Via Renewables, Inc. - Quarter Report: 2022 June (Form 10-Q)


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

FORM 10-Q

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

For the quarterly period ended June 30, 2022

☐ 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

Via Renewables, 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	VIA	The NASDAQ Global Select Market
8.75% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Stock, par value $0.01 per share	VIASP	The NASDAQ Global Select Market

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

Yes ☒ No ☐

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

Yes ☒ No ☐

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

Large accelerated filer ☐ Accelerated filer ☒

Non-accelerated filer ☐ Smaller reporting company ☐

Emerging Growth Company ☐

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

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

Yes ☐ No ☒

There were 15,857,766 shares of Class A common stock, 20,000,000 shares of Class B common stock and 3,567,543 shares of Series A Preferred Stock outstanding as of August 2, 2022.


VIA RENEWABLES, INC.
INDEX TO QUARTERLY REPORT ON FORM 10-Q
For the Quarter Ended June 30, 2022
						Page No.
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS

CONDENSED CONSOLIDATED BALANCE SHEETS AS OF JUNE 30, 2022 AND DECEMBER 31, 2021 (unaudited)						5

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2022 AND 2021 (unaudited)						6

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2022 AND 2021 (unaudited)						7

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE SIX MONTHS ENDED JUNE 30, 2022 AND 2021 (unaudited)						11

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (unaudited)						12

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS						38
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK						56
ITEM 4. CONTROLS AND PROCEDURES						58
PART II. OTHER INFORMATION						59
ITEM 1. LEGAL PROCEEDINGS						59
ITEM 1A. RISK FACTORS						59




ITEM 6. EXHIBITS						61

SIGNATURES						63

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Cautionary Note Regarding Forward Looking Statements

This Quarterly Report on Form 10-Q (this “Report”) contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. These forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), can be identified by the use of forward-looking terminology including “may,” “should,” “could,” “likely,” “will,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” “plan,” “intend,” “project,” or other similar words. Forward-looking statements appear in a number of places in this Report. All statements, other than statements of historical fact, included in this Report are forward-looking statements. The forward-looking statements include statements regarding the impacts of COVID-19 and the 2021 severe weather event, cash flow generation and liquidity, business strategy, prospects for growth and acquisitions, outcomes of legal proceedings, ability to pay and amount of cash dividends and distributions on our Class A common stock and Series A Preferred Stock, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans, objectives, beliefs of management, availability and terms of capital, competition, governmental regulation and general economic conditions. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we cannot give any assurance that such expectations will prove correct.

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

•evolving risks, uncertainties and impacts relating to COVID-19, including the geographic spread, the severity of the disease, the scope and duration of the COVID-19 outbreak, actions that may be taken by governmental authorities to contain the COVID-19 outbreak or to treat its impact, and the potential for continuing negative impacts of COVID-19 on economies and financial markets;

•the ultimate impact of the 2021 severe weather event, including future benefits or costs related to ERCOT market securitization efforts, and any corrective action by the State of Texas, ERCOT, the Railroad Commission of Texas, or the Public Utility Commission of Texas;

•changes in commodity prices, the margins we achieve, and interest rates;

•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;

•our ability to acquire customers and actual attrition rates;

•changes in costs to acquire customers;

•accuracy of billing systems;

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

•significant changes in, or new changes by, the independent system operators (“ISOs”) in the regions we operate;

•competition; and

•the “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2021, in "
Item 1A — Risk Factors" of this Report, and in our other public filings and press releases.

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

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the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements.

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PART I. — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

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VIA RENEWABLES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands, except share counts)

(unaudited)


	June 30, 2022		December 31, 2021
Assets
Current assets:
Cash and cash equivalents	$	43,196	$	68,899
Restricted cash	2,327		6,421
Accounts receivable, net of allowance for doubtful accounts of $4,040 at June 30, 2022 and $2,368 at December 31, 2021	56,292		66,676
Accounts receivable—affiliates	5,709		3,819
Inventory	2,391		1,982
Fair value of derivative assets, net	45,956		3,930
Customer acquisition costs, net	2,084		946
Customer relationships, net	6,591		8,523

Deposits	6,606		6,664
Renewable energy credit asset	16,811		14,691

Other current assets	10,785		14,129
Total current assets	198,748		196,680
Property and equipment, net	4,451		4,261
Fair value of derivative assets, net	990		340
Customer acquisition costs, net	1,177		453
Customer relationships, net	660		5,660
Deferred tax assets	18,321		23,915
Goodwill	120,343		120,343
Other assets	4,127		3,624
Total assets	$	348,817	$	355,276

Liabilities, Series A Preferred Stock and Stockholders' Equity
Current liabilities:
Accounts payable	$	31,770	$	43,285
Accounts payable—affiliates	427		491
Accrued liabilities	12,485		19,303
Renewable energy credit liability	9,469		13,548
Fair value of derivative liabilities, net	2,468		4,158






Other current liabilities	345		1,707
Total current liabilities	56,964		82,492
Long-term liabilities:
Fair value of derivative liabilities, net	11,185		36

Long-term portion of Senior Credit Facility	95,000		135,000
Subordinated debt—affiliates	20,000		—




Other long-term liabilities	—		109
Total liabilities	183,149		217,637
Commitments and contingencies (Note 12)

Series A Preferred Stock, par value $0.01 per share, 20,000,000 shares authorized, 3,567,543 shares issued and outstanding at June 30, 2022 and December 31, 2021	87,036		87,288

Stockholders' equity:
Common Stock:

Class A common stock, par value $0.01 per share, 120,000,000 shares authorized, 16,002,360 shares issued and 15,857,766 shares outstanding at June 30, 2022 and 15,791,019 shares issued and 15,646,425 shares outstanding at December 31, 2021	160		158
Class B common stock, par value $0.01 per share, 60,000,000 shares authorized, 20,000,000 shares issued and outstanding at June 30, 2022 and December 31, 2021	201		201


Additional paid-in capital	56,447		54,663
Accumulated other comprehensive loss	(40)		(40)
Retained earnings	9,004		776
Treasury stock, at cost, 144,594 shares at June 30, 2022 and December 31, 2021	(2,406)		(2,406)
Total stockholders' equity	63,366		53,352
Non-controlling interest in Spark HoldCo, LLC	15,266		(3,001)
Total equity	78,632		50,351
Total liabilities, Series A Preferred Stock and Stockholders' equity	$	348,817	$	355,276

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

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VIA RENEWABLES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)

(unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021

Revenues:
Retail revenues	$	98,347	$	82,309	$	226,405	$	195,454
Net asset optimization (expense) revenues	(1,248)		(114)		(2,152)		(254)
Total Revenues	97,099		82,195		224,253		195,200
Operating Expenses:
Retail cost of revenues	61,702		36,176		130,409		158,344
General and administrative	13,583		10,663		28,518		23,334
Depreciation and amortization	4,936		5,413		10,120		11,449
Total Operating Expenses	80,221		52,252		169,047		193,127
Operating income	16,878		29,943		55,206		2,073
Other (expense)/income:
Interest expense	(1,820)		(1,552)		(3,127)		(2,863)
Interest and other income	206		79		255		165
Total other expenses	(1,614)		(1,473)		(2,872)		(2,698)
Income (loss) before income tax expense	15,264		28,470		52,334		(625)
Income tax expense	2,730		3,674		8,774		2,139
Net income (loss)	$	12,534	$	24,796	$	43,560	$	(2,764)
Less: Net income (loss) attributable to non-controlling interests	7,916		14,313		25,968		(5,616)
Net income attributable to Via Renewables, Inc. stockholders	$	4,618	$	10,483	$	17,592	$	2,852
Less: Dividend on Series A Preferred Stock	1,700		1,951		3,651		3,902
Net income (loss) attributable to stockholders of Class A common stock	$	2,918	$	8,532	$	13,941	$	(1,050)







Net income (loss) attributable to Via Renewables, Inc. per share of Class A common stock
Basic	$	0.19	$	0.58	$	0.89	$	(0.07)
Diluted	$	0.18	$	0.58	$	0.88	$	(0.07)

Weighted average shares of Class A common stock outstanding
Basic	15,745		14,685		15,701		14,656
Diluted	15,776		14,821		15,793		14,767

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

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VIA RENEWABLES, INC.

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(in thousands)

(unaudited)


Six Months Ended June 30, 2022
	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, 2021	15,791	20,000	(144)	$	158	$	201	$	(2,406)	$	(40)	$	54,663	$	776	$	53,352	$	(3,001)	$	50,351
Stock based compensation	—	—	—			—		—		—		1,857		—		1,857		—		1,857
Restricted stock unit vesting	211		—	2		—		—		—		(471)		—		(469)		—		(469)
Consolidated net income	—	—	—	—		—		—		—		—		17,592		17,592		25,968		43,560

Distributions paid to non-controlling unit holders	—	—	—	—		—		—		—		—		—		—		(7,303)		(7,303)
Dividends paid to Class A common stockholders ($0.3625 per share)	—	—	—	—		—		—		—		—		(5,713)		(5,713)		—		(5,713)
Dividends paid to Preferred Stockholders	—	—	—	—		—		—		—		—		(3,651)		(3,651)		—		(3,651)



Changes in ownership interest	—	—	—	—		—		—		—		398		—		398		(398)		—
Balance at June 30, 2022	16,002	20,000	(144)	$	160	$	201	$	(2,406)	$	(40)	$	56,447	$	9,004	$	63,366	$	15,266	$	78,632

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

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Three Months Ended June 30, 2022
	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, 2022	15,804	20,000	(144)	$	158	$	201	$	(2,406)	$	(40)	$	55,209	$	8,960	$	62,082	$	11,114	$	73,196


Stock based compensation	—	—	—	—		—		—		—		1,512		—		1,512		—		1,512
Restricted stock unit vesting	198	—	—	2		—		—		—		(413)		—		(411)		—		(411)
Consolidated net income	—	—	—	—		—		—		—		—		4,618		4,618		7,916		12,534
Distributions paid to non-controlling unit holders	—	—	—	—		—		—		—		—		—		—		(3,625)		(3,625)
Dividends paid to Class A common stockholders ($0.18125 per share)	—	—	—	—		—		—		—		—		(2,874)		(2,874)		—		(2,874)
Dividends paid to Preferred Stockholders	—	—	—	—		—		—		—		—		(1,700)		(1,700)		—		(1,700)


Changes in Ownership Interest	—	—	—	—		—		—		—		139		—		139		(139)		—
Balance at June 30, 2022	16,002	20,000	(144)	$	160	$	201	$	(2,406)	$	(40)	$	56,447	$	9,004	$	63,366	$	15,266	$	78,632

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

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Six Months Ended June 30, 2021
	Issued Shares of Class A Common Stock	Issued Shares of Class B Common Stock	Treasury Stock	Class A Common Stock		Class B Common Stock		Treasury Stock		Accumulated Other Comprehensive Loss		Additional Paid-in Capital		Retained Earnings (Deficit)		Total Stockholders' Equity		Non-controlling Interest		Total Equity
Balance at December 31, 2020	14,772	20,800	(144)	$	148	$	209	$	(2,406)	$	(40)	$	55,222	$	11,721	$	64,854	$	23,607	$	88,461


Stock based compensation	—	—	—	—		—		—		—		1,402		—		1,402		—		1,402
Restricted stock unit vesting	145	—	—	1		—		—		—		(588)		—		(587)		—		(587)
Consolidated net income (loss)	—	—	—	—		—		—		—		—		2,852		2,852		(5,616)		(2,764)

Distributions paid to non-controlling unit holders	—	—	—	—		—		—		—		—		—		—		(10,186)		(10,186)
Dividends paid to Class A common stockholders ($0.3625 per share)	—	—	—	—		—		—		—		(2,651)		(2,677)		(5,328)		—		(5,328)
Dividends paid to Preferred Stockholders	—	—	—	—		—		—		—		—		(3,902)		(3,902)		—		(3,902)



Changes in ownership interest	—	—	—	—		—		—		—		(507)		—		(507)		507		—
Balance at June 30, 2021	14,917	20,800	(144)	$	149	$	209	$	(2,406)	$	(40)	$	52,878	$	7,994	$	58,784	$	8,312	$	67,096

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

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Three Months Ended June 30, 2021
	Issued Shares of Class A Common Stock	Issued Shares of Class B Common Stock	Treasury Stock	Class A Common Stock		Class B Common Stock		Treasury Stock		Accumulated Other Comprehensive Loss		Additional Paid-in Capital		Retained Earnings (Deficit)		Total Stockholders' Equity		Non-controlling Interest		Total Equity
Balance at March 31, 2021	14,772	20,800	(144)	$	148	$	209	$	(2,406)	$	(40)	$	52,904	$	2,139	$	52,954	$	(2,717)	$	50,237


Stock based compensation	—	—	—	—		—		—		—		1,025		—		1,025		—		1,025
Restricted stock unit vesting	145	—	—	1		—		—		—		(588)		—		(587)		—		(587)
Consolidated net income	—	—	—	—		—		—		—		—		10,483		10,483		14,313		24,796

Distributions paid to non-controlling unit holders	—	—	—	—		—		—		—		—		—		—		(3,747)		(3,747)
Dividends paid to Class A common stockholders ($0.18125 per share)	—	—	—	—		—		—		—		—		(2,677)		(2,677)		—		(2,677)
Dividends paid to Preferred Stockholders	—	—	—	—		—		—		—		—		(1,951)		(1,951)		—		(1,951)


