Issued Shares of Class B Common Stock	Treasury Stock		Class A Common Stock		Class B Common Stock		Treasury Stock			Accumulated Other Comprehensive Loss			Additional Paid-in Capital			Retained Earnings (Deficit)			Total Stockholders' Equity			Non-controlling Interest			Total Equity
Balance at December 31, 2018	14,178	20,800	(99	)	$	142	$	209	$	(2,011	)	$	2		$	46,157		$	1,307		$	45,806		$	44,488		$	90,294
Stock based compensation	301	—	—		—		—		—			—			2,511			—			2,511			—			2,511
Restricted stock unit vesting	—	—	—		3		—		—			—			(1,107		)	—			(1,104		)	—			(1,104		)
Consolidated net loss	—	—	—		—		—		—			—			—			(6,333		)	(6,333		)	(16,406		)	(22,739		)
Foreign currency translation adjustment for equity method investee	—	—	—		—		—		—			(40		)	—			—			(40		)	(58		)	(98		)
Distributions paid to non-controlling unit holders	—	—	—		—		—		—			—			—			—			—			(7,978		)	(7,978		)
Dividends paid to Class A common stockholders ($0.3625 per share)	—	—	—		—		—		—			—			(5,170		)	—			(5,170		)	—			(5,170		)
Changes in ownership interest	—	—	—		—		—		—			—			1,912			—			1,912			(1,912		)	—
Dividends paid to Preferred Stock	—	—	—		—		—		—			—			(2,029		)	(2,027		)	(4,056		)	—			(4,056		)
Proceeds from disgorgement of stockholder short-swing profits	—	—	—		—		—		—			—			55			—			55			—			55
Acquisition of Customers from Affiliate	—	—	—		—		—		—			—			—			—			—			(10		)	(10		)
Balance at June 30, 2019	14,479	20,800	(99	)	$	145	$	209	$	(2,011	)	$	(38	)	$	42,329		$	(7,053	)	$	33,581		$	18,124		$	51,705

Table of Contents



THREE MONTHS ENDED JUNE 30, 2019
	Issued Shares of Class A Common Stock	Issued Shares of Class B Common Stock	Treasury Stock		Class A Common Stock		Class B Common Stock		Treasury Stock			Accumulated Other Comprehensive Loss			Additional Paid-in Capital			Retained Earnings (Deficit)			Total Stockholders' Equity			Non-controlling Interest			Total Equity
Balance at March 31, 2019	14,241	20,800	(99	)	$	142	$	209	$	(2,011	)	$	(12	)	$	45,769		$	62		$	44,159		$	41,591		$	85,750
Stock based compensation	238	—	—		—		—		—			—			1,440			—			1,440			—			1,440
Restricted stock unit vesting	—	—	—		3		—		—			—			(1,107		)	—			(1,104		)	—			(1,104		)
Consolidated net loss	—	—	—		—		—		—			—			—			(7,115		)	(7,115		)	(18,369		)	(25,484		)
Foreign currency translation adjustment for equity method investee	—	—	—		—		—		—			(26		)	—			—			(26		)	(37		)	(63		)
Distributions paid to non-controlling unit holders	—	—	—		—		—		—			—			—			—			—			(4,208		)	(4,208		)
Dividends paid to Class A common stockholders ($0.18125 per share)	—	—	—		—		—		—			—			(2,606		)	—			(2,606		)	—			(2,606		)
Dividends to Preferred Stock	—	—	—		—		—		—			—			(2,029		)	—			(2,029		)	—			(2,029		)
Proceeds from disgorgement of stockholder short-swing profits	—	—	—		—		—		—			—			9			—			9			—			9
Changes in ownership interest	—	—	—		—		—		—			—			853			—			853			(853		)	—
Balance at June 30, 2019	14,479	20,800	(99	)	$	145	$	209	$	(2,011	)	$	(38	)	$	42,329		$	(7,053	)	$	33,581		$	18,124		$	51,705

Table of Contents

SPARK ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(in thousands)

(unaudited)



SIX MONTHS ENDED JUNE 30, 2018
	Issued Shares of Class A Common Stock	Issued Shares of Class B Common Stock	Treasury Stock		Class A Common Stock		Class B Common Stock		Treasury Stock			Accumulated Other Comprehensive Loss			Additional Paid-in Capital			Retained Earnings (Deficit)			Total Stockholders' Equity			Non-controlling Interest			Total Equity
Balance at December 31, 2017	13,235	21,485	(99	)	$	132	$	216	$	(2,011	)	$	(11	)	$	47,811		$	11,399		$	57,536		$	101,559		$	159,095
Stock based compensation	—	—	—		—		—		—			—			2,646			—			2,646			—			2,646
Restricted stock unit vesting	258	—	—		3		—		—			—			(715		)	—			(712		)	—			(712		)
Consolidated net loss	—	—	—		—		—		—			—			—			(2,320		)	(2,320		)	(15,584		)	(17,904		)
Foreign currency translation adjustment for equity method investee	—	—	—		—		—		—			(22		)	—			—			(22		)	(36		)	(58		)
Distributions paid to non-controlling unit holders	—	—	—		—		—		—			—			—			—			—			(19,501		)	(19,501		)
Dividends paid to Class A common stockholders ($0.3625 per share)	—	—	—		—		—		—			—			—			(4,805		)	(4,805		)	—			(4,805		)
Dividends to Preferred Stock	—	—	—		—		—		—			—			—			(4,055		)	(4,055		)	—			(4,055		)
Acquisition of Customers from Affiliate	—	—	—		—		—		—			—			—			—			—			(6,138		)	(6,138		)
Changes in ownership interest	—	—	—		—		—		—			—			(3,027		)	—			(3,027		)	3,027			—
Balance at June 30, 2018	13,493	21,485	(99	)	$	135	$	216	$	(2,011	)	$	(33	)	$	46,715		$	219		$	45,241		$	63,327		$	108,568

Table of Contents



THREE MONTHS ENDED JUNE 30, 2018
	Issued Shares of Class A Common Stock	Issued Shares of Class B Common Stock	Treasury Stock		Class A Common Stock		Class B Common Stock		Treasury Stock			Accumulated Other Comprehensive Loss			Additional Paid-in Capital			Retained Earnings (Deficit)			Total Stockholders' Equity			Non-controlling Interest			Total Equity
Balance at March 31, 2018	13,238	21,485	(99	)	$	132	$	216	$	(2,011	)	$	(43	)	$	47,900		$	(4,114	)	$	42,080		$	66,674		$	108,754
Stock based compensation	—	—	—		—		—		—			—			1,829			—			1,829			—			1,829
Restricted stock unit vesting	255	—	—		3		—		—			—			(701		)	—			(698		)	—			(698		)
Consolidated net income	—	—	—		—		—		—			—			—			8,785			8,785			15,142			23,927
Foreign currency translation adjustment for equity method investee	—	—	—		—		—		—			10			—			—			10			15			25
Distributions paid to non-controlling unit holders	—	—	—		—		—		—			—			—			—			—			(14,679		)	(14,679		)
Dividends paid to Class A common stockholders ($0.18125 per share)	—	—	—		—		—		—			—			—			(2,424		)	(2,424		)	—			(2,424		)
Dividends to Preferred Stock	—	—	—		—		—		—			—			—			(2,028		)	(2,028		)	—			(2,028		)
Acquisition of Customers from Affiliate	—	—	—		—		—		—			—			—			—			—			(6,138		)	(6,138		)
Changes in ownership interest	—	—	—		—		—		—			—			(2,313		)	—			(2,313		)	2,313			—
Balance at June 30, 2018	13,493	21,485	(99	)	$	135	$	216	$	(2,011	)	$	(33	)	$	46,715		$	219		$	45,241		$	63,327		$	108,568

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

Table of Contents

SPARK ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(unaudited)



	Six Months Ended June 30,
	2019			2018
Cash flows from operating activities:
Net loss	$	(22,739	)	$	(17,904	)
Adjustments to reconcile net loss to net cash flows provided by operating activities:
Depreciation and amortization expense	22,480			24,639
Deferred income taxes	(4,527		)	(3,396		)
Change in TRA liability	—			79
Stock based compensation	2,432			2,686
Amortization of deferred financing costs	505			612
Excess tax benefit related to restricted stock vesting	—			(101		)
Change in Fair Value of Earnout liabilities	—			(63		)
Bad debt expense	6,015			5,725
Loss on derivatives, net	54,997			19,488
Current period cash settlements on derivatives, net	(19,891		)	7,170
Other	(399		)	(554		)
Changes in assets and liabilities:
Decrease in accounts receivable	41,171			25,957
Increase in accounts receivable—affiliates	(1,324		)	(10		)
Decrease in inventory	1,858			2,693
Increase in customer acquisition costs	(9,185		)	(6,254		)
Decrease (increase) in prepaid and other current assets	11,545			(59		)
(Increase) decrease in other assets	(786		)	97
Decrease in accounts payable and accrued liabilities	(30,391		)	(20,140		)
Increase (decrease) in accounts payable—affiliates	11			(2,249		)
Decrease in other current liabilities	(792		)	(1,545		)
Increase (decrease) in other non-current liabilities	49			(461		)
Net cash provided by operating activities	51,029			36,410
Cash flows from investing activities:
Purchases of property and equipment	(460		)	(1,163		)
Acquisition of Starion customers	(5,913		)	—
Acquisition of HIKO	—			(15,041		)
Acquisition of Customers from Affiliate	—			(7,796		)
Net cash used in investing activities	(6,373		)	(24,000		)
Cash flows from financing activities:
Proceeds from (buyback) issuance of Series A Preferred Stock, net of issuance costs paid	(111		)	48,490
Borrowings on notes payable	118,500			146,800
Payments on notes payable	(164,000		)	(160,050		)
Payment of the Major Energy Companies Earnout	—			(1,607		)
Payments on the Verde promissory note	(2,036		)	(6,573		)
Proceeds from disgorgement of stockholders short-swing profits	55			244
Restricted stock vesting	(1,348		)	(2,589		)
Payment of Tax Receivable Agreement liability	—			(3,577		)
Payment of dividends to Class A common stockholders	(5,170		)	(4,805		)
Payment of distributions to non-controlling unitholders	(7,540		)	(19,501		)
Payment of Preferred Stock dividends	(4,054		)	(2,959		)
Payment to affiliates for acquisition of customer book	(10		)	—
Net cash used in financing activities	(65,714		)	(6,127		)
(Decrease) increase in Cash, cash equivalents and Restricted cash	(21,058		)	6,283
Cash, cash equivalents and Restricted cash—beginning of period	49,638			29,419
Cash, cash equivalents and Restricted cash—end of period	$	28,580		$	35,702
Supplemental Disclosure of Cash Flow Information:
Non-cash items:
Property and equipment purchase accrual	$	4		$	(123	)
Holdback for Verde Note—Indemnified Matters	$	4,900		$	—
Cash paid during the period for:
Interest	$	3,723		$	3,884
Taxes	$	1,440		$	5,399

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

Table of Contents

SPARK ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. Formation and Organization

Organization

We are an independent retail energy services company that provides residential and commercial customers in competitive markets across the United States with an alternative choice for natural gas and electricity. Spark Energy, Inc. (the "Company") is a holding company whose sole material asset consists of units in Spark HoldCo, LLC (“Spark HoldCo”). The Company is the sole managing member of Spark HoldCo, is responsible for all operational, management and administrative decisions relating to Spark HoldCo’s business and consolidates the financial results of Spark HoldCo and its subsidiaries. Spark HoldCo is the direct and indirect owner of the subsidiaries through which we operate. We conduct our business through several brands across our service areas, including Electricity Maine, Electricity N.H., Major Energy, Provider Power Massachusetts, Respond Power, Spark Energy, and Verde Energy.

Emerging Growth Company Status

The Company qualifies as an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012, or the JOBS Act. An emerging growth company may take advantage of specified reduced reporting and other regulatory requirements. The Company will remain an “emerging growth company” until the last day of 2019.

2. Basis of Presentation and Summary of Significant Accounting Policies

Basis of Presentation

The accompanying interim unaudited condensed consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) and pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC") as it applies to interim financial statements. This information should be read along with our consolidated financial statements and notes contained in our annual report on Form 10-K for the year ended December 31, 2018 (the “2018 Form 10-K”). Our unaudited condensed consolidated financial statements are presented on a consolidated basis and include all wholly-owned and controlled subsidiaries. We account for investments over which we have significant influence but not a controlling financial interest using the equity method of accounting. All significant intercompany transactions and balances have been eliminated in the unaudited condensed consolidated financial statements.

In the opinion of the Company's management, the accompanying condensed consolidated financial statements reflect all adjustments that are necessary to fairly present the financial position, the results of operations, the changes in equity and the cash flows of the Company for the respective periods. Such adjustments are of a normal recurring nature, unless otherwise disclosed.

Immaterial Corrections to Prior Year Financial Information

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

Table of Contents

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

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



	June 30, 2018
	As Reported			Adjustments			As Adjusted
Additional paid-in capital	$	28,846		$	17,869		$	46,715
Retained earnings	(2,678		)	2,897			219
Total Stockholders' Equity	24,475			20,766			45,241
Non-controlling interest in Spark HoldCo, LLC	86,302			(22,975		)	63,327
Total equity	$	110,777		$	(2,209	)	$	108,568

	Three Months Ended June 30, 2018
Net income attributable to stockholders of Class A common stock	$	5,473		$	1,285		$	6,758
Net income attributable to non-controlling interests	16,427			(1,285		)	15,142
Net income attributable to Spark Energy, Inc. stockholders	$	7,500		$	1,285		$	8,785

Net income attributable to Spark Energy, Inc. per share of Class A common stock
Basic	$	0.41		$	0.10		$	0.51
Diluted	$	0.41		$	0.10		$	0.51

	Six Months Ended June 30, 2018
Net loss attributable to stockholders of Class A common stock	$	(8,880	)	$	2,506		$	(6,374	)
Net loss attributable to non-controlling interests	(13,078		)	(2,506		)	(15,584		)
Net loss attributable to Spark Energy, Inc. stockholders	$	(4,826	)	$	2,506		$	(2,320	)

Net loss attributable to Spark Energy, Inc. per share of Class A common stock
Basic	$	(0.67	)	$	0.19		$	(0.48	)
Diluted	$	(0.67	)	$	0.15		$	(0.52	)

Subsequent Events

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

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

Table of Contents

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

New Accounting Standards Recently Adopted

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

In January 2017, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2017-04, Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment ("ASU 2017-04"). ASU 2017-04 simplifies the subsequent measurement of goodwill by eliminating Step 2 from the goodwill impairment test. Under this update, an entity should perform its annual or interim goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount, including goodwill. An entity should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit's fair value. However, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. ASU 2017-04 should be applied on a prospective basis and is effective for annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. We adopted ASU 2017-04 effective January 1, 2019, and the adoption of this standard did not have a material impact on the Company's consolidated financial statements.

In June 2018, the FASB issued ASU No. 2018-07, Compensation - Stock Compensation (Topic 718): Improvements to Non-employee Share-Based Payment Accounting ("ASU 2018-07"). ASU 2018-07 primarily expands the scope of Topic 718 to include share-based payment transactions for acquiring goods and services from non-employees. ASU 2018-07 is effective for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. We adopted ASU 2018-07 effective January 1, 2019, and the adoption of this standard did not have a material impact on the Company's consolidated financial statements.