Changes in ownership interest	—	—	—	—		—		—		—		(463)		—		(463)		463		—
Balance at June 30, 2021	14,917	20,800	(144)	$	149	$	209	$	(2,406)	$	(40)	$	52,878	$	7,994	$	58,784	$	8,312	$	67,096

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

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VIA RENEWABLES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(unaudited)


	Six Months Ended June 30,
	2022		2021
Cash flows from operating activities:
Net income (loss)	$	43,560	$	(2,764)
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization expense	10,120		11,449
Deferred income taxes	5,595		4,680

Stock based compensation	1,922		1,571
Amortization of deferred financing costs	713		517


Bad debt expense	1,833		(113)
Gain on derivatives, net	(57,460)		(25,928)
Current period cash settlements on derivatives, net	21,844		390

Other	43		—
Changes in assets and liabilities:
Decrease in accounts receivable	8,585		25,057
(Increase) decrease in accounts receivable—affiliates	(1,890)		380
(Increase) decrease in inventory	(409)		400
Increase in customer acquisition costs	(2,590)		(456)
Decrease in prepaid and other current assets	2,678		6,324
Decrease in intangible assets—customer acquisition	13		27
(Increase) decrease in other assets	(705)		519
Decrease in accounts payable and accrued liabilities	(19,372)		(12,948)
Decrease in accounts payable—affiliates	(64)		(382)
(Decrease) increase in other current liabilities	(1,362)		473
Decrease in other non-current liabilities	(110)		(28)
Net cash provided by operating activities	12,944		9,168
Cash flows from investing activities:
Purchases of property and equipment	(1,126)		(1,063)
Acquisition of Customers	(4,034)		—

Net cash used in investing activities	(5,160)		(1,063)
Cash flows from financing activities:

Borrowings on notes payable	223,000		371,000
Payments on notes payable	(263,000)		(336,000)
Net borrowings on subordinated debt facility	20,000		10,000



Restricted stock vesting	(663)		(833)


Payment of dividends to Class A common stockholders	(5,713)		(5,328)
Payment of distributions to non-controlling unitholders	(7,303)		(10,186)
Payment of Preferred Stock dividends	(3,902)		(3,902)

Net cash (used in) provided by financing activities	(37,581)		24,751
(Decrease) Increase in Cash, cash equivalents and Restricted cash	(29,797)		32,856
Cash, cash equivalents and Restricted cash—beginning of period	75,320		71,684
Cash, cash equivalents and Restricted cash—end of period	$	45,523	$	104,540
Supplemental Disclosure of Cash Flow Information:
Non-cash items:
Property and equipment purchase accrual	$	4	$	69



Cash paid (received) during the period for:
Interest	$	2,270	$	2,145
Taxes	$	1,252	$	(5,866)

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

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VIA RENEWABLES, 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. The Company is a holding company whose primary 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 our retail energy services. We conduct our retail energy services business through several brands across our service areas, including Electricity Maine, Electricity N.H., Major Energy, Provider Power Massachusetts, Spark Energy, and Verde Energy. Via Energy Solutions (“VES”) is a wholly owned subsidiary of the Company that offers broker services for retail energy customers.

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, 2021 (the “2021 Form 10-K”). Our unaudited condensed consolidated financial statements are presented on a consolidated basis and include all wholly-owned and controlled subsidiaries. We account for investments over which we have significant influence but not a controlling financial interest using the equity method of accounting. All significant intercompany transactions and balances have been eliminated in the unaudited condensed consolidated financial statements.

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

Use of Estimates and Assumptions

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

Relationship with our Founder, Majority Shareholder, and Chief Executive Officer

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

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Holdings LLC ("NuDevco Retail Holdings"), which is a wholly owned subsidiary of Electric HoldCo, LLC, which is also a wholly owned subsidiary of TxEx.

ERCOT Securitization Proceeds

In June 2022, the Company received $9.6 million from ERCOT related to PURA Subchapter N Securitization financing. The Company accounted for the proceeds received as the recovery of costs of sales and services from a vendor under FASB ASC Topic 705, Cost of Sales and Services reflected as a reduction of retail cost of revenues within our consolidated statements of operations for the quarter ended June 30, 2022, as that is where the initial costs related to the impact of Winter Storm Uri were recorded.

New Accounting Standards Recently Adopted

There have been no changes to our significant accounting policies as disclosed in our 2021 Form 10-K, except as follows:

In March 2020, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2020-04, Reference Rate Reform (Topic 848), Facilitation of the Effects of Reference Rate Reform on Financial Reporting ("ASU 2020-04"). The amendments in ASU 2020-04 provide optional expedients and exceptions for applying GAAP to contracts, hedging relationships, and other transactions that reference the London Interbank Offered Rate (“LIBOR”) or another reference rate expected to be discontinued because of reference rate reform. In January 2021, the FASB issued ASU 2021-01, Reference Rate Reform ("ASU 2021-01"), which clarifies the scope and application of certain optional expedients and exceptions regarding the original guidance. The amendments in these ASUs were effective upon issuance and can be applied prospectively through December 31, 2022. The Company's Series A Preferred Stock Certificate of Designations make reference to a LIBOR rate. We adopted ASU 2020-04 effective January 1, 2022 and the adoption did not have a material impact on our consolidated financial statements.

Standards Being Evaluated/Standards Not Yet Adopted

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

3. Revenues

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

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

Revenues for electricity, natural gas, and related services are recognized as the Company transfers the promised goods and services to the customer. Electricity and natural gas products may be sold as fixed-price or variable-price products. The typical length of a contract to provide electricity and/or natural gas is twelve months. Customers are billed and generally pay at least monthly, based on usage. Electricity and natural gas sales that have been delivered but not billed by period end are estimated and recorded as accrued unbilled revenues based on estimates of customer usage since the date of the last meter read provided by the utility. Volume estimates are based on forecasted volumes and estimated residential and commercial customer usage. Unbilled revenues are calculated by multiplying these volume estimates by the applicable rate by customer class (residential or commercial). Estimated amounts are adjusted when actual usage is known and billed.