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) ("ASU 2016-02"). Under this new guidance, lessees will be required to recognize assets and liabilities on the balance sheet for the rights and obligations created by all leases with terms of greater than twelve months. The guidance requires qualitative disclosures along with certain specific quantitative disclosures for both lessees and lessors. The FASB issued ASU No. 2018-10, Codification Improvements to Topic 842, Leases, ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, and ASU No. 2019-01, Leases (Topic 842): Codification Improvements, to provide additional guidance for the adoption of Topic 842. ASU 2016-02 and its related amendments are effective for fiscal years beginning after December 15, 2018, with early adoption permitted, and are effective for interim periods in the year of adoption. ASU 2016-02 should be applied using a modified retrospective approach, which requires lessees and lessors to recognize and measure leases at the beginning of the earliest period presented with an option to use certain practical expedients, which we elected to use. We evaluated the impact of this new guidance and reviewed lease or possible lease contracts and evaluated contract related processes. We adopted ASU 2016-02 effective January 1, 2019, and recorded right-of-use assets and liabilities for our real estate operating leases of approximately $1.0 million.

Standards Being Evaluated/Standards Not Yet Adopted

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments ("ASU 2016-13"). ASU 2016-13 requires entities to use a current expected credit loss ("CECL") model, which is a new impairment model based on expected losses rather than incurred losses on financial assets, including accounts receivables, loans, and held-to-maturity debt securities, among others. The model requires financial assets measured at an amortized cost be presented at the net amount

Table of Contents

expected to be collected. The measurement of expected credit losses is based on relevant information about past events, historical experience, current conditions, and reasonable forecasts. ASU 2016-13 is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years.

The FASB also issued subsequent amendments to the initial guidance: ASU 2019-04, Codification Improvements to Topic 326, Financial Instruments - Credit Losses, Topic 815, Derivatives and Hedging, and Topic 825, Financial Instruments ("ASU 2019-04") in April 2019, and ASU 2019-05, Financial Instruments - Credit Losses (Topic 326), Targeted Transition Relief ("ASU 2019-05") in May 2019. ASU 2019-04 provides clarifications and minor improvements related to these topics. ASU 2019-05 provides entities that have certain instruments with an option to irrevocably elect the fair value option in Subtopic 825-10, Financial Instruments - Overall, applied on an instrument-by-instrument basis for eligible instruments, upon adoption of Topic 326. The Company is currently evaluating the impact of adopting this guidance on its consolidated financial statements.

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.

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

Retail Electricity

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

Retail Natural Gas

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

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

Table of Contents



	Reportable Segments
	Three Months Ended June 30, 2019								Three Months Ended June 30, 2018
	Retail Electricity		Retail Natural Gas			Total Reportable Segments			Retail Electricity		Retail Natural Gas			Total Reportable Segments


Primary markets (a)
New England	$	67,905	$	3,152		$	71,057		$	93,926	$	3,228		$	97,154
Mid-Atlantic	54,503		5,334			59,837			67,928		9,419			77,347
Midwest	17,473		4,736			22,209			18,085		5,428			23,513
Southwest	20,895		3,807			24,702			29,508		3,966			33,474
	$	160,776	$	17,029		$	177,805		$	209,447	$	22,041		$	231,488

Customer type
Commercial	$	59,699	$	8,834		$	68,533		$	77,255	$	10,877		$	88,132
Residential	97,419		16,516			113,935			115,110		20,341			135,451
Unbilled revenue (b)	3,658		(8,321		)	(4,663		)	17,082		(9,177		)	7,905
	$	160,776	$	17,029		$	177,805		$	209,447	$	22,041		$	231,488

Customer credit risk
POR	$	110,270	$	7,928		$	118,198		$	144,239	$	12,782		$	157,021
Non-POR	50,506		9,101			59,607			65,208		9,259			74,467
	$	160,776	$	17,029		$	177,805		$	209,447	$	22,041		$	231,488

Table of Contents



	Reportable Segments
	Six Months Ended June 30, 2019									Six Months Ended June 30, 2018
	Retail Electricity			Retail Natural Gas			Total Reportable Segments			Retail Electricity			Retail Natural Gas			Total Reportable Segments


Primary markets (a)
New England	$	144,139		$	11,680		$	155,819		$	195,024		$	12,579		$	207,603
Mid-Atlantic	121,314			26,703			148,017			145,483			35,350			180,833
Midwest	39,580			25,225			64,805			35,920			24,686			60,606
Southwest	37,835			11,483			49,318			53,919			12,528			66,447
	$	342,868		$	75,091		$	417,959		$	430,346		$	85,143		$	515,489

Customer type
Commercial	$	126,934		$	28,701		$	155,635		$	174,148		$	35,176		$	209,324
Residential	222,187			57,611			279,798			263,104			66,070			329,174
Unbilled revenue (b)	(6,253		)	(11,221		)	(17,474		)	(6,906		)	(16,103		)	(23,009		)
	$	342,868		$	75,091		$	417,959		$	430,346		$	85,143		$	515,489

Customer credit risk
POR	$	239,207		$	41,223		$	280,430		$	301,240		$	49,552		$	350,792
Non-POR	103,661			33,868			137,529			129,106			35,591			164,697
	$	342,868		$	75,091		$	417,959		$	430,346		$	85,143		$	515,489

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


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


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


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


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

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

We record gross receipts taxes on a gross basis in retail revenues and retail cost of revenues. During the three months ended June 30, 2019 and 2018, our retail revenues included gross receipts taxes of $0.3 million and $0.4 million, respectively, and our retail cost of revenues include gross receipts taxes of $1.8 million and $2.3 million, respectively. During the six months ended June 30, 2019 and 2018, our retail revenues included gross receipts taxes of $0.8 million and $0.8 million, respectively, and our retail cost of revenues included gross receipts taxes of $4.5 million and $5.1 million, respectively.

4. Acquisitions

Acquisition of HIKO

In March 2018, we entered into a Membership Interest Purchase Agreement under which we acquired all of the membership interests of HIKO Energy, LLC ("HIKO"), a New York limited liability company, for a total purchase price of $6.0 million in cash, plus working capital. At the time of acquisition, HIKO had a total of approximately

Table of Contents

29,000 RCEs located in 42 markets in seven states. The acquisition was accounted for under the acquisition method. Our preliminary allocation of the purchase price was based upon the estimated fair value of the tangible and identified intangible assets acquired and liabilities assumed in the acquisition. The allocation of the purchase consideration is as follows (in thousands):



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

Acquisition from Related Parties

In March 2018, we entered into an asset purchase agreement with an affiliate pursuant to which we agreed to acquire up to 50,000 RCEs for a cash purchase price of $250 for each RCE, or up to $12.5 million in the aggregate. These customers began transferring after April 1, 2018 and are located in 24 markets in eight states. For the year ended December 31, 2018, we paid $8.8 million under the terms of the purchase agreement for approximately 35,000 RCEs. We do not anticipate any additional customer transfers or consideration will be paid on this transaction. The acquisition was treated as a transfer of assets between entities under common control, and accordingly, the assets were recorded at our affiliate's historical value at the date of transfer, which was $1.7 million. The transaction resulted in $7.1 million recorded in equity as a net distribution to affiliate as of December 31, 2018. Of the $8.8 million paid to our affiliate, $1.7 million was an investing cash outflow and the remaining $7.1 million was deemed a distribution to our non-controlling interest and classified as financing activity.

Acquisitions of Customer Books

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

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

5. Equity

Non-controlling Interest

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

Table of Contents



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

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



	Three Months Ended June 30,					Six Months Ended June 30,
	2019			2018		2019			2018

Net (loss) income allocated to non-controlling interest	$	(18,888	)	$	15,523	$	(17,895	)	$	(15,586	)
Income tax (benefit) expense allocated to non-controlling interest	(519		)	381		(1,489		)	(2		)
Net (loss) income attributable to non-controlling interest	$	(18,369	)	$	15,142	$	(16,406	)	$	(15,584	)

Class A Common Stock and Class B Common Stock

Holders of the Company's Class A common stock and Class B common stock vote together as a single class on all matters presented to our stockholders for their vote or approval, except as otherwise required by applicable law or by our certificate of incorporation.

Dividends declared for the Company's Class A common stock are reported as a reduction of retained earnings, or a reduction of additional paid in capital to the extent retained earnings are exhausted. During the six months ended June 30, 2019, we paid $5.2 million in dividends to the holders of the Company's Class A common stock.

In order to pay our stated dividends to holders of our Class A common stock, our subsidiary, Spark HoldCo is required to make corresponding distributions to holders of its units, including those holders that own our Class B common stock (our non-controlling interest holder). As a result, during the six months ended June 30, 2019, Spark HoldCo made corresponding distributions of $7.5 million to our non-controlling interest holders.

Earnings Per Share

Basic earnings per share (“EPS”) is computed by dividing net income attributable to stockholders (the numerator) by the weighted-average number of Class A common shares outstanding for the period (the denominator). Class B common shares are not included in the calculation of basic earnings per share because they are not participating securities and have no economic interests. Diluted earnings per share is similarly calculated except that the denominator is increased by potentially dilutive securities.

Table of Contents

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



	Three Months Ended June 30,					Six Months Ended June 30,
	2019			2018		2019			2018
Net (loss) income attributable to Spark Energy, Inc. stockholders	$	(7,115	)	$	8,785	$	(6,333	)	$	(2,320	)
Less: Dividend on Series A preferred stock	2,027			2,027		4,054			4,054
Net (loss) income attributable to stockholders of Class A common stock	$	(9,142	)	$	6,758	$	(10,387	)	$	(6,374	)

Basic weighted average Class A common shares outstanding	14,246			13,229		14,191			13,183
Basic (loss) income per share attributable to stockholders	$	(0.64	)	$	0.51	$	(0.73	)	$	(0.48	)

Net (loss) income attributable to stockholders of Class A common stock	$	(9,142	)	$	6,758	$	(10,387	)	$	(6,374	)
Effect of conversion of Class B common stock to shares of Class A common stock	(16,557		)	—		(15,242		)	(11,601		)
Diluted net (loss) income attributable to stockholders of Class A common stock	$	(25,699	)	$	6,758	$	(25,629	)	$	(17,975	)

Basic weighted average Class A common shares outstanding	14,246			13,229		14,191			13,183
Effect of dilutive Class B common stock	20,800			—		20,800			21,485
Effect of dilutive restricted stock units	—			17		—			—
Diluted weighted average shares outstanding	35,046			13,246		34,991			34,668

Diluted (loss) income per share attributable to stockholders	$	(0.73	)	$	0.51	$	(0.73	)	$	(0.52	)

The computation of diluted earnings per share for the three and six months ended June 30, 2019 excludes 0.8 million restricted stock units 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, 2019 and December 31, 2018 (in thousands):

Table of Contents



	June 30, 2019		December 31, 2018
Assets
Current assets:
Cash and cash equivalents	$	27,486	$	36,724
Accounts receivable	103,680		150,866
Other current assets	66,726		92,963
Total current assets	197,892		280,553
Non-current assets:
Goodwill	120,343		120,343
Other assets	40,468		47,159
Total non-current assets	160,811		167,502
Total Assets	$	358,703	$	448,055

Liabilities
Current liabilities:
Accounts payable and accrued liabilities	$	72,251	$	79,692
Contingent consideration	1,328		1,328
Other current liabilities	54,839		59,330
Total current liabilities	128,418		140,350
Long-term liabilities:
Long-term portion of Senior Credit Facility	94,000		129,500
Subordinated debt — affiliate	—		10,000
Other long-term liabilities	4,838		319
Total long-term liabilities	98,838		139,819
Total Liabilities	$	227,256	$	280,169

6. Preferred Stock

During the year ended December 31, 2018, we issued an aggregate of 2,917 shares of Series A Preferred Stock under an at-the-market issuance sales agreement (the "ATM Agreement"). We received net proceeds of $0.1 million and paid compensation to the sales agent of less than $0.1 million with respect to these sales.

In January 2018, we issued 2,000,000 shares of Series A Preferred Stock, plus accumulated and unpaid dividends, at a price to the public of $25.25 per share. The Company received approximately $48.9 million ($24.45 per share) in net proceeds from the offering, after deducting underwriting discounts and commissions and a structuring fee. Offering expenses of $0.5 million were recorded as a reduction to the carrying value of the Series A Preferred Stock.

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

Holders of the Series A Preferred Stock have no voting rights, except in specific circumstances of delisting or in the case the dividends are in arrears as specified in the Series A Preferred Stock Certificate of Designations. The Series A Preferred Stock accrue dividends at an annual percentage rate of 8.75%, and the liquidation preference provisions of the Series A Preferred Stock are considered contingent redemption provisions because there are rights granted to

Table of Contents

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, 2019, we paid $2.0 million and $4.0 million, respectively, in dividends to holders of the Series A Preferred Stock. As of June 30, 2019, we had accrued $2.0 million related to dividends to holders of the Series A Preferred Stock. This dividend was paid on July 15, 2019.

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



	(in thousands)
Balance at December 31, 2018	$	90,758
Accumulated dividends on Series A Preferred Stock	—
Repurchase of Series A Preferred Stock	(109		)
Balance at June 30, 2019	$	90,649

7. Derivative Instruments

We are exposed to the impact of market fluctuations in the price of electricity and natural gas, basis differences in the price of natural gas, storage charges, 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, 2019 and December 31, 2018, we had paid $0.8 million and zero, respectively, in collateral. The specific types of derivative instruments we may execute to manage the commodity price risk include the following:


•	Forward contracts, which commit us to purchase or sell energy commodities in the future;


•	Futures contracts, which are exchange-traded standardized commitments to purchase or sell a commodity or financial instrument;


•	Swap agreements, which require payments to or from counterparties based upon the differential between two prices for a predetermined notional quantity; and


•	Option contracts, which convey to the option holder the right but not the obligation to purchase or sell a commodity.

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


•	Forward electricity and natural gas purchase contracts for retail customer load;


•	Renewable energy credits; and


•	Natural gas transportation contracts and storage agreements.

Table of Contents

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, 2019	December 31, 2018
Natural Gas	MMBtu	5,268	8,176
Natural Gas Basis	MMBtu	70	115
Electricity	MWh	7,049	6,781

Trading



Commodity	Notional	June 30, 2019	December 31, 2018
Natural Gas	MMBtu	459	188
Natural Gas Basis	MMBtu	—	(380	)

(Losses) Gains on Derivative Instruments

(Losses) gains 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,
	2019			2018
(Loss) gain on non-trading derivatives, net	$	(35,466	)	$	16,601
Gain on trading derivatives, net	10			453
(Loss) gain on derivatives, net	(35,456		)	17,054
Current period settlements on non-trading derivatives ⁽¹⁾	12,788			8,793
Current period settlements on trading derivatives	(19		)	(1		)
Total current period settlements on derivatives	$	12,769		$	8,792

(1) Excludes settlements of less than $0.1 million and $0.4 million, respectively, for the three months ended June 30, 2019 and 2018 related to non-trading derivative liabilities assumed in various acquisitions.



	Six Months Ended June 30,
	2019			2018
Loss on non-trading derivatives, net	$	(55,269	)	$	(20,111	)
Gain on trading derivatives, net	272			623
Loss on derivatives, net	(54,997		)	(19,488		)
Current period settlements on non-trading derivatives ^{(1) (2)}	20,913			(6,089		)
Current period settlements on trading derivatives	(119		)	(656		)
Total current period settlements on derivatives	$	20,794		$	(6,745	)

(1) Excludes settlements of less than $0.1 million and $(0.4) million, respectively, for the six months ended June 30, 2019 and 2018 related to non-trading derivative liabilities assumed in various acquisitions.

(2) Excludes settlements of $(0.9) million and zero, respectively, for the six months ended June 30, 2019 and 2018 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.

Table of Contents

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, 2019
Description	Gross Assets		Gross Amounts Offset			Net Assets		Cash Collateral Offset		Net Amount Presented
Non-trading commodity derivatives	$	4,213	$	(4,193	)	$	20	$	—	$	20
Trading commodity derivatives	34		(2		)	32		—		32
Total Current Derivative Assets	4,247		(4,195		)	52		—		52
Non-trading commodity derivatives	581		(581		)	—		—		—
Trading commodity derivatives	—		—			—		—		—
Total Non-current Derivative Assets	581		(581		)	—		—		—
Total Derivative Assets	$	4,828	$	(4,776	)	$	52	$	—	$	52



	June 30, 2019
Description	Gross Liabilities			Gross Amounts Offset		Net Liabilities			Cash Collateral Offset		Net Amount Presented
Non-trading commodity derivatives	$	(42,293	)	$	15,695	$	(26,598	)	$	750	$	(25,848	)
Trading commodity derivatives	(57		)	57		—			—		—
Total Current Derivative Liabilities	(42,350		)	15,752		(26,598		)	750		(25,848		)
Non-trading commodity derivatives	(6,527		)	1,949		(4,578		)	—		(4,578		)
Trading commodity derivatives	(13		)	13		—			—		—
Total Non-current Derivative Liabilities	(6,540		)	1,962		(4,578		)	—		(4,578		)
Total Derivative Liabilities	$	(48,890	)	$	17,714	$	(31,176	)	$	750	$	(30,426	)



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

Table of Contents



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

8. Property and Equipment

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



	Estimated useful lives (years)	June 30, 2019			December 31, 2018
Information technology	2 – 5	$	21,423		$	34,611
Leasehold improvements	2 – 5	—			4,568
Furniture and fixtures	2 – 5	1,850			1,964
Building improvements	2 – 5	—			268
Total		23,273			41,411
Accumulated depreciation		(19,698		)	(37,045		)
Property and equipment—net		$	3,575		$	4,366

Information technology assets include software and consultant time used in the application, development and implementation of various systems including customer billing and resource management systems. As of each of June 30, 2019 and December 31, 2018, information technology includes $0.3 million of costs associated with assets not yet placed into service.

Depreciation expense recorded in the condensed consolidated statements of operations was $0.5 million and $0.9 million for the three months ended June 30, 2019 and 2018, respectively, and $1.2 million and $2.1 million for the six months ended June 30, 2019 and 2018, respectively.

Table of Contents

9. Intangible Assets

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



	June 30, 2019			December 31, 2018
Goodwill	$	120,343		$	120,343
Customer relationships—Acquired
Cost	$	84,248		$	99,402
Accumulated amortization	(55,336		)	(63,208		)
Customer relationships—Acquired & Non-Compete Agreements, net	$	28,912		$	36,194
Customer relationships—Other
Cost	$	17,885		$	16,155
Accumulated amortization	(7,520		)	(9,290		)
Customer relationships—Other, net	$	10,365		$	6,865
Trademarks
Cost	$	9,770		$	9,770
Accumulated amortization	(3,373		)	(2,483		)
Trademarks, net	$	6,397		$	7,287

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



	Goodwill		Customer Relationships— Acquired & Non-Compete Agreements			Customer Relationships— Other			Trademarks
Balance at December 31, 2018	$	120,343	$	36,194		$	6,865		$	7,287
Additions	—		—			6,913			—
Amortization	—		(7,282		)	(3,413		)	(890		)
Balance at June 30, 2019	$	120,343	$	28,912		$	10,365		$	6,397

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



Year ending December 31,
2019 (remaining six months)	$	8,592
2020	14,561
2021	12,987
2022	6,038
2023	450
> 5 years	3,046
Total	$	45,674

Table of Contents

10. Debt

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



	June 30, 2019		December 31, 2018
Current:
Note Payable—Verde Notes	$	—	$	6,936
Total current portion of debt	—		6,936
Long-term debt:
Senior Credit Facility ^{(1) (2)}	94,000		129,500
Subordinated Debt	—		10,000
Total long-term debt	94,000		139,500
Total debt	$	94,000	$	146,436

(1) As of June 30, 2019 and December 31, 2018, the weighted average interest rate on the Senior Credit Facility was 5.47% and 5.48%, respectively.

(2) As of June 30, 2019 and December 31, 2018, we had $41.7 million and $49.4 million in letters of credit issued, respectively.

Capitalized financing costs associated with our Senior Credit Facility were $1.9 million and $1.4 million as of June 30, 2019 and December 31, 2018, respectively. Of these amounts, $1.0 million and $1.0 million are recorded in other current assets, and $0.9 million and $0.4 million are recorded in other non-current assets in the condensed consolidated balance sheets as of June 30, 2019 and December 31, 2018, respectively.

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Senior Credit Facility	$	1,179	$	1,208	$	2,621	$	2,472
Subordinated debt	—		6		4		7
Note Payable—Verde Notes	89		363		230		690
Letters of credit fees and commitment fees	490		422		858		780
Amortization of deferred financing costs	237		317		505		612
Interest Expense	$	1,995	$	2,316	$	4,218	$	4,561

Senior Credit Facility

The Company, as guarantor, and Spark HoldCo (the “Borrower” and, together with each subsidiary of Spark HoldCo (“Co-Borrowers”)), maintain a senior secured borrowing base credit facility (as amended, “Senior Credit Facility”) that allows us to borrow on a revolving basis and has a maximum borrowing capacity of $217.5 million as of June 30, 2019. Subject to applicable sublimits and terms of the Senior Credit Facility, as amended, borrowings are available for the issuance of letters of credit (“Letters of Credit”), working capital and general purpose revolving credit loans (“Working Capital Loans”), and bridge loans (“Bridge Loans”) for the purpose of partial funding for acquisitions. Borrowings under the Senior Credit Facility may be used to pay fees and expenses in connection with the Senior Credit Facility, finance ongoing working capital requirements and general corporate purpose requirements of the Co-Borrowers, to provide partial funding for acquisitions, as allowed under terms of the Senior Credit Facility, and to make open market purchases of our Class A common stock and Series A Preferred Stock. As of June 30, 2019, we had $94.0 million outstanding under the Senior Credit Facility, as well as $41.7 million of outstanding letters of credit.

On June 13, 2019, the Company entered into the Third Amendment to its Senior Credit Facility, which, among other things, extended the expiration date and revised the Fixed Charge Coverage Ratio. The Senior Credit Facility will mature on May 19, 2021, and all amounts outstanding thereunder will be payable on the maturity date. Borrowings

Table of Contents

under the Bridge Loan sublimit, if any, will be repaid 25% per year on a quarterly basis (or 6.25% per quarter), with the remainder due at maturity. As of June 30, 2019, there were no Bridge Loans outstanding.

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

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

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

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

•

Minimum Fixed Charge Coverage Ratio. We must maintain a minimum fixed charge coverage ratio of not less than 1.25 to 1.00. The Fixed Charge Coverage Ratio is defined as the ratio of (a) Adjusted EBITDA to (b) the sum of consolidated (with respect to the Company and the Co-Borrowers) interest expense (other than interest paid-in-kind in respect of certain subordinated debt but including interest in respect of that certain promissory note made by CenStar Energy Corp. ("CenStar") in connection with the permitted acquisition from Verde Energy USA Holdings, LLC), letter of credit fees, commitment fees, acquisition earn-out payments (excluding earnout payments funded with proceeds from newly issued preferred or common equity), distributions, the aggregate amount of repurchases of our Class A common stock, Series A Preferred Stock, or commitments for such purchases, taxes and scheduled amortization payments. The Senior Credit Facility permits, upon satisfaction of a Step-Down Condition, for the Company to elect to reduce the minimum required Fixed Charge Coverage Ratio from 1.25 to 1.00 to 1.10 to 1.00 for a period of one year. A Step-Down Condition is defined as the consummation by the Company of share buybacks of its Series A Preferred Stock under the Repurchase Program with an aggregate purchase price not less than $10.0 million.


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

•

Maximum Senior Secured Leverage Ratio. We must maintain a Senior Secured Leverage Ratio of no more than 1.85 to 1.00. The Senior Secured Leverage Ratio is defined as the ratio of (a) all indebtedness of the loan parties on a consolidated basis that is secured by a lien on any property of any loan party (including the effective amount of all loans then outstanding under the Senior Credit Facility) plus 50% of the effective amount of letter of credit obligations attributable to performance standby letters of credit to (b) Adjusted EBITDA.

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

Table of Contents

for credit facilities of this type. As of June 30, 2019, we are in compliance with our various covenants under the Senior Credit Facility.

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

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

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

Subordinated Debt Facility

On June 13, 2019, the Company entered into an Amended and Restated Subordinated Promissory Note in the principal amount of up to $25.0 million (the “Subordinated Debt Facility”), by and among the Company, Spark HoldCo and Retailco. The Subordinated Debt Facility amended and restated the Subordinated Promissory Note, dated as of December 27, 2016, by and among the Company, Spark HoldCo and Retailco, solely to extend the expiration date from July 1, 2020 to December 31, 2021.

The Subordinated Debt Facility allows us to draw advances in increments of no less than $1.0 million per advance up to the maximum principal amount of the Subordinated Debt Facility. Advances thereunder accrue interest at 5% per annum from the date of the advance. We have the right to capitalize interest payments under the Subordinated Debt Facility. The Subordinated Debt Facility is subordinated in certain respects to our Senior Credit Facility pursuant to a subordination agreement. We may pay interest and prepay principal on the Subordinated Debt Facility so long as we are in compliance with the covenants under our Senior Credit Facility, are not in default under the Senior Credit Facility and have minimum availability of $5.0 million under the borrowing base under the Senior Credit Facility. Payment of principal and interest under the Subordinated Debt Facility is accelerated upon the occurrence of certain change of control or sale transactions.

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

Verde Notes

In connection with the acquisition of the Verde Companies in July 2017, we entered into a promissory note in the aggregate principal amount of $20.0 million (the "Verde Promissory Note"). The Verde Promissory Note required repayment in eighteen monthly installments beginning in August 2017, and accrued interest at 5% per annum from

Table of Contents

the date of issuance. The Verde Promissory Note, including principal and interest, was unsecured, but was guaranteed by us. In January 2018, in connection with the Earnout Termination Agreement (defined below), we issued to the seller of the Verde Companies an amended and restated promissory note (the “Amended and Restated Verde Promissory Note”), which amended and restated the Verde Promissory Note. The Amended and Restated Verde Promissory Note matured in January 2019, and bore interest at a rate of 9% per annum. Principal and interest were payable monthly on the first day of each month, with a portion of each payment going into an escrow account, which serves as security for certain indemnification claims and obligations under the Verde purchase agreement. As of June 30, 2019 and December 31, 2018, there was zero and $1.0 million outstanding, respectively, under the Amended and Restated Verde Promissory Note.

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

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

11. Fair Value Measurements

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

We apply fair value measurements to our commodity derivative instruments and contingent payment arrangements based on the following fair value hierarchy, which prioritizes the inputs to the valuation techniques used to measure fair value into three broad levels:


•	Level 1—Quoted prices in active markets for identical assets and liabilities. Instruments categorized in Level 1 primarily consist of financial instruments such as exchange-traded derivative instruments.

•

Level 2—Inputs other than quoted prices recorded in Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 primarily include non-exchange traded derivatives such as over-the-counter commodity forwards and swaps and options.


•	Level 3—Unobservable inputs for the asset or liability, including situations where there is little, if any, observable market activity for the asset or liability. The Level 3 category includes estimated earnout obligations related to our acquisitions.

As the fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3), the Company maximizes the use of observable inputs and minimizes the use

Table of Contents

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, 2019
Non-trading commodity derivative assets	$	—		$	20		$	—		$	20
Trading commodity derivative assets	—			32			—			32
Total commodity derivative assets	$	—		$	52		$	—		$	52
Non-trading commodity derivative liabilities	$	(1,415	)	$	(29,011	)	$	—		$	(30,426	)
Trading commodity derivative liabilities	—			—			—			—
Total commodity derivative liabilities	$	(1,415	)	$	(29,011	)	$	—		$	(30,426	)
Contingent payment arrangement	$	—		$	—		$	(1,328	)	$	(1,328	)



	Level 1			Level 2			Level 3			Total
December 31, 2018
Non-trading commodity derivative assets	$	104		$	9,821		$	—		$	9,925
Trading commodity derivative assets	44			596			—			640
Total commodity derivative assets	$	148		$	10,417		$	—		$	10,565
Non-trading commodity derivative liabilities	$	(352	)	$	(5,685	)	$	—		$	(6,037	)
Trading commodity derivative liabilities	(75		)	(472		)	—			(547		)
Total commodity derivative liabilities	$	(427	)	$	(6,157	)	$	—		$	(6,584	)
Contingent payment arrangement	$	—		$	—		$	(1,328	)	$	(1,328	)

We had no transfers of assets or liabilities between any of the above levels during the six months ended June 30, 2019 and the year ended December 31, 2018.

Our derivative contracts include exchange-traded contracts valued utilizing readily available quoted market prices and non-exchange-traded contracts valued using market price quotations available through brokers or over-the-counter and on-line exchanges. In addition, in determining the fair value of our derivative contracts, we apply a credit risk valuation adjustment to reflect credit risk, which is calculated based on our or the counterparty’s historical credit risks. As of June 30, 2019 and December 31, 2018, the credit risk valuation adjustment was less than $0.1 million. We deemed it immaterial and no adjustment was recorded in the financial statements.

The contingent payment arrangements referred to above reflect estimated earnout obligations incurred in relation to our acquisition of the Major Energy Companies in 2016.

Contingent Payment Arrangements

The following table presents a roll forward of our contingent payment arrangements, which are measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the six months ended June 30, 2019.

Table of Contents



	Major Earnout and Stock Earnout
Fair Value at December 31, 2018	$	1,328
Change in fair value of contingent consideration, net	—
Accretion of contingent earnout consideration (included within interest expense)	—
Payments and settlements	—
Fair Value at June 30, 2019	$	1,328

Other Financial Instruments

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

12. Income Taxes

Income Taxes

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

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

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

We periodically assess whether it is more likely than not that we will generate sufficient taxable income to realize our deferred income tax assets. In making this determination, we consider all available positive and negative evidence and make certain assumptions. We consider, among other things, our deferred tax liabilities, the overall business environment, our historical earnings and losses, current industry trends, and our outlook for future years. We believe it is more likely than not that our deferred tax assets will be utilized, and accordingly have not recorded a valuation allowance on these assets.