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


	Reportable Segments
	Three Months Ended June 30, 2022				Three Months Ended June 30, 2021
	Retail Electricity (a)		Retail Natural Gas		Total Reportable Segments		Retail Electricity		Retail Natural Gas		Total Reportable Segments

Primary markets (b)
New England	$	23,636	$	1,349	$	24,985	$	21,398	$	1,402	$	22,800
Mid-Atlantic	25,124		7,602		32,726		23,309		3,223		26,532
Midwest	9,292		3,121		12,413		9,362		2,910		12,272
Southwest	24,238		3,985		28,223		17,620		3,085		20,705
	$	82,290	$	16,057	$	98,347	$	71,689	$	10,620	$	82,309

Customer type
Commercial	$	9,479	$	10,764	$	20,243	$	11,171	$	4,982	$	16,153
Residential	69,548		9,200		78,748		57,390		9,640		67,030
Unbilled revenue (c)	3,263		(3,907)		(644)		3,128		(4,002)		(874)
	$	82,290	$	16,057	$	98,347	$	71,689	$	10,620	$	82,309

Customer credit risk
POR	$	46,726	$	9,435	$	56,161	$	41,404	$	4,980	$	46,384
Non-POR	35,564		6,622		42,186		30,285		5,640		35,925
	$	82,290	$	16,057	$	98,347	$	71,689	$	10,620	$	82,309

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	Reportable Segments
	Six Months Ended June 30, 2022				Six Months Ended June 30, 2021
	Retail Electricity (a)		Retail Natural Gas		Total Reportable Segments		Retail Electricity		Retail Natural Gas		Total Reportable Segments

Primary markets (b)
New England	$	53,097	$	6,510	$	59,607	$	47,639	$	5,779	$	53,418
Mid-Atlantic	55,542		27,115		82,657		51,859		16,678		68,537
Midwest	19,232		12,741		31,973		20,421		13,148		33,569
Southwest	42,460		9,708		52,168		30,525		9,405		39,930
	$	170,331	$	56,074	$	226,405	$	150,444	$	45,010	$	195,454

Customer type
Commercial	$	20,540	$	31,193	$	51,733	$	26,387	$	16,498	$	42,885
Residential	149,486		31,346		180,832		130,662		36,130		166,792
Unbilled revenue (c)	305		(6,465)		(6,160)		(6,605)		(7,618)		(14,223)
	$	170,331	$	56,074	$	226,405	$	150,444	$	45,010	$	195,454

Customer credit risk
POR	$	102,903	$	34,945	$	137,848	$	92,254	$	24,580	$	116,834
Non-POR	67,428		21,129		88,557		58,190		20,430		78,620
	$	170,331	$	56,074	$	226,405	$	150,444	$	45,010	$	195,454

(a) Retail Electricity includes Services

(b) The primary markets include the following states:

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

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

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

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

(c) 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, 2022 and 2021, our retail revenues included gross receipts taxes of $0.3 million and $0.2 million, respectively, and our retail cost of revenues included gross receipts taxes of $1.2 million and $1.0 million, respectively. During the six months ended June 30, 2022 and 2021, our retail

revenues included gross receipts taxes of $0.6 million and $0.5 million, respectively, and our retail cost of revenues included gross receipts taxes of $2.6 million and $2.2 million, respectively.

Accounts receivables and Allowance for Credit Losses

The Company conducts business in many utility service markets where the local regulated utility purchases our receivables, and then becomes responsible for billing the customer and collecting payment from the customer (“POR programs”). These POR programs result in substantially all of the Company’s credit risk being linked to the

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applicable utility, which generally has an investment-grade rating, and not to the end-use customer. The Company monitors the financial condition of each utility and currently believes its receivables are collectible.

In markets that do not offer POR programs or when the Company chooses to directly bill its customers, certain receivables are billed and collected by the Company. The Company bears the credit risk on these accounts and records an appropriate allowance for doubtful accounts to reflect any losses due to non-payment by customers. The Company’s customers are individually insignificant and geographically dispersed in these markets. The Company writes off customer balances when it believes that amounts are no longer collectible and when it has exhausted all means to collect these receivables.

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

A rollforward of our allowance for credit losses for the six months ended June 30, 2022 are presented in the table below (in thousands):




Balance at December 31, 2021	$	(2,368)

Current period bad debt provision	(1,833)
Write-offs	200
Recovery of previous write offs	(39)
Balance at June 30, 2022	$	(4,040)

4. Equity

Non-controlling Interest

We hold an economic interest and are the sole managing member in Spark HoldCo, with affiliates of our Founder holding the remaining economic interests in Spark HoldCo. As a result, we consolidate the financial position and results of operations of Spark HoldCo, and reflect the economic interests owned by these affiliates as a non-controlling interest. The Company and affiliates owned the following economic interests in Spark HoldCo at June 30, 2022 and December 31, 2021, respectively.


	The Company		Affiliated Owners
June 30, 2022	44.45	%	55.55	%
December 31, 2021	44.12	%	55.88	%

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021

Net income (loss) allocated to non-controlling interest	$	7,994	$	15,246	$	27,341	$	(3,075)
Income tax expense allocated to non-controlling interest	78		933		1,373		2,541



Net income (loss) attributable to non-controlling interest	$	7,916	$	14,313	$	25,968	$	(5,616)

Class A Common Stock and Class B Common Stock

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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.

Conversion of Class B Common Stock to Class A Common Stock

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

Dividends on Class A Common Stock

Dividends declared for the Company's Class A common stock are reported as a reduction of retained earnings, or a reduction of additional paid in capital to the extent retained earnings are exhausted. During the six months ended June 30, 2022, we paid $5.7 million in dividends to the holders of the Company's Class A common stock. This dividend represented a quarterly rate of $0.18125 per share on each share of Class A common stock.

In order to pay our stated dividends to holders of our Class A common stock, our subsidiary, Spark HoldCo is required to make corresponding distributions to holders of its units, including those holders that own our Class B common stock (our non-controlling interest holder). As a result, during the six months ended June 30, 2022, Spark HoldCo made corresponding distributions of $7.3 million to our non-controlling interest holders.

Earnings Per Share

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

The following table presents the computation of basic and diluted income per share for the three and six months ended June 30, 2022 and 2021 (in thousands, except per share data):

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	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Net income attributable to Via Renewables, Inc. stockholders	$	4,618	$	10,483	$	17,592	$	2,852
Less: Dividend on Series A Preferred Stock	1,700		1,951		3,651		3,902
Net income (loss) attributable to stockholders of Class A common stock	$	2,918	$	8,532	$	13,941	$	(1,050)

Basic weighted average Class A common shares outstanding	15,745		14,685		15,701		14,656
Basic income (loss) per share attributable to stockholders	$	0.19	$	0.58	$	0.89	$	(0.07)

Net income (loss) attributable to stockholders of Class A common stock	$	2,918	$	8,532	$	13,941	$	(1,050)


Diluted net income (loss) attributable to stockholders of Class A common stock	$	2,918	$	8,532	$	13,941	$	(1,050)

Basic weighted average Class A common shares outstanding	15,745		14,685		15,701		14,656


Effect of dilutive restricted stock units	31		136		92		111
Diluted weighted average shares outstanding	15,776		14,821		15,793		14,767

Diluted income (loss) per share attributable to stockholders	$	0.18	$	0.58	$	0.88	$	(0.07)

The computation of diluted earnings per share for the three and six months ended June 30, 2022 and 2021, respectively, excludes 20.0 million and 20.8 million shares of Class B common stock because the effect of their conversion was antidilutive. The Company's outstanding shares of Series A Preferred Stock were not included in the calculation of diluted earnings per share because they contain only contingent redemption provisions that have not occurred.