As of June 30, 2019, we had a net deferred tax asset of approximately $15.6 million related to the original step up in tax basis resulting from the initial purchase of Spark HoldCo units from NuDevco Retail and NuDevco Retail

Table of Contents

Holdings (predecessor to Retailco) in connection with our initial public offering. In addition, as of June 30, 2019, we had a total liability of $27.6 million for the effect of the Tax Receivable Agreement ("TRA") liability, with approximately $11.2 million classified as short-term liability and the remainder as long-term. On July 11, 2019, the TRA was terminated. See Note 14 "Transactions with Affiliates" and Note 16 "Subsequent Events" for further discussion of the TRA and TRA termination.

The effective U.S. federal and state income tax rate for the six months ended June 30, 2019 and 2018 is 13.5% and 15.2%, respectively. The effective tax rate for the six months ended June 30, 2019 reflects the corporate U.S. federal statutory tax rate of 21%, applied to the mix of earnings between corporate and partnership income, offset by the tax effect of Series A Preferred Stock dividends. Total income tax expense for the six months ended June 30, 2019 differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income primarily due to state taxes and the impact of permanent differences between book and taxable income, most notably the income attributable to non-controlling interests. The effective tax rate includes a rate benefit attributable to the fact that Spark HoldCo operates as a limited liability company treated as a partnership for federal and state income tax purposes and is not subject to federal and state income taxes. Accordingly, the portion of earnings attributable to non-controlling interest is subject to tax when reported as a component of the non-controlling interest’s taxable income.

13. Commitments and Contingencies

From time to time, we may be involved in legal, tax, regulatory and other proceedings in the ordinary course of business. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.

Legal Proceedings

Below is a summary of our currently pending material legal proceedings. We are subject to other lawsuits and claims arising in the ordinary course of our business. This litigation is in various stages and is subject to substantial uncertainties concerning the outcome of material factual and legal issues. Accordingly, we cannot currently predict the manner and timing of the resolution of this litigation or estimate a range of possible losses or a minimum loss that could result from an adverse verdict in a potential lawsuit. While the lawsuits and claims are asserted for amounts that may be material should an unfavorable outcome occur, management does not currently expect that any currently pending matters will have a material adverse effect on our financial position or results of operations.

Katherine Veilleux, et. al. v. Electricity Maine LLC, Provider Power, LLC, Spark HoldCo, LLC, Kevin Dean, and Emile Clavet is a purported class action lawsuit filed on November 18, 2016 in the United States District Court of Maine, alleging that Electricity Maine, LLC ("Electricity Maine"), an entity acquired by Spark Holdco in mid-2016, enrolled and re-enrolled customers through fraudulent and misleading advertising, promotions, and other communications prior to and following the acquisition. Plaintiffs allege claims under RICO, the Maine Unfair Trade Practice Act, civil conspiracy, fraudulent misrepresentation, unjust enrichment and breach of contract. Plaintiffs seek damages for themselves and the purported class, rescission of contracts with Electricity Maine, injunctive relief, restitution, and attorney’s fees. Discovery is ongoing in this matter. Spark HoldCo and Electricity Maine intend to vigorously defend this matter and the allegations asserted therein, including the request to certify a class. Electricity Maine and Spark HoldCo have also filed a motion to compel arbitration of certain Plaintiffs’ claims as some of the applicable Terms of Service contain an arbitration provision and class action waiver. The parties are currently in settlement negotiations. In a parallel declaratory judgment action, the Company won a favorable verdict against Zurich, one of Electricity Maine’s insurance carriers, and Zurich has been ordered to pay certain costs associated with this claim that the Company believes will offset any total losses to the Company. The Company also believes indemnity offsets with the former sellers of Electricity Maine will be applicable to any settlement, but the Company may have some additional liability beyond the existing indemnity and insurance coverage to resolve this matter. Given the early stages of the settlement discussions, we cannot predict the amount of additional liability of this case at this time, but we do not believe that the potential additional liability, if any, will have a material adverse effect on our financial position.

Table of Contents

Gillis et al. v. Respond Power, LLC is a purported class action lawsuit that was originally filed on May 21, 2014 in the Philadelphia Court of Common Pleas but was later removed to the United States District Court for the Eastern District of Pennsylvania. On September 15, 2014, the plaintiffs filed an amended class action complaint seeking a declaratory judgment that the disclosure statement contained in Respond Power, LLC’s variable rate contracts with Pennsylvania consumers limited the variable rate that could be charged to no more than the monthly rate charged by the consumers’ local utility company and alleged claims of deceptive conduct in violation of Pennsylvania Unfair Trade Practices and Consumer Protection Act, negligent misrepresentation, fraudulent concealment, and breach of contract and of the covenant of good faith and fair dealing by charging rates above the utility. The amount of damages sought is not specified. By order dated August 31, 2015, the district court denied class certification. The plaintiffs appealed the district court’s denial of class certification to the United States Court of Appeals for the Third Circuit and that court vacated the district court’s denial of class certification and remanded the matter to the district court for further proceedings. On July 16, 2018, the district court granted Respond Power LLC's motion to dismiss the Plaintiff’s class action claims. Plaintiffs filed their notice of appeal to the Third Circuit Court on August 7, 2018. The Third Circuit has declined to hear oral arguments on this matter but has not yet ruled on this appeal. The Company believes it has full indemnity coverage for any actual exposure in this case at this time.

Jurich v. Verde Energy USA, Inc., is a class action originally filed on March 3, 2015 in the United States District Court for the District of Connecticut and subsequently re-filed on October 8, 2015 in the Superior Court of Judicial District of Hartford, State of Connecticut. The Amended Complaint asserts that the Verde Companies charged rates in violation of its contracts with Connecticut customers and alleges (i) violation of the Connecticut Unfair Trade Practices Act, Conn. Gen. Stat. §§ 42-110a et seq., and (ii) breach of the covenant of good faith and fair dealing. Plaintiffs are seeking unspecified actual and punitive damages for the class and injunctive relief. As part of an agreement in connection with the acquisition of the Verde Companies, the original owners of the Verde Companies are handling this matter. The parties have reached a confidential settlement in this matter, which is pending court approval. The Company believes it has full indemnity coverage, net of tax benefit, for any actual exposure in this case at this time.

Richardson et. al. v. Verde Energy USA, Inc. is a purported class action filed on November 25, 2015 in the United States District Court for the Eastern District of Pennsylvania alleging that the Verde Companies violated the Telephone Consumer Protection Act ("TCPA") by placing marketing calls using an automatic telephone dialing system ("ATDS") or a prerecorded voice to the purported class members’ cellular phones without prior express consent and by continuing to make such calls after receiving requests for the calls to cease. Following discovery and dispositive motions, the Verde Companies received a favorable ruling on summary judgment with the court agreeing with the Verde Companies that the call system used in this case was not an ATDS as defined by the TCPA. Plaintiffs subsequently amended their petition eliminating theirs ATDS claim and including a class based on failure to comply with the National Do Not Call registry. As part of an agreement in connection with the acquisition of the Verde Companies, the original owners of the Verde Companies are handling this matter. The parties have reached a confidential settlement in this matter which is pending court approval. The Company believes it has full indemnity coverage, net of tax benefit, for the settlement exposure in this case.

Saul Horowitz, as Sellers’ Representative for the former owners of the Major Energy Companies v. National Gas & Electric, LLC ("NG&E") and Spark Energy, Inc. ("Spark"), is a lawsuit filed on October 17, 2017 in the United States District Court for the Southern District of New York asserting claims of fraudulent inducement against NG&E, breach of contract against NG&E and Spark, and tortious interference with contract against Spark related to the membership interest purchase agreement, subsequent dropdown, and associated earnout agreements with the Major Energy Companies' former owners. The relief sought includes unspecified compensatory and punitive damages, prejudgment and post judgment interest, and attorneys’ fees. On September 24, 2018, the court granted our motion to dismiss in part and dismissed plaintiffs’ fraudulent inducement claims but allowed the tortious interference claims to remain as well as the claims for consequential damages and punitive damages. NG&E and Spark filed their affirmative defenses and answer to the remaining claims on October 15, 2018. Discovery is ongoing. On January 14, 2019, the plaintiff filed a Motion for Partial Summary Judgment, which was subsequently denied by the Court on May 8, 2019. On March 25, 2019, Spark and NG&E filed a Motion for Sanctions in

Table of Contents

connection with deletion of electronically stored data by plaintiff Saul Horowitz and co-seller Mark Wiederman after receiving a litigation hold notice, which the Court granted in part on May 8, 2019, including an award of attorney’s fees and costs to Spark and NG&E in connection with the Motion for Sanctions. On June 7, 2019, the parties jointly filed a letter agreement with the Court confirming plaintiff’s payment of fees and costs, including costs associated with forensic analysis, in the amount of less than $0.1 million to Spark and NG&E in connection with the Court’s ruling on the Motion for Sanctions. This case is currently set for a final pre-trial conference on December 16, 2019 and for trial to commence on January 13, 2020. Spark and NG&E deny the allegations asserted by plaintiffs and intend to vigorously defend this matter. Given the ongoing discovery and current stage of this matter, we cannot predict the outcome or consequences of this case at this time.

Albrecht v. Oasis Power, LLC, is a putative nationwide class action that was filed on February 12, 2018 in the United States District Court for the Northern District of Illinois, alleging that Oasis made illegal prerecorded telemarketing calls, including auto-dialed calls, to consumers’ mobile phones, in violation of the Telephone Consumer Protection Act ("TCPA") and the Illinois Automatic Telephone Dialers Act ("ATDA"). Plaintiff seeks an injunction requiring Oasis to cease all unsolicited calling activities, an award of statutory and trebled damages under the TCPA and the ATDA, as well as costs and attorney’s fees. Oasis filed its motion to dismiss on April 16, 2018 and a renewed motion to dismiss on May 4, 2018. The parties have reached a confidential class settlement which is pending court approval. The Company has sought indemnity and insurance coverage from two vendors and their carriers that worked for the Company on the telemarketing campaigns at issue.

Regulatory Matters

State of Illinois v. Major Energy Electric Services, LLC is a complaint filed by the Illinois Attorney General for injunctive and other relief against Major Energy Electric Services, LLC ("Major") asserting claims that Major engaged in a pattern and practice of deceptive conduct intended to defraud Illinois consumers through door-to-door and telephone solicitations, in-person solicitations at retail establishments, advertisements on its website and direct mail advertisements to sign up for electricity services. The complaint seeks injunctive relief and monetary damages representing the amounts Illinois consumers have allegedly lost due to fraudulent marketing activities. The Attorney General also requests civil penalties under the Consumer Fraud Act and to revoke Major’s authority to operate in the state. The complaint was filed on April 9, 2018 in the Circuit Court of Cook County, Illinois, County Department, Chancery Division. Major filed its motion to dismiss on July 31, 2018 and the judge denied that motion on October 10, 2018. Major filed a motion for reconsideration on the Court’s ruling on its motion to dismiss, which was denied. The parties are in final settlement negotiations.

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

Table of Contents

PUCO Investigation. Verde Energy USA Ohio, LLC (“Verde Ohio”) is the subject of a formal investigation by the Public Utilities Commission of Ohio (“PUCO”) initiated on April 16, 2019. The investigation asserts that Verde Ohio engaged in misleading and deceptive practices to market and enroll customers as well as allegations of violating several requirements of Ohio’s retail energy supplier regulations. On May 3, 2019, Verde Ohio filed a Motion to Temporarily Suspend the Procedural Schedule and Stay Discovery Pending Negotiation of a Stipulation between the parties. In its Motion, Verde Ohio agreed to a thirty (30) day voluntary marketing and customer enrollment stay in Ohio. Although the Motion was not granted by PUCO, Verde Ohio has continued its voluntary marketing and customer enrollment stay in Ohio in furtherance of settlement negotiations with PUCO Staff. Also on May 3, 2019, PUCO Staff issued a report of its findings following their investigation of Verde Ohio, and filed a corrected version on May 29, 2019, as contemplated in PUCO’s procedural schedule set forth in the April 17th, 2019 PUCO entry in the matter. PUCO has extended the procedural schedule for the filing of direct testimony and the date for the Show Cause Hearing numerous times during this investigation. Verde Ohio and PUCO Staff are in the final stages of settlement negotiations and are nearing a negotiated resolution which would need to be approved by PUCO. While investigations of this nature may be resolved in a manner that allows the retail energy supplier to continue operating in Ohio with stipulations, there can be no assurance that PUCO will not take more severe action.

Indirect Tax Audits

We are undergoing various types of indirect tax audits spanning from years 2013 to 2018 for which we may have additional liabilities arise. These indirect tax audits are at an early stage and subject to substantial uncertainties concerning the outcome of audit findings and corresponding responses.

As of June 30, 2019 and December 31, 2018, we accrued $18.7 million and $0.9 million, respectively, related to litigation and regulatory matters and $0.4 million and $0.6 million, respectively, related to indirect tax audits. The outcome of each of these may result in additional expense.

14. Transactions with Affiliates

Transactions with Affiliates

We enter into transactions with and pay certain costs on behalf of affiliates that are commonly controlled in order to reduce risk, reduce administrative expense, create economies of scale, create strategic alliances and supply goods and services to these related parties. We also sell and purchase natural gas and electricity with affiliates. We present receivables and payables with the same affiliate on a net basis in the condensed consolidated balance sheets as all affiliate activity is with parties under common control. Affiliated transactions include certain services to the affiliated companies associated with employee benefits provided through our benefit plans, insurance plans, leased office space, administrative salaries, due diligence work, recurring management consulting, and accounting, tax, legal, or technology services. Amounts billed are based on the services provided, departmental usage, or headcount, which are considered reasonable by management. As such, the accompanying condensed consolidated financial statements include costs that have been incurred by us and then directly billed or allocated to affiliates, as well as costs that have been incurred by our affiliates and then directly billed or allocated to us, and are recorded net in general and administrative expense on the condensed consolidated statements of operations with a corresponding accounts receivable—affiliates or accounts payable—affiliates, respectively, recorded in the condensed consolidated balance sheets. Transactions with affiliates for sales or purchases of natural gas and electricity are recorded in retail revenues, retail cost of revenues, and net asset optimization revenues in the condensed consolidated statements of operations with a corresponding accounts receivable—affiliate or accounts payable—affiliate are recorded in the condensed consolidated balance sheets.

Master Service Agreement with Retailco Services, LLC

Prior to April 1, 2018, we were a party to a Master Service Agreement with an affiliated company owned by our Founder. The Master Service Agreement provided us with operational support services such as enrollment and renewal transaction services, customer billing and transaction services, electronic payment processing services,

Table of Contents

customer service, and information technology infrastructure and application support services. Effective April 1, 2018, we terminated the agreement, and these operational support services were transferred back to us.

Cost Allocations

Where costs incurred on behalf of the affiliate or us cannot be determined by specific identification for direct billing, the costs are allocated to the affiliated entities or us based on estimates of percentage of departmental usage, wages or headcount. The total net amount direct billed and allocated from affiliates was $0.4 million and $1.5 million for the three months ended June 30, 2019 and 2018, respectively. The total net amount direct billed and allocated from affiliates was $0.4 million and $8.4 million for the six months ended June 30, 2019 and 2018, respectively.

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

Accounts Receivable and Payable—Affiliates

As of June 30, 2019 and December 31, 2018, we had current accounts receivable—affiliates of $3.9 million and $2.6 million, respectively, and current accounts payable—affiliates of $2.5 million and $2.5 million, respectively.