Variable Interest Entity

Spark HoldCo is a variable interest entity due to its lack of rights to participate in significant financial and operating decisions and its inability to dissolve or otherwise remove its management. Spark HoldCo owns all of the outstanding membership interests in each of our operating subsidiaries except VES. 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, 2022 and December 31, 2021 (in thousands):

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	June 30, 2022		December 31, 2021
Assets
Current assets:
Cash and cash equivalents	$	42,875	$	68,703
Accounts receivable	56,189		66,676

Other current assets	95,871		56,392
Total current assets	194,935		191,771
Non-current assets:
Goodwill	120,343		120,343

Other assets	12,542		16,758
Total non-current assets	132,885		137,101
Total Assets	$	327,820	$	328,872

Liabilities
Current liabilities:
Accounts payable and accrued liabilities	$	44,057	$	62,538



Other current liabilities	43,120		49,328
Total current liabilities	87,177		111,866
Long-term liabilities:
Long-term portion of Senior Credit Facility	95,000		135,000
Subordinated debt — affiliate	20,000		—

Other long-term liabilities	11,185		145
Total long-term liabilities	126,185		135,145
Total Liabilities	$	213,362	$	247,011

5. Preferred Stock

Holders of the Series A Preferred Stock have no voting rights, except in specific circumstances of delisting or in the case the dividends are in arrears as specified in the Series A Preferred Stock Certificate of Designations. The Series A Preferred Stock accrued dividends at an annual percentage rate of 8.75% through April 14, 2022. The floating rate period for the Series A Preferred Stock began on April 15, 2022. The dividend on the Series A Preferred Stock will accrue at an annual rate equal to the sum of (a) Three-Month LIBOR (if it then exists), or an alternative reference rate as of the applicable determination date and (b) 6.578%, based on the $25.00 liquidation preference per share of the Series A Preferred Stock. The liquidation preference provisions of the Series A Preferred Stock are considered contingent redemption provisions because there are rights granted to the holders of the Series A Preferred Stock that are not solely within our control upon a change in control of the Company. Accordingly, the Series A Preferred Stock is presented between liabilities and the equity sections in the accompanying condensed consolidated balance sheets. We have the option to redeem our Series A Preferred Stock on or after April 15, 2022.

During the three and six months ended June 30, 2022, we paid $1.9 million and $3.9 million in dividends to holders of the Series A Preferred Stock. As of June 30, 2022, we had accrued $1.7 million related to dividends to holders of the Series A Preferred Stock. This dividend was paid on July 15, 2022.

A summary of our preferred equity balance for the six months ended June 30, 2022 is as follows:


	(in thousands)






Balance at December 31, 2021	$	87,288

Accumulated dividends on Series A Preferred Stock	(252)
Balance at June 30, 2022	$	87,036

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6. Derivative Instruments

We are exposed to the impact of market fluctuations in the price of electricity and natural gas, basis differences in the price of natural gas, storage charges, renewable energy credits ("RECs"), and capacity charges from independent system operators. We use derivative instruments in an effort to manage our cash flow exposure to these risks. These instruments are not designated as hedges for accounting purposes, and, accordingly, changes in the market value of these derivative instruments are recorded in the cost of revenues. As part of our strategy to optimize pricing in our natural gas related activities, we also manage a portfolio of commodity derivative instruments held for trading purposes. Our commodity trading activities are subject to limits within our Risk Management Policy. For these derivative instruments, changes in the fair value are recognized currently in earnings in net asset optimization revenues.

Derivative assets and liabilities are presented net in our condensed consolidated balance sheets when the derivative instruments are executed with the same counterparty under a master netting arrangement. Our derivative contracts include transactions that are executed both on an exchange and centrally cleared, as well as over-the-counter, bilateral contracts that are transacted directly with third parties. To the extent we have paid or received collateral related to the derivative assets or liabilities, such amounts would be presented net against the related derivative asset or liability’s fair value. As of June 30, 2022 and December 31, 2021, we offset $0.7 million and $0.5 million, respectively, in collateral to net against the related derivative asset and liability's fair value. The specific types of derivative instruments we may execute to manage the commodity price risk include the following:

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

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

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

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

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

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

•Renewable energy credits; and

•Natural gas transportation contracts and storage agreements.

Volumes Underlying Derivative Transactions

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

Non-trading

Commodity

Notional

June 30, 2022

December 31, 2021

Natural Gas

MMBtu

3,747

3,862

Electricity

MWh

2,355

1,785

Trading

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Commodity

Notional

June 30, 2022

December 31, 2021

Natural Gas

MMBtu

1,503

1,536

Gains (Losses) on Derivative Instruments

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021			2022		2021
Gain on non-trading derivatives, net	$	12,067	$	18,898		$	55,983	$	25,952
Gain (loss) on trading derivatives, net	330		6			1,477		(24)
Gain on derivatives, net	12,397		18,904			57,460		25,928
Current period settlements on non-trading derivatives	$	(8,679)	$	795		$	(21,999)	$	(394)
Current period settlements on trading derivatives	(29)		—			155		4
Total current period settlements on derivatives	$	(8,708)	$	795		$	(21,844)	$	(390)

Gains (losses) on trading derivative instruments are recorded in net asset optimization revenues and gains (losses) on non-trading derivative instruments are recorded in retail cost of revenues on the condensed consolidated statements of operations.

Fair Value of Derivative Instruments

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


	June 30, 2022
Description	Gross Assets		Gross Amounts Offset		Net Assets		Cash Collateral Offset		Net Amount Presented
Non-trading commodity derivatives	$	71,188	$	(25,629)	$	45,559	$	(1,108)	$	44,451
Trading commodity derivatives	2,115		(610)		1,505		—		1,505
Total Current Derivative Assets	73,303		(26,239)		47,064		(1,108)		45,956
Non-trading commodity derivatives	1,000		(37)		963		—		963
Trading commodity derivatives	27		—		27		—		27
Total Non-current Derivative Assets	1,027		(37)		990		—		990
Total Derivative Assets	$	74,330	$	(26,276)	$	48,054	$	(1,108)	$	46,946