Revenues and Cost of Revenues—Affiliates

Revenues recorded in net asset optimization revenues in the condensed consolidated statements of operations for the three months ended June 30, 2019 and 2018 related to affiliated sales were $0.6 million and $0.4 million, respectively. Revenues recorded in net asset optimization revenues in the condensed consolidated statements of operations for the six months ended June 30, 2019 and 2018 related to affiliated sales were $1.8 million and $1.0 million, respectively.

Cost of revenues recorded in net asset optimization revenues in the condensed consolidated statements of operations for the three months ended June 30, 2019 and 2018 related to affiliated purchases were less than $0.1 million. Cost of revenues recorded in net asset optimization revenues in the condensed consolidated statements of operations for the six months ended June 30, 2019 and 2018 related to affiliated purchases were less than $0.1 million. These amounts are presented as net on the Consolidated Statements of Operations.

Acquisitions from Related Parties

In March 2018, we entered into an asset purchase agreement with an affiliate to acquire up to 50,000 RCEs for a cash purchase price of $250 for each RCE, or up to $12.5 million in the aggregate. A total of $8.8 million was paid in 2018 under the terms of the purchase agreement for approximately 35,000 RCEs, and no further material payments are anticipated. The acquisition was treated as a transfer of assets between entities under common control, and accordingly, the assets were recorded at their historical value at the date of transfer. The transaction resulted in less than $0.1 million and $7.1 million recorded in equity as a net distribution to affiliate as of June 30, 2019 and December 31, 2018, respectively.

Distributions to and Contributions from Affiliates

During the six months ended June 30, 2019 and 2018, we made distributions to affiliates of our Founder of $7.5 million and $7.8 million, respectively, for payments of quarterly distributions on their respective Spark HoldCo

Table of Contents

units. During the six months ended June 30, 2019 and 2018, we also made distributions to these affiliates for gross-up distributions of zero and $11.7 million, respectively, in connection with distributions made between Spark HoldCo and Spark Energy, Inc. for payment of income taxes incurred by us.

Proceeds from Disgorgement of Stockholder Short-swing Profits

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

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

Subordinated Debt Facility

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

Tax Receivable Agreement

Prior to July 11, 2019, we were party to a TRA with affiliates. The TRA was terminated on July 11, 2019. Please see Note 16 "Subsequent Events."

The TRA generally provided for the payment by us to affiliates of 85% of the net cash savings, if any, in U.S. federal, state and local income tax or franchise tax that we realized or would realize (or were deemed to realize in certain circumstances) in future periods as a result of (i) any tax basis increases resulting from the initial purchase by us of Spark HoldCo units from entities owned by our Founder, (ii) any tax basis increases resulting from the exchange of Spark HoldCo units for shares of Class A common stock pursuant to the Exchange Right (or resulting from an exchange of Spark HoldCo units for cash pursuant to the Cash Option) and (iii) any imputed interest deemed to be paid by us as a result of, and additional tax basis arising from, any payments we made under the TRA. We retained the benefit of the remaining 15% of these tax savings. See Note 12 "Income Taxes" for further discussion.

In certain circumstances, we could defer or partially defer any payment due (a “TRA Payment”) to the holders of rights under the TRA for a five year period that would end September 30, 2019. Deferral of payment was required to the extent that Spark HoldCo did not generate sufficient Cash Available for Distribution (as defined below) during the four-quarter period ending September 30th of the applicable year in which the TRA Payment was to be made in an amount that equaled or exceeded 130% (the “TRA Coverage Ratio”) of the Total Distributions (as defined below) paid in such four-quarter period by Spark HoldCo. For purposes of computing the TRA Coverage Ratio:


•	“Cash Available for Distribution” was generally defined as the Adjusted EBITDA of Spark HoldCo for the applicable period, less (i) cash interest paid by Spark HoldCo, (ii) capital expenditures of Spark HoldCo (exclusive of customer acquisition costs) and (iii) any taxes payable by Spark HoldCo; and


•	“Total Distributions” were defined as the aggregate distributions necessary to cause us to receive distributions of cash equal to (i) the targeted quarterly distribution we intended to pay to holders of our

Table of Contents

Class A common stock and Series A Preferred Stock payable during the applicable four-quarter period, plus (ii) the estimated taxes payable by us during such four-quarter period, plus (iii) the expected TRA Payment payable during the calendar year for which the TRA Coverage Ratio is being tested.

At the end of the deferral period, we were obligated to pay any outstanding deferred TRA Payments to the extent such deferred TRA Payments did not exceed (i) the lesser of our proportionate share of aggregate Cash Available for Distribution of Spark HoldCo during the five-year deferral period or the cash distributions actually received by us during the five-year deferral period, reduced by (ii) the sum of (a) the aggregate target quarterly dividends (which, for the purposes of the TRA, was $0.18125 per Class A common stock share and $0.546875 per Series A Preferred Stock share per quarter) during the five-year deferral period, (b) our estimated taxes during the five-year deferral period, and (c) all prior TRA Payments and (d) if with respect to the quarterly period during which the deferred TRA Payment is otherwise paid or payable, Spark HoldCo had or reasonably determined it would have amounts necessary to cause us to receive distributions of cash equal to the target quarterly distribution payable during that quarterly period. Any portion of the deferred TRA Payments not payable due to these limitations would no longer be payable.

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

As of June 30, 2019 and December 31, 2018, we had a total liability related to the TRA of $27.6 million, of which $11.2 million and $1.7 million was classified as current liabilities at June 30, 2019 and December 31, 2018, respectively.

15. Segment Reporting

Our determination of reportable business segments considers the strategic operating units under which we make financial decisions, allocate resources and assess performance of our business. Our reportable business segments are retail electricity and retail natural gas. The retail electricity segment consists of electricity sales and transmission to residential and commercial customers. The retail natural gas segment consists of natural gas sales to, and natural gas transportation and distribution for, residential and commercial customers. Corporate and other consists of expenses and assets of the retail electricity and natural gas segments that are managed at a consolidated level such as general and administrative expenses. Asset optimization activities are also included in Corporate and other.

For the three months ended June 30, 2019 and 2018, we recorded asset optimization revenues of $12.7 million and $32.7 million and asset optimization cost of revenues of $12.8 million and $31.9 million, respectively, which are presented on a net basis in asset optimization (expense) revenues. For the six months ended June 30, 2019 and 2018, we recorded asset optimization revenues of $36.1 million and $110.9 million and asset optimization cost of revenues of $33.6 million and $107.4 million, respectively, which are presented on a net basis in asset optimization revenues.

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

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

Table of Contents

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 (loss) income before income tax expense (in thousands):



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Reconciliation of Retail Gross Margin to (Loss) income before taxes
(Loss) income before income tax expense	$	(30,070	)	$	27,178		$	(26,284	)	$	(21,120	)
Interest and other income	(494		)	(553		)	(683		)	(754		)
Interest expense	1,995			2,316			4,218			4,561
Operating (loss) income	(28,569		)	28,941			(22,749		)	(17,313		)
Depreciation and amortization	10,312			12,861			22,467			25,880
General and administrative	37,247			27,780			66,723			57,827
Less:
Net asset optimization (expense) revenues	(56		)	763			2,496			3,450
Net, (loss) gain on non-trading derivative instruments	(35,466		)	16,601			(55,269		)	(20,111		)
Net, Cash settlements on non-trading derivative instruments	12,788			8,793			20,913			(6,089		)
Retail Gross Margin	$	41,724		$	43,425		$	98,301		$	89,144

Table of Contents

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



Three Months Ended June 30, 2019
	Retail Electricity			Retail Natural Gas			Corporate and Other			Eliminations			Consolidated
Total Revenues	$	160,776		$	17,029		$	(56	)	$	—		$	177,749
Retail cost of revenues	148,187			10,572			—			—			158,759
Less:
Net asset optimization expenses	—			—			(56		)	—			(56		)
Net, loss on non-trading derivative instruments	(33,694		)	(1,772		)	—			—			(35,466		)
Current period settlements on non-trading derivatives	12,669			119			—			—			12,788
Retail Gross Margin	$	33,614		$	8,110		$	—		$	—		$	41,724
Total Assets at June 30, 2019	$	2,186,160		$	732,038		$	355,034		$	(2,876,148	)	$	397,084
Goodwill at June 30, 2019	$	117,813		$	2,530		$	—		$	—		$	120,343



Three Months Ended June 30, 2018
	Retail Electricity		Retail Natural Gas		Corporate and Other		Eliminations			Consolidated
Total revenues	$	209,447	$	22,041	$	763	$	—		$	232,251
Retail cost of revenues	151,953		10,716		—		—			162,669
Less:
Net asset optimization revenues	—		—		763		—			763
Net, gain on non-trading derivative instruments	16,120		481		—		—			16,601
Current period settlements on non-trading derivatives	8,732		61		—		—			8,793
Retail Gross Margin	$	32,642	$	10,783	$	—	$	—		$	43,425
Total Assets at December 31, 2018	$	1,857,790	$	649,969	$	361,697	$	(2,380,718	)	$	488,738
Goodwill at December 31, 2018	$	117,813	$	2,530	$	—	$	—		$	120,343

Table of Contents



Six Months Ended June 30, 2019
	Retail Electricity			Retail Natural Gas		Corporate and Other		Eliminations			Consolidated
Total revenues	$	342,868		$	75,091	$	2,496	$	—		$	420,455
Retail cost of revenues	314,074			39,940		—		—			354,014
Less:
Net asset optimization revenues	—			—		2,496		—			2,496
Net, (Loss) gain on non-trading derivatives	(55,636		)	367		—		—			(55,269		)
Current period settlements on non-trading derivatives	20,842			71		—		—			20,913
Retail Gross Margin	$	63,588		$	34,713	$	—	$	—		$	98,301
Total Assets at June 30, 2019	$	2,186,160		$	732,038	$	355,034	$	(2,876,148	)	$	397,084
Goodwill at June 30, 2019	$	117,813		$	2,530	$	—	$	—		$	120,343



Six Months Ended June 30, 2018
	Retail Electricity			Retail Natural Gas			Corporate and Other		Eliminations			Consolidated
Total revenues	$	430,346		$	85,143		$	3,450	$	—		$	518,939
Retail cost of revenues	401,500			51,045			—		—			452,545
Less:
Net asset optimization revenues	—			—			3,450		—			3,450
Net, Loss on non-trading derivatives	(17,199		)	(2,912		)	—		—			(20,111		)
Current period settlements on non-trading derivatives	(6,316		)	227			—		—			(6,089		)
Retail Gross Margin	$	52,361		$	36,783		$	—	$	—		$	89,144
Total Assets at December 31, 2018	$	1,857,790		$	649,969		$	361,697	$	(2,380,718	)	$	488,738
Goodwill at December 31, 2018	$	117,813		$	2,530		$	—	$	—		$	120,343

Table of Contents

16. Subsequent Events

Termination of Tax Receivable Agreement

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

Declaration of Dividends

On July 17, 2019, we declared a quarterly dividend of $0.18125 per share to holders of record of our Class A common stock on September 2, 2019, which will be paid on September 16, 2019.

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

Table of Contents

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the unaudited condensed consolidated financial statements and the related notes thereto included elsewhere in this Report and the audited consolidated financial statements and notes thereto and management's discussion and analysis of financial condition and results of operations included in our 2018 Form 10-K filed with the Securities and Exchange Commission (“SEC”) on March 4, 2019. Results of operations and cash flows for the three and six months ended June 30, 2019 are not necessarily indicative of results to be attained for any other period. See "Cautionary Note Regarding Forward-Looking Statements."

Overview

We are an independent retail energy services company founded in 1999 that provides residential and commercial customers in competitive markets across the United States with an alternative choice for their natural gas and electricity. We purchase our natural gas and electricity supply from a variety of wholesale providers and bill our customers monthly for the delivery of natural gas and electricity based on their consumption at either a fixed or variable price. Natural gas and electricity are then distributed to our customers by local regulated utility companies through their existing infrastructure. As of June 30, 2019, we operated in 94 utility service territories across 19 states and the District of Columbia.

Our business consists of two operating segments:

•

Retail Electricity Segment. In this segment, we purchase electricity supply through physical and financial transactions with market counterparties and ISOs and supply electricity to residential and commercial consumers pursuant to fixed-price and variable-price contracts. For the three months ended June 30, 2019 and 2018, approximately 90% 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, 2019 and 2018, approximately 10% of our retail revenues were derived from the sale of natural gas.

Recent Developments

Preferred Stock Share Repurchase Program

In May 2019, we commenced a share repurchase program (the "Repurchase Program") of our Series A Preferred Stock. We may make purchases of our Series A Preferred Stock under the Repurchase Program through May 20, 2020, and there is no dollar limit on the amount of Series A Preferred Stock that may be purchased. The Repurchase Program does not obligate us to make any repurchases and may be suspended for periods or discontinued at any time. During the three months ended June 30, 2019, we repurchased 4,500 shares of Series A Preferred Stock at a weighted-average price of $24.70 per share, for a total cost of approximately $0.1 million.

Senior Credit Facility Amendment

On June 13, 2019, the Company entered into the Third Amendment to its Senior Credit Facility (the “Third Amendment”). The Third Amendment extends the maturity date of the Senior Credit Facility to May 19, 2021. The Third Amendment also changed the Fixed Charge Coverage ratio to permit, upon satisfaction of a step-down condition, for the Company to elect to reduce the minimum required Fixed Charge Coverage Ratio from 1.25 to 1.00 to 1.10 to 1.00 for a period of one year. A step-down condition is defined as the consummation by the Company of share buybacks of its Series A Preferred Stock under the Repurchase Program with an aggregate purchase price of not less than $10.0 million.

Table of Contents

Amended and Restated Subordinated Debt Facility

Termination of Tax Receivable Agreement

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

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, 2019:



RCEs:
(In thousands)	March 31, 2019	Additions	Attrition	June 30, 2019	% Increase (Decrease)
Retail Electricity	713	36	(76)	673	(6)%
Retail Natural Gas	152	14	(21)	145	(5)%
Total Retail	865	50	(97)	818	(5)%



RCEs:
(In thousands)	December 31, 2018	Additions	Attrition	June 30, 2019	% Increase (Decrease)
Retail Electricity	754	116	(197)	673	(11)%
Retail Natural Gas	154	34	(43)	145	(6)%
Total Retail	908	150	(240)	818	(10)%

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



RCEs by Geographic Location:
(In thousands)	Electricity	% of Total	Natural Gas	% of Total	Total	% of Total
New England	301	45%	28	19%	329	40%
Mid-Atlantic	237	35%	48	33%	285	35%
Midwest	68	10%	49	34%	117	14%
Southwest	67	10%	20	14%	87	11%
Total	673	100%	145	100%	818	100%

Table of Contents

The geographical regions noted above include the following states:


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


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


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


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

Across our market areas, we have operated under a number of different retail brands. During 2018, we began consolidating brands and billing systems. In 2019, we expect to further consolidate our brands and systems as we simplify our business.

Drivers of our Business

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

Customer Growth

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 each period. Our customer growth strategy includes growing organically through traditional sales channels complemented by customer portfolio and business acquisitions.