Description	Gross Liabilities		Gross Amounts Offset		Net Liabilities		Cash Collateral Offset		Net Amount Presented
Non-trading commodity derivatives	$	(2,879)	$	451	$	(2,428)	$	458	$	(1,970)
Trading commodity derivatives	(517)		19		(498)		—		(498)
Total Current Derivative Liabilities	(3,396)		470		(2,926)		458		(2,468)
Non-trading commodity derivatives	(13,299)		2,349		(10,950)		—		(10,950)
Trading commodity derivatives	(515)		280		(235)		—		(235)
Total Non-current Derivative Liabilities	(13,814)		2,629		(11,185)		—		(11,185)
Total Derivative Liabilities	$	(17,210)	$	3,099	$	(14,111)	$	458	$	(13,653)


	December 31, 2021
Description	Gross Assets		Gross Amounts Offset		Net Assets		Cash Collateral Offset		Net Amount Presented
Non-trading commodity derivatives	$	7,121	$	(3,319)	$	3,802	$	—	$	3,802
Trading commodity derivatives	143		(15)		128		—		128
Total Current Derivative Assets	7,264		(3,334)		3,930		—		3,930
Non-trading commodity derivatives	411		(71)		340		—		340
Trading commodity derivatives	—		—		—		—		—
Total Non-current Derivative Assets	411		(71)		340		—		340
Total Derivative Assets	$	7,675	$	(3,405)	$	4,270	$	—	$	4,270


Description	Gross Liabilities		Gross Amounts Offset		Net Liabilities		Cash Collateral Offset		Net Amount Presented
Non-trading commodity derivatives	$	(18,195)	$	14,504	$	(3,691)	$	491	$	(3,200)
Trading commodity derivatives	(1,403)		445		(958)		—		(958)
Total Current Derivative Liabilities	(19,598)		14,949		(4,649)		491		(4,158)
Non-trading commodity derivatives	(236)		200		(36)		—		(36)
Trading commodity derivatives	—		—		—		—		—
Total Non-current Derivative Liabilities	(236)		200		(36)		—		(36)
Total Derivative Liabilities	$	(19,834)	$	15,149	$	(4,685)	$	491	$	(4,194)

7. Property and Equipment

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


	Estimated useful lives (years)	June 30, 2022		December 31, 2021

Information technology	2 – 5	$	7,052	$	6,534

Furniture and fixtures	2 – 5	20		957
Total		7,072		7,491
Accumulated depreciation		(2,621)		(3,230)
Property and equipment—net		$	4,451	$	4,261

Information technology assets include software and consultant time used in the application, development and implementation of various systems including customer billing and resource management systems. As of June 30, 2022 and December 31, 2021, information technology includes $1.3 million and $0.2 million, respectively, of costs associated with assets not yet placed into service.

Depreciation expense recorded in the condensed consolidated statements of operations was $0.4 million and $0.5 million, respectively, for the three months ended June 30, 2022 and 2021 and $0.9 million and $0.9 million for the six months ended June 30, 2022 and 2021, respectively.

8. Intangible Assets

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


	June 30, 2022		December 31, 2021
Goodwill	$	120,343	$	120,343
Customer relationships—Acquired
Cost	$	33,918	$	46,552
Accumulated amortization	(32,933)		(41,120)
Customer relationships—Acquired	$	985	$	5,432
Customer relationships—Other
Cost	$	7,886	$	15,955
Accumulated amortization	(1,620)		(7,204)
Customer relationships—Other, net	$	6,266	$	8,751
Trademarks
Cost	$	7,040	$	7,040
Accumulated amortization	(4,000)		(3,508)
Trademarks, net	$	3,040	$	3,532

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


	Goodwill		Customer Relationships— Acquired		Customer Relationships— Other		Trademarks
Balance at December 31, 2021	$	120,343	$	5,432	$	8,751	$	3,532
Additions	—		—		1,092		—

Amortization	—		(4,447)		(3,577)		(492)
Balance at June 30, 2022	$	120,343	$	985	$	6,266	$	3,040

During the six months ended June 30, 2022, the Company changed the estimated average life for Customer Relationships – Other from three years to eighteen months, resulting in approximately $0.9 million of additional amortization recorded in the six months ended June 30, 2022.

Estimated future amortization expense for customer relationships and trademarks at June 30, 2022 is as follows (in thousands):


Year ending December 31,

2022 (remaining six months)	$	4,465
2023	2,921
2024	746
2025	543
2026	404
> 5 years	1,212
Total	$	10,291

9. Debt

Debt consists of the following amounts as of June 30, 2022 and December 31, 2021 (in thousands):


	June 30, 2022		December 31, 2021








Long-term debt:
Senior Credit Facility (1) (2)	$	95,000	$	135,000
Subordinated Debt	20,000		—

Total long-term debt	115,000		135,000
Total debt	$	115,000	$	135,000

(1) As of June 30, 2022 and December 31, 2021, the weighted average interest rate on the Senior Credit Facility was 5.04% and 3.24%, respectively.

(2) As of June 30, 2022 and December 31, 2021, we had $32.1 million and $27.7 million in letters of credit issued, respectively.

Capitalized financing costs associated with our Senior Credit Facility were $2.4 million and $1.8 million as of June 30, 2022 and December 31, 2021, respectively. Of these amounts, $0.9 million and $1.0 million are recorded in other current assets, and $1.5 million and $0.8 million are recorded in other non-current assets in the condensed consolidated balance sheets as of June 30, 2022 and December 31, 2021, respectively.

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021			2022		2021
Senior Credit Facility	$	883	$	804		$	1,579	$	1,272

Letters of credit fees and commitment fees	397		335			762		737
Amortization of deferred financing costs	468		258			713		517
Other	72		155			73		337
Interest Expense	$	1,820	$	1,552		$	3,127	$	2,863

Prior Senior Credit Facility

The Company, as guarantor, and Spark HoldCo and each subsidiary of Spark HoldCo party thereto were previously party to a senior secured revolving credit facility, dated May 19, 2017 (as amended, the “Prior Senior Credit Facility”), which included a senior secured revolving facility up to $227.5 million. The Prior Senior Credit Facility had a maturity date of October 13, 2023. The outstanding balances under the Prior Senior Credit Facility were paid in full on June 30, 2022 and it was terminated upon execution of the Company's new Senior Credit Facility.

Senior Credit Facility

On June 30, 2022, the Company and Spark HoldCo, and together with certain subsidiaries of the Company and Spark Holdco, the “Co-Borrowers”) entered into a Credit Agreement (the “Credit Agreement”).

The Credit Agreement provides for a senior secured credit facility (the “Senior Credit Facility”), which allows the Co-Borrowers to borrow up to $195.0 million on a revolving basis. The Senior Credit Facility provides for working capital loans, loans to fund acquisitions, swingline loans and letters of credit. The Senior Credit Facility expires on June 30, 2025, and all amounts outstanding thereunder are payable on the expiration date.

Borrowings under the Senior Credit Facility bear interest at the following rates depending on the classification of the borrowing and provided further that at no time shall the interest rate be less than four percent (4.0%) per annum:

•The Base Rate (a rate per annum equal to the greatest of (a) the prime rate, (b) the Federal Funds Rate plus ½ of 1% and (c) Term Secured Overnight Financing Rate ("SOFR") for a one month tenor plus 1.0%, provided, that the Base Rate shall not at any time be less than 0%), plus an applicable margin of 3.25% to 4.50% depending on the type of borrowing and the average outstanding amount of loans and letters of credit under the Credit Agreement at the end of the prior fiscal quarter;

•The Term SOFR (a rate equal to the forward looking secured overnight financing rate published by the SOFR administrator on the website of the Federal Reserve Bank of New York or any successor source with either a comparable tenor (for any calculation with respect to a SOFR loan) or a one month tenor (for any calculation with respect to a Base Rate loan)), plus an applicable margin of 3.25% to 4.50% depending on the type of borrowing and the average outstanding amount of loans and letters of credit under the Credit Agreement at the end of the prior fiscal quarter; or

•The Daily Simple SOFR (a rate equal to the forward looking secured overnight financing rate published by the SOFR administrator on the website of the Federal Reserve Bank of New York or any successor source and applied on a daily basis by the Agent in accordance with rate recommendations for daily loans), plus an applicable margin of 3.25% to 4.50% depending on the type of borrowing and the average outstanding amount of loans and letters of credit under the Credit Agreement at the end of the prior fiscal quarter, plus a liquidity premium added by the Agent to each borrowing.

The Co-Borrowers are required to pay a non-utilization 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 administrative agency fee, an arrangement fee and letter of credit fees.

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

•Minimum Fixed Charge Coverage Ratio. The Company must maintain a minimum fixed charge coverage ratio of not less than 1.10 to 1.00. The Minimum Fixed Charge Coverage Ratio is defined as the ratio of (a) Adjusted EBITDA to (b) the sum of, among other things, consolidated interest expense, letter of credit fees, non-utilization fees, earn-out payments, certain restricted payments, taxes, and payments made on or after July 31, 2020 related to the settlement of civil and regulatory matters if not included in the calculation of Adjusted EBITDA. Our Minimum Fixed Charge Coverage Ratio as of June 30, 2022 was 1.34 to 1.00.

•Maximum Total Leverage Ratio. The Company must maintain a ratio of (x) the sum of all consolidated indebtedness (excluding eligible subordinated debt and letter of credit obligations), plus (y) gross amounts reserved for civil and regulatory liabilities identified filings with the Securities and Exchange Commission, to Adjusted EBITDA of no more than 2.50 to 1.00. Our Maximum Total Leverage Ratio as of June 30, 2022 was 1.81 to 1.00.

•Maximum Senior Secured Leverage Ratio. The Company must maintain a Senior Secured Leverage Ratio of no more than 2.00 to 1.00. The Senior Secured Leverage Ratio is defined as the ratio of (a) all consolidated indebtedness 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 but excluding eligible subordinated debt and letter of credit obligations) to (b) Adjusted EBITDA for the most recent twelve month period then ended. Our Maximum Senior Secured Leverage Ratio as of June 30, 2022 was 1.64 to 1.00.

As of June 30, 2022, the Company was in compliance with financial covenants under the Senior Credit Facility. The Company has experienced compressed gross profit due to an extreme elevation of commodity costs during 2022, impacting calculated Adjusted EBITDA, a primary component of the financial covenants described above. The Company is actively working to manage the expected impact of continued gross profit compression due to elevated commodity costs on financial covenant compliance. Maintaining compliance with our covenants under our Senior Credit Facility may impact our ability to pay dividends on our Class A common stock and Series A Preferred Stock.

The Credit Agreement contains various customary affirmative covenants that require, among other things, the Company to maintain insurance, pay its obligations and comply with law. The Credit Agreement also contains customary negative covenants that limit the Company's ability to, among other things, incur certain additional indebtedness, grant certain liens, engage in certain asset dispositions, merge or consolidate, make certain payments, distributions and dividends, investments, acquisitions or loans, materially modify certain agreements, and enter into transactions with affiliates.

The Senior Credit Facility is secured by pledges of the equity of the portion of Spark HoldCo owned by the Company, 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 intellectual property assets, accounts receivable, inventory and liquid investments, and control agreements relating to bank accounts.

The Company is entitled to pay cash dividends to the holders of its Series A Preferred Stock and Class A common stock 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 do not exceed the borrowing base limits.

The Credit Agreement 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, beneficially own at least fifty-one percent (51%) of the Company’s outstanding Class A common stock and Class B common stock on a combined basis, and a controlling percentage of the voting equity interest of the Company, and certain other changes in control. If such an event of default occurs, the lenders under the Senior Credit Facility would be entitled to take various actions, including the acceleration of amounts due under the facility and all actions permitted to be taken by a secured creditor.

Subordinated Debt Facility

The Company maintains an Amended and Restated Subordinated Promissory Note in the principal amount of up to $25.0 million (the “Subordinated Debt Facility”), by and among the Company, Spark HoldCo and Retailco. The Subordinated Debt Facility allows the Company to draw advances in increments of no less than $1.0 million per advance up to $25.0 million through January 31, 2026. Borrowings are at the discretion of Retailco. Advances thereunder accrue interest at an annual rate equal to the prime rate as published by the Wall Street Journal plus two percent (2.0%) from the date of the advance.

The Company has 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. The Company may pay interest and prepay principal on the Subordinated Debt Facility so long it is in compliance with the covenants under the Senior Credit Facility, is not in default under the Senior Credit Facility and has minimum availability of $5.0 million under the borrowing base under the Senior Credit Facility. Payment of principal and interest under the Subordinated Debt Facility is accelerated upon the occurrence of certain change of control or sale transactions.

As of June 30, 2022, and December 31, 2021, there were $20.0 million and zero, respectively, of outstanding borrowings under the Subordinated Debt Facility.

10. Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. Fair values are based on assumptions

that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. This includes the credit standing of counterparties involved and the impact of credit enhancements.

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

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

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

•Level 3—Unobservable inputs for the asset or liability, including situations where there is little, if any, observable market activity for the asset or liability.

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

Assets and Liabilities Measured at Fair Value on a Recurring Basis

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


	Level 1		Level 2		Level 3		Total
June 30, 2022
Non-trading commodity derivative assets	$	1,722	$	43,692	$	—	$	45,414
Trading commodity derivative assets	56		1,476		—		1,532
Total commodity derivative assets	$	1,778	$	45,168	$	—	$	46,946
Non-trading commodity derivative liabilities	$	—	$	(12,920)	$	—	$	(12,920)
Trading commodity derivative liabilities	—		(733)		—		(733)
Total commodity derivative liabilities	$	—	$	(13,653)	$	—	$	(13,653)


	Level 1		Level 2		Level 3		Total
December 31, 2021
Non-trading commodity derivative assets	$	104	$	4,038	$	—	$	4,142
Trading commodity derivative assets	—		128		—		128
Total commodity derivative assets	$	104	$	4,166	$	—	$	4,270
Non-trading commodity derivative liabilities	$	—	$	(3,236)	$	—	$	(3,236)
Trading commodity derivative liabilities	—		(958)		—		(958)
Total commodity derivative liabilities	$	—	$	(4,194)	$	—	$	(4,194)

We had no transfers of assets or liabilities between any of the above levels during the six months ended June 30, 2022 and the year ended December 31, 2021.