Organic Sales

Our organic sales strategies are designed to offer competitive pricing, price certainty, and/or green product offerings to residential and commercial customers. We manage growth on a market-by-market basis by developing price curves in each of the markets we serve and comparing the market prices to the price offered by the local regulated utility. We then determine if there is an opportunity in a particular market based on our ability to create a competitive product on economic terms that provides customer value and satisfies our profitability objectives. We develop marketing campaigns using a combination of sales channels. Our marketing team continuously evaluates the effectiveness of each customer acquisition channel and makes adjustments in order to achieve desired targets. During the second quarter of 2019, we added approximately 50,000 RCEs through our various organic sales channels.

Acquisitions

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

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

Customer Acquisition Costs

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

We attempt to maintain a disciplined approach to recovery of our customer acquisition costs within a 12 month period. We capitalize and amortize our customer acquisition costs over a two year period, which is based on our

Table of Contents

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 although we continue to evaluate opportunities to acquire customers through acquisitions where they make sense economically or strategically.

Customer Attrition

Customer attrition occurs primarily as a result of: (i) customer initiated switches; (ii) residential moves and (iii) disconnection for customer payment defaults. Average monthly customer attrition for the three months ended June 30, 2019 and 2018 was 3.8% and 3.7%, respectively, and average monthly customer attrition for the six months ended June 30, 2019 and 2018 was 4.6% and 4.0%, respectively. Consistent with our previously communicated strategy to shrink our C&I customer book, our customer attrition was slightly higher than the prior year because of our pro-active non-renewal of some of our large commercial contracts.

Customer Credit Risk

Our bad debt expense for the three months ended June 30, 2019 and 2018 was 3.6% and 4.5%, respectively, and our bad debt expense for the six months ended June 30, 2019 and 2018 was 4.4% and 3.4%, respectively, of non-purchase of receivable market ("non-POR") revenues. We experienced higher bad debt expense in 2019 as a result of accounts receivable adjustments subsequent to our brand consolidations. In addition, as our geographic and acquisition channel mix has changed, our bad debt expense has increased. In order to manage this exposure, we have increased our focus on collection efforts in 2019, and focused on timely billing along with credit monitoring for new enrollments in non-POR markets.

Weather Conditions

Weather conditions directly influence the demand for natural gas and electricity and affect the prices of energy commodities. Our hedging strategy is based on forecasted customer energy usage, which can vary substantially as a result of weather patterns deviating from historical norms. We are particularly sensitive to this variability in our residential customer segment where energy usage is highly sensitive to weather conditions that impact heating and cooling demand.

Our risk management policies direct that we hedge substantially all of our forecasted demand, which is typically hedged to long-term normal weather patterns. We also attempt to add additional protection from time to time to protect us from potential volatility in markets where we have historically experienced higher exposure to extreme weather conditions. Because we attempt to match commodity purchases to anticipated demand, unanticipated changes in weather patterns can have a significant impact on our operating results and cash flows from period to period.

During the second quarter of 2019, we experienced milder than normal weather in most of our geographies. This milder weather resulted in lower than normal heating degree days for the first two-thirds of the quarter and lower than normal cooling degree days for the final third of the quarter. The lower demand for commodities meant that in some cases, where we were fully hedged, we were selling back some of those hedges into a depressed wholesale market.

During the first quarter of 2019, we experienced weather volatility in the New England, Mid-Atlantic and Midwest regions that resulted in higher-than-normal heating degree days. Prices in the day-ahead and real-time markets were less volatile than they had been in the first quarter of 2018, which in aggregate positively affected our gross margin. In the first quarter of 2018, these same markets experienced extreme unpredicted weather patterns, resulting in much higher than normal demand for electricity and natural gas, as well as prolonged periods of well-above normal prices for commodities in the day-ahead and real-time markets. This negatively impacted the gross margin in the

Table of Contents

first quarter of 2018 for the additional commodity that we supplied to our customers above the normal-weather load we had estimated and hedged.

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 results were a loss of $0.1 million for the three months ended June 30, 2019.

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)	2019		2018		2019		2018
Adjusted EBITDA	$	13,595	$	16,084	$	38,658	$	31,986
Retail Gross Margin	$	41,724	$	43,425	$	98,301	$	89,144

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.

We deduct all current period customer acquisition costs (representing spending for organic customer acquisitions) in the Adjusted EBITDA calculation because such costs reflect a cash outlay in the period in which they are incurred, even though we capitalize and amortize such costs over two years. We do not deduct the cost of customer acquisitions through acquisitions of businesses or portfolios of customers in calculating Adjusted EBITDA.

We deduct our net (losses) gains on derivative instruments, excluding current period cash settlements, from the Adjusted EBITDA calculation in order to remove the non-cash impact of net gains and losses on these instruments. We also deduct non-cash compensation expense that results from the issuance of restricted stock units under our long-term incentive plan due to the non-cash nature of the expense. Finally, we also adjust from time to time other non-cash or unusual and/or infrequent charges due to either their non-cash nature or their infrequency.

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


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


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


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


•	our compliance with financial debt covenants. (Refer to Note 10 "Debt" to Part I, Item 1 of this Report for discussion of the material terms of our Senior Credit Facility, including the covenant requirements for our

Table of Contents

Minimum Fixed Charge Coverage Ratio, Maximum Total Leverage Ratio, and Maximum Senior Secured Leverage Ratio.)

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



	Three Months Ended June 30,					Six Months Ended June 30,
(in thousands)	2019			2018		2019			2018
Reconciliation of Adjusted EBITDA to Net (loss) income:
Net (loss) income	$	(25,484	)	$	23,927	$	(22,739	)	$	(17,904	)
Depreciation and amortization	10,312			12,861		22,467			25,880
Interest expense	1,995			2,316		4,218			4,561
Income tax (benefit) expense	(4,586		)	3,251		(3,545		)	(3,216		)
EBITDA	(17,763		)	42,355		401			9,321
Less:
Net, (loss) gain on derivative instruments	(35,456		)	17,054		(54,997		)	(19,488		)
Net cash settlements on derivative instruments	12,769			8,792		20,794			(6,745		)
Customer acquisition costs	3,396			1,980		9,185			6,254
Plus:
Non-cash compensation expense	1,260			1,555		2,432			2,686
Non-recurring legal and regulatory settlements	10,807			—		10,807			—
Adjusted EBITDA	$	13,595		$	16,084	$	38,658		$	31,986

Table of Contents

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)	2019			2018			2019			2018
Reconciliation of Adjusted EBITDA to net cash provided by operating activities:
Net cash provided by operating activities	$	20,980		$	45,950		$	51,029		$	36,410
Amortization of deferred financing costs	(237		)	(317		)	(505		)	(612		)
Bad debt expense	(2,166		)	(3,302		)	(6,015		)	(5,725		)
Interest expense	1,995			2,316			4,218			4,561
Income tax (benefit) expense	(4,586		)	3,251			(3,545		)	(3,216		)
Changes in operating working capital
Accounts receivable, prepaids, current assets	(41,028		)	(38,516		)	(51,392		)	(25,888		)
Inventory	1,785			1,377			(1,858		)	(2,693		)
Accounts payable and accrued liabilities	20,222			7,618			31,172			23,934
Other	16,630			(2,293		)	15,554			5,215
Adjusted EBITDA	$	13,595		$	16,084		$	38,658		$	31,986
Cash Flow Data:
Cash flows provided by operating activities	$	20,980		$	45,950		$	51,029		$	36,410
Cash flows used in investing activities	$	(250	)	$	(8,205	)	$	(6,373	)	$	(24,000	)
Cash flows used in financing activities	$	(27,353	)	$	(23,108	)	$	(65,714	)	$	(6,127	)

Retail Gross Margin. We define retail gross margin as operating income (loss) plus (i) depreciation and amortization expenses and (ii) general and administrative expenses, less (iii) net asset optimization (expenses) revenues, (iv) net gains (losses) on non-trading derivative instruments, and (v) net current period cash settlements on non-trading derivative instruments. Retail gross margin is included as a supplemental disclosure because it is a primary performance measure used by our management to determine the performance of our retail natural gas and electricity segments. As an indicator of our retail energy business’s operating performance, retail gross margin should not be considered an alternative to, or more meaningful than, operating income (loss), its most directly comparable financial measure calculated and presented in accordance with GAAP.

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

Table of Contents

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)	2019			2018		2019			2018
Reconciliation of Retail Gross Margin to Operating (loss) income:
Operating (loss) income	$	(28,569	)	$	28,941	$	(22,749	)	$	(17,313	)
Plus:
Depreciation and amortization	10,312			12,861		22,467			25,880
General and administrative expense	37,247			27,780		66,723			57,827
Less:
Net asset optimization (expenses) revenues	(56		)	763		2,496			3,450
Net, (loss) gain on non-trading derivative instruments	(35,466		)	16,601		(55,269		)	(20,111		)
Net, Cash settlements on non-trading derivative instruments	12,788			8,793		20,913			(6,089		)
Retail Gross Margin	$	41,724		$	43,425	$	98,301		$	89,144
Retail Gross Margin - Retail Electricity Segment	$	33,614		$	32,642	$	63,588		$	52,361
Retail Gross Margin - Retail Natural Gas Segment	$	8,110		$	10,783	$	34,713		$	36,783

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.

Table of Contents

Consolidated Results of Operations

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



(In Thousands)	Three Months Ended June 30,
	2019			2018
Revenues:
Retail revenues	$	177,805		$	231,488
Net asset optimization (expense) revenues	(56		)	763
Total Revenues	177,749			232,251
Operating Expenses:
Retail cost of revenues	158,759			162,669
General and administrative expense	37,247			27,780
Depreciation and amortization	10,312			12,861
Total Operating Expenses	206,318			203,310
Operating (loss) income	(28,569		)	28,941
Other (expense)/income:
Interest expense	(1,995		)	(2,316		)
Interest and other income	494			553
Total other expenses	(1,501		)	(1,763		)
(Loss) income before income tax (benefit) expense	(30,070		)	27,178
Income tax (benefit) expense	(4,586		)	3,251
Net (loss) income	$	(25,484	)	$	23,927
Other Performance Metrics:
Adjusted EBITDA ⁽¹⁾	$	13,595		$	16,084
Retail Gross Margin ⁽¹⁾	$	41,724		$	43,425
Customer Acquisition Costs	$	3,396		$	1,980
RCE Attrition	3.8		%	3.7		%

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

Total Revenues. Total revenues for the three months ended June 30, 2019 were approximately $177.7 million, a decrease of approximately $54.5 million, or 23%, from approximately $232.2 million for the three months ended June 30, 2018, as indicated in the table below (in millions). This decrease was primarily due to a decrease in electricity and natural gas volumes as a result of a smaller C&I customer book in the second quarter of 2019 as compared to the second quarter of 2018, as well as milder than normal weather across many of our service territories, partially offset by an increase in electricity unit revenue per MWh.



Change in electricity volumes sold	$	(58.2	)
Change in natural gas volumes sold	(6.1		)
Change in electricity unit revenue per MWh	9.6
Change in natural gas unit revenue per MMBtu	1.1
Change in net asset optimization revenue	(0.9		)
Change in total revenues	$	(54.5	)

Retail Cost of Revenues. Total retail cost of revenues for the three months ended June 30, 2019 was approximately $158.8 million, a decrease of approximately $3.9 million, or 2%, from approximately $162.7 million for the three months ended June 30, 2018, as indicated in the table below (in millions). This decrease was primarily due to a

Table of Contents

decrease in electricity and natural gas volumes as a result of a smaller C&I customer book in 2019, milder than normal weather across many of our service territories, and because in the second quarter of 2018 our retail COGS were elevated as a result of full year hedges we executed in the first quarter of 2018 in order to manage through the extreme weather event with a constrained balance sheet. These impacts were mostly offset by the change in the fair value of our retail derivative portfolio.



Change in electricity volumes sold	$	(49.2	)
Change in natural gas volumes sold	(3.1		)
Change in electricity unit cost per MWh	(0.5		)
Change in natural gas unit cost per MMBtu	0.8
Change in value of retail derivative portfolio	48.1
Change in retail cost of revenues	$	(3.9	)

General and Administrative Expense. General and administrative expense for the three months ended June 30, 2019 was approximately $37.2 million, an increase of approximately $9.4 million, or 34%, as compared to $27.8 million for the three months ended June 30, 2018. This increase was primarily attributable to non-recurring legal and regulatory settlements and increased litigation expense in second quarter of 2019.

Depreciation and Amortization Expense. Depreciation and amortization expense for the three months ended June 30, 2019 was approximately $10.3 million, a decrease of approximately $2.6 million, or 20%, from approximately $12.9 million for the three months ended June 30, 2018. This decrease was primarily due to the decreased amortization expense associated with customer intangibles.

Customer Acquisition Cost. Customer acquisition cost for the three months ended June 30, 2019 was approximately $3.4 million, an increase of approximately $1.4 million, or 72%, from approximately $2.0 million for the three months ended June 30, 2018. This increase was primarily due to an increase in the number of organic sales in 2019 as compared to 2018, as we had slowed our organic sales in 2018 to concentrate on acquisitions.

Table of Contents

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018



(In Thousands)	Six Months Ended June 30,
	2019			2018
Revenues:
Retail revenues	$	417,959		$	515,489
Net asset optimization revenues	2,496			3,450
Total Revenues	420,455			518,939
Operating Expenses:
Retail cost of revenues	354,014			452,545
General and administrative	66,723			57,827
Depreciation and amortization	22,467			25,880
Total Operating Expenses	443,204			536,252
Operating loss	(22,749		)	(17,313		)
Other (expense)/income:
Interest expense	(4,218		)	(4,561		)
Interest and other income	683			754
Total other expenses	(3,535		)	(3,807		)
Loss before income tax benefit	(26,284		)	(21,120		)
Income tax benefit	(3,545		)	(3,216		)
Net loss	$	(22,739	)	$	(17,904	)
Other Performance Metrics:
Adjusted EBITDA ⁽¹⁾	$	38,658		$	31,986
Retail Gross Margin ⁽¹⁾	$	98,301		$	89,144
Customer Acquisition Costs	$	9,185		$	6,254
RCE Attrition	4.6		%	4.0		%

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

Total Revenues. Total revenues for the six months ended June 30, 2019 were approximately $420.4 million, a decrease of approximately $98.5 million, or 19%, from approximately $518.9 million for the six months ended June 30, 2018, as indicated in the table below (in millions). This decrease was primarily due to a decrease in electricity and natural gas volumes as a result of a smaller C&I customer book in 2019 as compared to 2018, as well as milder and less extreme weather across many of our service territories compared to 2018, partially offset by an increase in electricity unit revenue per MWh.



Change in electricity volumes sold	$	(109.5	)
Change in natural gas volumes sold	(12.2		)
Change in electricity unit revenue per MWh	22.1
Change in natural gas unit revenue per MMBtu	2.2
Change in net asset optimization revenue (expense)	(1.1		)
Change in total revenues	$	(98.5	)

Retail Cost of Revenues. Total retail cost of revenues for the six months ended June 30, 2019 was approximately $354.0 million, a decrease of approximately $98.6 million, or 22%, from approximately $452.6 million for the six months ended June 30, 2018, as indicated in the table below (in millions). This decrease was primarily due to a decrease in electricity and natural gas volumes as a result of smaller C&I customer book in 2019, milder and less

Table of Contents

extreme weather across many of our service territories compared to extreme weather in 2018, partially offset by the change in fair value of our retail derivative portfolio.



Change in electricity volumes sold	$	(96.2	)
Change in natural gas volumes sold	(6.9		)
Change in electricity unit cost per MWh	(2.5		)
Change in natural gas unit cost per MMBtu	(1.1		)
Change in value of retail derivative portfolio	8.1
Change in retail cost of revenues	$	(98.6	)

General and Administrative Expense. General and administrative expense for the six months ended June 30, 2019 was approximately $66.7 million, an increase of approximately $8.9 million, or 15%, as compared to $57.8 million for the six months ended June 30, 2018. This increase was primarily attributable to non-recurring legal and regulatory settlements and increased litigation expense in 2019.

Depreciation and Amortization Expense. Depreciation and amortization expense for the six months ended June 30, 2019 was approximately $22.5 million, a decrease of approximately $3.4 million, or 13%, from approximately $25.9 million for the six months ended June 30, 2018. This decrease was primarily due to the decreased amortization expense associated with customer relationship intangibles.

Customer Acquisition Cost. Customer acquisition cost for the six months ended June 30, 2019 was approximately $9.2 million, an increase of approximately $2.9 million, or 47%, from approximately $6.3 million for the six months ended June 30, 2018. This increase was primarily due to an increase in the number of organic sales in 2019 as compared to 2018, as we had slowed our organic sales in 2018 to concentrate on acquisitions.

Table of Contents

Operating Segment Results



	Three Months Ended June 30,					Six Months Ended June 30,
	2019			2018		2019			2018
	(in thousands, except volume and per unit operating data)
Retail Electricity Segment
Total Revenues	$	160,776		$	209,447	$	342,868		$	430,346
Retail Cost of Revenues	148,187			151,953		314,074			401,500
Less: Net (loss) gain on non-trading derivatives, net of cash settlements	(21,025		)	24,852		(34,794		)	(23,515		)
Retail Gross Margin⁽¹⁾ — Electricity	$	33,614		$	32,642	$	63,588		$	52,361
Volumes — Electricity (MWhs)	1,516,139			2,100,007		3,244,222			4,352,031
Retail Gross Margin ⁽²⁾— Electricity per MWh	$	22.17		$	15.54	$	19.60		$	12.03

Retail Natural Gas Segment
Total Revenues	17,029			22,041		75,091			85,143
Retail Cost of Revenues	10,572			10,716		39,940			51,045
Less: Net (loss) gain on non-trading derivatives, net of cash settlements	(1,653		)	542		438			(2,685		)
Retail Gross Margin ⁽¹⁾— Gas	$	8,110		$	10,783	$	34,713		$	36,783
Volumes — Gas (MMBtus)	2,057,121			2,840,721		9,008,731			10,517,802
Retail Gross Margin ⁽²⁾— Gas per MMBtu	$	3.94		$	3.80	$	3.85		$	3.50

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

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

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

Retail Electricity Segment

Total revenues for the Retail Electricity Segment for the three months ended June 30, 2019 were approximately $160.8 million, a decrease of approximately $48.6 million, or 23%, from approximately $209.4 million for the three months ended June 30, 2018. This decrease was largely due to lower volumes sold, resulting in a decrease of $58.2 million as a result of a smaller C&I customer book in 2019 as well as milder than normal weather across many of our service territories. This decrease was partially offset by higher electricity prices as a result of the decrease of C&I RCEs as a total percentage of our customer book, which resulted in an increase of $9.6 million.

Retail cost of revenues for the Retail Electricity Segment for the three months ended June 30, 2019 were approximately $148.2 million, a decrease of approximately $3.7 million, or 2%, from approximately $151.9 million for the three months ended June 30, 2018. This decrease was primarily due to fewer C&I customers and lower volumes sold from milder weather, resulting in a decrease of $49.2 million, a decrease in supply costs of $0.5 million, offset by change in the value of our retail derivative portfolio used for hedging, which resulted in an increase of $46.0 million.

Retail gross margin for the Retail Electricity Segment for the three months ended June 30, 2019 was approximately $33.6 million, an increase of approximately $1.0 million, or 3%, from approximately $32.6 million for the three months ended June 30, 2018, as indicated in the table below (in millions).

Table of Contents



Change in volumes sold	$	(9.1	)
Change in unit margin per MWh	10.1
Change in retail electricity segment retail gross margin	$	1.0

Retail Natural Gas Segment

Total revenues for the Retail Natural Gas Segment for the three months ended June 30, 2019 were approximately $17.0 million, a decrease of approximately $5.0 million, or 23%, from approximately $22.0 million for the three months ended June 30, 2018. This decrease was primarily attributable to lower volumes sold, which decreased total revenues by $6.1 million, offset by an increase in natural gas rates, which resulted in an increase in total revenues of $1.1 million.

Retail cost of revenues for the Retail Natural Gas Segment for the three months ended June 30, 2019 were approximately $10.6 million, a decrease of $0.1 million, or 1%, from approximately $10.7 million for the three months ended June 30, 2018. This decrease was primarily due to lower volumes resulting in a decrease of $3.1 million, offset by higher natural gas prices, which resulted in an increase of $0.8 million, a change in the value of our derivative portfolio used for hedging, which resulted in an increase of $2.2 million.

Retail gross margin for the Retail Natural Gas Segment for the three months ended June 30, 2019 was approximately $8.1 million, a decrease of approximately $2.7 million, or 25%, from approximately $10.8 million for the three months ended June 30, 2018, as indicated in the table below (in millions).



Change in volumes sold	$	(3.0	)
Change in unit margin per MMBtu	0.3
Change in retail natural gas segment retail gross margin	$	(2.7	)

Table of Contents

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018

Retail Electricity Segment

Total revenues for the Retail Electricity Segment for the six months ended June 30, 2019 were approximately $342.9 million, a decrease of approximately $87.4 million, or 20%, from approximately $430.3 million for the six months ended June 30, 2018. This decrease was largely due to a decrease in volumes, resulting in a decrease of $109.5 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 $22.1 million.

Retail cost of revenues for the Retail Electricity Segment for the six months ended June 30, 2019 was approximately $314.1 million, a decrease of approximately $87.4 million, or 22%, from approximately $401.5 million for the six months ended June 30, 2018. This decrease was primarily due to a decrease in volumes, resulting in a decrease of $96.2 million. This decrease was further impacted by decreased electricity prices, which resulted in a decrease in retail cost of revenues of $2.5 million. These decreases were partially offset by an increase of $11.3 million due to a change in the value of our retail derivative portfolio used for hedging.

Retail gross margin for the Retail Electricity Segment for the six months ended June 30, 2019 was approximately $63.6 million, an increase of approximately $11.3 million, or 21%, from approximately $52.3 million for the six months ended June 30, 2018, as indicated in the table below (in millions).



Change in volumes sold	$	(13.3	)
Change in unit margin per MWh	24.6
Change in retail electricity segment retail gross margin	$	11.3

Retail Natural Gas Segment

Total revenues for the Retail Natural Gas Segment for the six months ended June 30, 2019 were approximately $75.1 million, a decrease of approximately $10.0 million, or 12%, from approximately $85.1 million for the six months ended June 30, 2018. This decrease was primarily attributable to a decrease in volumes of $12.2 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, 2019 was approximately $39.9 million, a decrease of approximately $11.1 million, or 22%, from approximately $51.0 million for the six months ended June 30, 2018. This decrease was due to decreased supply costs of $1.1 million, a decrease of $6.9 million related to decreased volumes, and a $3.1 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, 2019 was approximately $34.7 million, a decrease of approximately $2.1 million, or 6%, from approximately $36.8 million for the six months ended June 30, 2018, as indicated in the table below (in millions).



Change in volumes sold	$	(5.3	)
Change in unit margin per MMBtu	3.2
Change in retail natural gas segment retail gross margin	$	(2.1	)

Table of Contents

Liquidity and Capital Resources

Overview

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

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

Liquidity Position

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



($ in thousands)	June 30, 2019
Cash and cash equivalents	$	27,579
Senior Credit Facility Availability ⁽¹⁾	55,488
Subordinated Debt Facility Availability ⁽²⁾	25,000
Total Liquidity	$	108,067

(1) Reflects amount of Letters of Credit that could be issued based on existing covenants as of June 30, 2019.

(2) The availability of the Subordinated Facility is dependent on our Founder's willingness and ability to lend. See "—Sources of Liquidity— Subordinated Debt Facility."

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

Senior Credit Facility Amendment

On June 13, 2019, the Company entered into the Third Amendment to its Senior Credit Facility, which extended the maturity date to May 19, 2021 and revised the Fixed Charge Coverage ratio to permit, upon satisfaction of a step-down condition, the Company to elect to reduce the minimum required Fixed Charge Coverage Ratio from 1.25 to 1.00 to 1.10 to 1.00 for a period of one year. A step-down condition is defined as the consummation by the Company of share buybacks of its Series A Preferred Stock under the Repurchase Program with an aggregate purchase price of not less than $10.0 million.

Amended and Restated Subordinated Debt Facility

On June 13, 2019, the Company entered into the Subordinated Debt Facility. The Subordinated Debt Facility amended and restated that certain Subordinated Promissory Note, dated as of December 27, 2016, by and among the Company, Spark HoldCo and Retailco, solely to extend the expiration date from July 1, 2020 to December 31, 2021 as a condition of the Third Amendment. On July 16, 2019, we borrowed $16.3 million under the Subordinated Debt Facility.

Table of Contents

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

Cash Flows

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



	Six Months Ended June 30,
	2019			2018			Change
Net cash provided by operating activities	$	51,029		$	36,410		$	14,619
Net cash used in investing activities	$	(6,373	)	$	(24,000	)	$	17,627
Net cash used in financing activities	$	(65,714	)	$	(6,127	)	$	(59,587	)

Six Months Ended June 30, 2019 Compared to the Six Months Ended June 30, 2018

Cash Flows Provided by Operating Activities. Cash flows provided by operating activities for the six months ended June 30, 2019 increased by $14.6 million compared to the six months ended June 30, 2018. The increase was primarily the result of a decrease in the changes in working capital for the six months ended June 30, 2019 primarily due to declines in accounts receivable and accounts payable attributable to lower sales and cost of sales during the 2019 period.

Cash Flows Used in Investing Activities. Cash flows used in investing activities decreased by $17.6 million for the six months ended June 30, 2019. The decrease was primarily the result of the amount paid for acquisitions during the six months ended June 30, 2019 compared to the six months ended June 30, 2018.

Cash Flows Used in Financing Activities. Cash flows used in financing activities increased by $59.6 million for the six months ended June 30, 2019. Cash flows used in financing activities increased due to an increased net paydown of our Senior Credit Facility for the six months ended June 30, 2019. In addition, for the six months ended June 30, 2018, we received proceeds from the issuance of Series A Preferred Stock of approximately $48.5 million, which did not reoccur during the six months ended June 30, 2019.

Sources of Liquidity and Capital Resources

Senior Credit Facility

As of June 30, 2019, our Senior Credit Facility had total commitments of $217.5 million, of which $135.7 million was outstanding, including $41.7 million of outstanding letters of credit. Under the Senior Credit Facility, we have various limits on advances for Working Capital Loans, Letters of Credit and Bridge Loans. The Senior Credit Facility matures on May 19, 2021. For a description of the terms and conditions of our Senior Credit Facility, including descriptions of the interest rate, commitment fee, covenants and terms of default, please see Note 10 "Debt" in the notes to our condensed consolidated financial statements. As of June 30, 2019, we were in compliance with the covenants under our Senior Credit Facility. We entered into the Third Amendment to the Senior Credit Facility on June 13, 2019. See "—Recent Developments" above.

Amended and Restated Subordinated Debt Facility

Our Subordinated Debt Facility allows us to draw advances in increments of no less than $1.0 million per advance up to $25.0 million. Although we may use the Subordinated Debt Facility from time to time to enhance short term liquidity, we do not view the Subordinated Debt Facility as a material source of liquidity. See Note 10 "Debt" for additional details. As of June 30, 2019, there was zero outstanding borrowings under the Subordinated Debt Facility. We amended and restated the Subordinated Debt Facility on July 13, 2019. See "—Recent Developments" above.

Table of Contents

Uses of Liquidity and Capital Resources

Repayment of Current Portion of Senior Credit Facility

Our Senior Credit Facility matures in 2021, and thus, no amounts are due currently. However, due to the revolving nature of the facility, excess cash available is generally used to reduce the balance outstanding, which at June 30, 2019 was $94.0 million. The current variable interest rate on the facility at June 30, 2019 was 5.47%.

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, 2019 and 2018, we spent a total of $3.4 million and $2.0 million, respectively, on organic customer acquisitions. During the six months ended June 30, 2019 and 2018, we spent a total of $9.2 million and $6.3 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, 2019 included $0.5 million related to information systems improvements.

Dividends and Distributions

During the six months ended June 30, 2019, we paid dividends to holders of our Class A common stock for the quarter ended December 31, 2018 and March 31, 2019 of approximately $0.18125 per share for each dividend declaration or $5.2 million in the aggregate. In order to pay our stated dividends to holders of our Class A common stock, our subsidiary, Spark HoldCo is required to make corresponding distributions to holders of its units, including those holders that own our Class B common stock (our non-controlling interest holder). As a result, during the six months ended June 30, 2019, Spark HoldCo made corresponding distributions of $7.5 million to our non-controlling interest holders.

For the six months ended June 30, 2019, we paid 4.0 million related to dividends to holders of Series A Preferred Stock. As of June 30, 2019, we had accrued $2.0 million related to dividends to holders of our Series A Preferred Stock, which was paid on July 15, 2019. For the full year ended December 31, 2019, we anticipate Series A Preferred Stock dividends of $2.1875 per share, or $8.1 million in the aggregate based on the Series A Preferred Stock outstanding as of June 30, 2019.

On July 17, 2019, our Board of Directors declared a quarterly dividend of $0.18125 per share of the Class A common stock and $0.546875 for the Series A Preferred Stock for the second quarter of 2019. Dividend on Class A common stock will be paid on September 16, 2019 to the holders of record as of September 2, 2019, and Series A Preferred Stock dividends will be paid on October 15, 2019 to the holders of record as of October 1, 2019.

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.

Table of Contents

Tax Receivable Agreement

Prior to July 11, 2019, we were party to a TRA with affiliates. The TRA was terminated on July 11, 2019. See “—Recent Developments” above. The TRA generally provided for the payment by the Company of 85% of the net cash savings, if any, in U.S. federal, state and local income tax or franchise tax that the Company actually realized (or was deemed to have realized in certain circumstances) in future periods. The Company retained the benefit of the remaining 15% of these tax savings.

As of each of June 30, 2019 and December 31, 2018, we had a total liability related to the TRA on our balance sheet of $27.6 million. See Note 14 "Transactions with Affiliates" in the notes to our condensed consolidated financial statements for additional details on the TRA. In July 2019, we terminated the TRA and paid $11.2 million to settle all obligations related to the TRA. See Note 16 "Subsequent Events" in the notes to our condensed consolidated financial statements and "—Recent Developments” for details of the Release Agreement.

Verde Promissory Note

In January 2018, we issued an amended and restated promissory note to the sellers of the Verde Companies (the "Verde Promissory Note”). As of December 31, 2018, there was $1.0 million outstanding under the Verde Promissory Note, all of which was paid in January 2019. The note bore interest at 9% per annum, and we made monthly payments of principal and associated interest, a portion of which was deposited into an escrow account to provide security for certain indemnification claims and obligations under the Verde purchase agreement. As of June 30, 2019 and December 31, 2018, a total of $8.0 million and $7.6 million, respectively, was held in escrow for such claims.

Verde Earnout Termination Note

Table of Contents

Off-Balance Sheet Arrangements

As of June 30, 2019, we had no material "off-balance sheet arrangements."

Related Party Transactions

For a discussion of related party transactions, see Note 14 "Transactions with Affiliates" to Part I, Item 1 of this Report.

Critical Accounting Policies and Estimates

Our critical accounting policies and estimates are described in “Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” in our 2018 Form 10-K. There have been no changes to these policies and estimates since the date of our 2018 Form 10-K.

Refer to Note 2 "Basis of Presentation and Summary of Significant Accounting Policies" to Part I, Item 1 of this Report for a discussion on recent accounting pronouncements.

Contingencies

In the ordinary course of business, we may become party to lawsuits, administrative proceedings and governmental investigations, including regulatory and other matters. Except as described in Note 13 "Commitments and Contingencies" to Part I, Item 1 of this Report, as of June 30, 2019, management does not believe that any of our outstanding lawsuits, administrative proceedings or investigations could result in a material adverse effect. Liabilities for loss contingencies arising from claims, assessments, litigation, fines, penalties and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. For a discussion of the status of current legal and regulatory matters, see Note 13 "Commitments and Contingencies" to Part I, Item 1 of this Report.

Table of Contents

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Commodity Price Risk

We hedge and procure our energy requirements from various wholesale energy markets, including both physical and financial markets and through short and long-term contracts. Our financial results are largely dependent on the margin we are able to realize between the wholesale purchase price of natural gas and electricity plus related costs and the retail sales price we charge our customers for these commodities. We actively manage our commodity price risk by entering into various derivative or non-derivative instruments to hedge the variability in future cash flows from fixed-price forecasted sales and purchases of natural gas and electricity in connection with our retail energy operations. These instruments include forwards, futures, swaps, and option contracts traded on various exchanges, such as NYMEX and Intercontinental Exchange, or ICE, as well as over-the-counter markets. These contracts have varying terms and durations, which range from a few days to several years, depending on the instrument. We also utilize similar derivative contracts in connection with our asset optimization activities to attempt to generate incremental gross margin by effecting transactions in markets where we have a retail presence. Generally, any such instruments that are entered into to support our retail electricity and natural gas business are categorized as having been entered into for non-trading purposes, and instruments entered into for any other purpose are categorized as having been entered into for trading purposes.

Our net (loss) gain on our non-trading derivative instruments, net of cash settlements, was $(22.7) million and $25.4 million for the three months ended June 30, 2019 and 2018, respectively, and $(34.4) million and $(26.2) million for the six months ended June 30, 2019 and 2018, respectively.

We have adopted risk management policies to measure and limit market risk associated with our fixed-price portfolio and our hedging activities. For additional information regarding our commodity price risk and our risk management policies, see “Item 1A—Risk Factors” in our 2018 Form 10-K.

We measure the commodity risk of our non-trading energy derivatives using a sensitivity analysis on our net open position. As of June 30, 2019, our Gas Non-Trading Fixed Price Open Position (hedges net of retail load) was a short position of 288,262 MMBtu. An increase of 10% in the market prices (NYMEX) from their June 30, 2019 levels would have increased the fair market value of our net non-trading energy portfolio by $0.1 million. Likewise, a decrease of 10% in the market prices (NYMEX) from their June 30, 2019 levels would have decreased the fair market value of our non-trading energy derivatives by $0.1 million. As of June 30, 2019, our Electricity Non-Trading Fixed Price Open Position (hedges net of retail load) was a long position of 55,175 MWhs. An increase of 10% in the forward market prices from their June 30, 2019 levels would have decreased the fair market value of our net non-trading energy portfolio by $0.6 million. Likewise, a decrease of 10% in the forward market prices from their June 30, 2019 levels would have increased the fair market value of our non-trading energy derivatives by $0.6 million.

Credit Risk

In many of the utility services territories where we conduct business, Purchase of Receivables ("POR") programs have been established, whereby the local regulated utility purchases our receivables, and becomes responsible for billing the customer and collecting payment from the customer. This service results in substantially all of our credit risk being with the utility and not to our end-use customer in these territories. Approximately 66% and 68% 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, 2019 and 2018, respectively, and 67% and 68% for the six months ended June 30, 2019 and 2018, respectively, all of which had investment grade ratings as of such date. We paid these local regulated utilities a weighted average discount of approximately 0.9% and 1.0% for the three

Table of Contents

months ended June 30, 2019 and 2018, respectively, and 0.9% and 1.1% for the six months ended June 30, 2019 and 2018, respectively, of total revenues for customer credit risk protection. In certain of the POR markets in which we operate, the utilities limit their collections exposure by retaining the ability to transfer a delinquent account back to us for collection when collections are past due for a specified period.

If our collection efforts are unsuccessful, we return the account to the local regulated utility for termination of service. Under these service programs, we are exposed to credit risk related to payment for services rendered during the time between when the customer is transferred to us by the local regulated utility and the time we return the customer to the utility for termination of service, which is generally one to two billing periods. We may also realize a loss on fixed-price customers in this scenario due to the fact that we will have already fully hedged the customer’s expected commodity usage for the life of the contract.

In non-POR markets (and in POR markets where we may choose to direct bill our customers), we manage customer credit risk through formal credit review in the case of commercial customers, and credit score screening, deposits and disconnection for non-payment, in the case of residential customers. Economic conditions may affect our customers’ ability to pay bills in a timely manner, which could increase customer delinquencies and may lead to an increase in bad debt expense. Our bad debt expense for the three months ended June 30, 2019 and 2018 was approximately 3.6% and 4.5% of non-POR market retail revenues, respectively, and our bad debt expense for the six months ended June 30, 2019 and 2018 was approximately 4.4% and 3.4% 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, 2019.

We are exposed to wholesale counterparty credit risk in our retail and asset optimization activities. We manage this risk at a counterparty level and secure our exposure with collateral or guarantees when needed. At June 30, 2019, approximately $0.8 million of our total exposure of $3.5 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, 2019.

Interest Rate Risk

We are exposed to fluctuations in interest rates under our variable-price debt obligations. At June 30, 2019, we were co-borrowers under the Senior Credit Facility, under which $94.0 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, 2019, a 1% increase in interest rates would have resulted in additional annual interest expense of approximately $0.9 million. During 2018, we entered into two interest rate swap agreements to manage interest rate risk.

Table of Contents

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our Chief Executive Officer and our Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10-Q. The term “disclosure controls and procedures,” as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to our management, including our principal executive and principal financial officers or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving their objectives, and management necessarily applies its judgment in evaluating the cost benefit relationship of possible controls and procedures. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2019 at a reasonable assurance level.

Changes in Internal Control over Financial Reporting

There was no change in our internal control over financial reporting identified in connection with the evaluation required by Rule 13a-15(d) and 15d-15(d) of the Exchange Act that occurred during the three months ended June 30, 2019 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Table of Contents

PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

See Note 13 "Commitments and Contingencies" to Part I, Item 1 of this Report, which is incorporated by reference into this Part II, Item 1, for a description of certain ligation, legal proceedings, and regulatory matters.

Item 1A. Risk Factors.

Security holders and potential investors in our securities should carefully consider the risk factors under "Item 1A— Risk Factors" in our 2018 Form 10-K. Except as provided below, there has been no material change in our risk factors from those described in the 2018 Form 10-K. 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.

We cannot guarantee that our Repurchase Program will enhance shareholder value and purchases, if any, could increase the volatility of the price of our Series A Preferred Stock.

Our Board of Directors has authorized the Repurchase Program, which permits us to purchase our Series A Preferred Stock through May 20, 2020. The Repurchase Program does not obligate us to purchase a specific dollar amount or number of shares of Series A Preferred Stock. The specific timing and amount of purchases, if any, will depend upon several factors, including ongoing assessments of capital needs, the market price of the Series A Preferred Stock, and other factors, including general market conditions. There can be no assurance that we will make future purchases of Series A Preferred Stock or that we will purchase a sufficient number of shares to satisfy market expectations.

Purchases of our Series A Preferred Stock could affect the market price and increase volatility of our Series A Preferred Stock. We cannot provide any assurance that purchases under the Repurchase Program will be made at the best possible price. Additionally, purchases under our Repurchase Program could diminish our cash reserves or increase borrowings under our Senior Credit Facility or Subordinated Facility, which may impact our ability to finance future growth and to pursue possible future strategic opportunities and acquisitions. Although our Repurchase Program is intended to enhance long-term shareholder value, there is no assurance that it will do so.

We are permitted to and could discontinue our Repurchase Program prior to its expiration or completion. The existence of the Repurchase Program could cause our Series A Preferred Stock price to be higher than it would be in the absence of such a program, and any such discontinuation could cause the market price of our Series A Preferred Stock to decline.

We may not be able to maintain our listing on NASDAQ.

As previously disclosed, James G. Jones II resigned from our Board of Directors, effective as of June 13, 2019. Upon Mr. Jones’s resignation, the Audit Committee of the Board consisted of only two independent directors. On June 13, 2019, we provided notice to the NASDAQ that we did not satisfy NASDAQ Listing Rule 5605(c)(2)(A), which requires the Audit Committee of the Board of Directors to consist of at least three independent directors. On June 17, 2019, we received a letter from NASDAQ noting the deficiency. We are relying upon a cure period under NASDAQ Listing Rule 5605(c)(4)(B), which expires at our 2020 annual meeting of shareholders or June 13, 2020, whichever is earlier.

While the Board is actively working to fill the vacancy left by Mr. Jones’s resignation and to regain compliance with the audit committee composition requirements under NASDAQ Listing Rule 5605(c)(2)(A) by or before the end of the cure period, there can be no assurance that we will be able to do so.

Table of Contents

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

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



Period	(a) Total Number of Shares Purchased	(b) Average Price Paid per Share		(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs⁽¹⁾	(d) Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
April 1 - April 30, 2019	—	$	—	—	$	—
May 1 - May 31, 2019	4,500	24.70		4,500	—
June 1 - June 30, 2019	—	—		—	—
Total	4,500	$	24.70	4,500	$	—

(1) On May 22, 2019, the Company announced that the Board of Directors authorized the Repurchase Program to purchase shares of Series A Preferred Stock through May 20, 2020. There is no dollar limit on the amount of Series A Preferred Stock that may be purchased. The Repurchase Program does not obligate us to make any repurchases and may be suspended for periods or discontinued at any time.

Table of Contents



Item 6. Exhibits

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

Table of Contents



INDEX TO EXHIBITS
		Incorporated by Reference
Exhibit	Exhibit Description	Form	Exhibit Number		Filing Date	SEC File No.
2.1#	Membership Interest Purchase Agreement, by and among Spark Energy, Inc., Spark HoldCo, LLC, Provider Power, LLC, Kevin B. Dean and Emile L. Clavet, dated as of May 3, 2016.	10-Q		2.1	5/5/2016	001-36559
2.2#	Membership Interest Purchase Agreement, by and among Spark Energy, Inc., Spark HoldCo, LLC, Retailco, LLC and National Gas & Electric, LLC, dated as of May 3, 2016.	10-Q		2.2	5/5/2016	001-36559
2.3#	Amendment No. 1 to the Membership Interest Purchase Agreement, dated as of July 26, 2016, by and among Spark Energy, Inc., Spark HoldCo, LLC, Provider Power, LLC, Kevin B. Dean and Emile L. Clavet.	8-K		2.1	8/1/2016	001-36559
2.4#	Membership Interest and Stock Purchase Agreement, by and among Spark Energy, Inc., CenStar Energy Corp. and Verde Energy USA Holdings, LLC, dated as of May 5, 2017.	10-Q		2.4	5/8/2017	001-36559
2.5	First Amendment to the Membership Interest and Stock Purchase Agreement, dated July 1, 2017, by and among Spark Energy, Inc., CenStar Energy Corp., and Verde Energy USA Holdings, LLC.	8-K		2.1	7/6/2017	001-36559
2.6#	Agreement to Terminate Earnout Payments, effective January 12, 2018, by and among Spark Energy, Inc., CenStar Energy Corp., Woden Holdings, LLC (fka Verde Energy USA Holdings, LLC), Verde Energy USA, Inc., Thomas FitzGerald, and Anthony Mench.	8-K		2.1	1/16/2018	001-36559
2.7#	Asset Purchase Agreement, dated March 7, 2018, by and between Spark HoldCo, LLC and National Gas & Electric, LLC.	10-K		2.7	3/9/2018	001-36559
2.8#	Asset Purchase Agreement, by and between Spark HoldCo, LLC, Starion Energy Inc., Starion Energy NY Inc., and Starion Energy PA Inc., dated October 19, 2018.	8-K		2.1	10/25/2018	001-36559
3.1	Amended and Restated Certificate of Incorporation of Spark Energy, Inc.	8-K		3.1	8/4/2014	001-36559
3.2	Amended and Restated Bylaws of Spark Energy, Inc.	8-K		3.2	8/4/2014	001-36559
3.3	Certificate of Designations of Rights and Preferences of 8.75% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Stock	8-A		5	3/14/2017	001-36559
4.1	Class A Common Stock Certificate	S-1		4.1	6/30/2014	333-196375
10.1†	Spark Energy, Inc. Second Amended and Restated Long Term Incentive Plan.	8-K		10.1	5/23/2019	001-36559
10.2	Amendment No. 3 to the Credit Agreement, dated as of June 13, 2019, by and among Spark Energy, Inc., the Co-Borrowers, the Issuing Banks party thereto, Coӧperatieve Rabobank U.A., New York Branch, as agent, and the Banks party thereto.	8-K		10.1	6/18/2019	001-36559
10.3	Amended and Restated Subordinated Promissory Note of Spark HoldCo, LLC and Spark Energy, Inc., dated June 13, 2019.	8-K		10.2	6/18/2019	001-36559
10.4†	Employment Agreement, dated June 14, 2019, by and between Spark Energy, Inc. and James G. Jones II.	8-K		10.3	6/18/2019	001-36559

Table of Contents



10.5	TRA Termination and Release Agreement, dated July 11, 2019, by and among Spark Energy, Inc., Spark HoldCo, LLC, Retailco, LLC, NuDevco Retail, LLC and W. Keith Maxwell III.	8-K	10.1	7/17/2019	001-36559
31.1*	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
31.2*	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
32**	Certifications pursuant to 18 U.S.C. Section 1350.
101.INS*	XBRL Instance Document.
101.SCH*	XBRL Schema Document.
101.CAL*	XBRL Calculation Document.
101.LAB*	XBRL Labels Linkbase Document.
101.PRE*	XBRL Presentation Linkbase Document.
101.DEF*	XBRL Definition Linkbase Document.

* Filed herewith

** Furnished herewith

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

† Compensatory plan or arrangement

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 8, 2019		/s/ James G. Jones II
		James G. Jones II
		Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)