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, 2022 and December 31, 2021, the credit risk valuation adjustment was a reduction of derivative assets and liabilities, net of $0.1 million and $0.1 million, respectively.

11. Income Taxes

Income Taxes

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

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

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

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

As of June 30, 2022, we had a net deferred tax asset of $18.3 million, due in large part to the original step up in tax basis resulting from the initial purchase of Spark HoldCo units from NuDevco Retail and NuDevco Retail Holdings (predecessor to Retailco) in connection with our initial public offering.

The effective U.S. federal and state income tax rate for the three months ended June 30, 2022 and 2021 was 17.9% and 12.9%, respectively. The effective U.S. federal and state income tax rate for the six months ended June 30, 2022 and 2021 was 16.8% and (342.2)%, respectively. The effective tax rate for the three and six months ended June 30, 2022 differed from the U.S. federal statutory tax rate of 21% primarily due to state taxes and the benefit provided from Spark HoldCo operating as a limited liability company, which is treated as a partnership for federal and state income tax purposes and is not subject to federal and state income taxes. Accordingly, the portion of earnings attributable to non-controlling interest is subject to tax when reported as a component of the non-controlling interest holders' taxable income.

12. Commitments and Contingencies

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

Legal Proceedings

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

Consumer Lawsuits

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

Variable Rate Cases

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

In January 2022, the Company participated in mediation which covered three Spark brand matters: (1) Janet Rolland et al v. Spark Energy, LLC (D.N.J Apr. 2017); (2) Burger v. Spark Energy Gas, LLC (N.D. Ill. Dec. 2019); and (3) Local 901 v. Spark Energy, LLC (Sup. Ct. Allen County, Indiana Aug. 2019). The Company is working with an independent mediator to find a resolution to these cases, and the parties have suspended litigation pending a mutually agreed settlement. Given the ongoing mediation we cannot predict the outcome of these cases at this time.

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

Corporate Matter Lawsuits

Saul Horowitz, as Sellers’ Representative for the former owners of the Major Energy Companies v. National Gas & Electric, LLC (“NG&E”) and Spark Energy, Inc., was a lawsuit filed on October 17, 2017 in the United States District Court for the Southern District of New York related to the Company's purchase of Major Energy and structure of the earn-out in connection therewith ("Major Earn-Out Case") asserting claims of fraudulent inducement against NG&E, breach of contract against NG&E and Spark, and tortious interference with contract against Spark related to a membership interest purchase agreement, subsequent dropdown, and associated earnout agreements with the Major Energy Companies' former owners. On September 30, 2021, the Court held in favor of

the Company on all claims and entered judgment in favor of the Company to close this case. On October 29, 2021, plaintiffs filed a notice of appeal to the Second Circuit Court of Appeals.

On July 1, 2022, a stipulation of dismissal with prejudice was entered dismissing the appeal.

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

Regulatory Matters

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

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

New York. Prior to the purchase of Major Energy by the Company, in 2015, Major Energy Services, LLC and Major Energy Electric Services were contacted by the Attorney General, Bureau of Consumer Frauds & Protection for State of New York relating to their marketing practices. Major Energy has exchanged information in response to various requests from the Attorney General and recently agreed to respond to additional questions via remote proceedings in October of 2020. In January 2022, New York State Attorney General filed a complaint against Major Energy regarding the historical acts of Major Energy (a pre-acquisition matter). Via Renewables, Inc. was also named in the action due to current ownership. The Company has responded to the complaint. Given the current early stage of this regulatory matter, we cannot predict the outcome of this case at this time.

Pennsylvania. Verde Energy USA, Inc. (“Verde”) was the subject of a formal investigation by the Pennsylvania Public Utility Commission, Bureau of Investigation and Enforcement (“PPUC”) initiated on January 30, 2020. The investigation asserted that Verde may have violated Pennsylvania retail energy supplier regulations. The Company met with the PPUC in February 2020 to discuss the matter and to work with the PPUC cooperatively. Verde reached a settlement, which included payment of a civil penalty of $1.0 million and a $0.1 million contribution to the PPL hardship fund. On June 30, 2020, Verde and PPUC Bureau of Investigation and Enforcement filed a Joint Petition for Approval of Settlement and Statements in Support of that Joint Petition with the Commission. This settlement should be approved by December 2022.

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

Indirect Tax Audits

We are undergoing various types of indirect tax audits spanning from years 2018 to 2021 for which additional liabilities may arise. At the time of filing these consolidated financial statements, these indirect tax audits are at an

early stage and subject to substantial uncertainties concerning the outcome of audit findings and corresponding responses.

As of June 30, 2022 and December 31, 2021, we had accrued $9.7 million and $14.7 million, respectively, related to litigation and regulatory matters and $0.3 million and $0.7 million, respectively, related to indirect tax audits. The outcome of each of these may result in additional expense.

13. Transactions with Affiliates

Transactions with Affiliates

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

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


	June 30, 2022		December 31, 2021








Assets
Accounts Receivable - affiliates	$	5,709	$	3,819
Total Assets - affiliates	$	5,709	$	3,819


	June 30, 2022		December 31, 2021








Liabilities
Accounts Payable - affiliates	$	427	$	491
Subordinated Debt - affiliates (1)	20,000		—
Total Liabilities - affiliates	$	20,427	$	491

(1) The Subordinated Debt Facility allows us to draw advances in increments of no less than $1.0 million per advance up to the maximum principal amount of the Subordinated Debt Facility, subject to Retailco’s discretion. Advances thereunder accrue interest at an annual rate equal to the prime rate as published by the Wall Street Journal plus two percent (2.0%) from the date of the advance. See Note 9 "Debt" for a further description of terms and conditions of the Subordinated Debt Facility.

The following table presents revenues and cost of revenues recorded in net asset optimization revenue associated with affiliates for the periods indicated (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021			2022		2021









Revenue NAO - affiliates	$	626	$	224		$	1,577	$	569
Cost of Revenue NAO - affiliates	4		5			33		5

Net NAO - affiliates	$	622	$	219		$	1,544	$	564

Cost Allocations

Where costs incurred on behalf of the affiliate or us cannot be determined by specific identification for direct billing, the costs are allocated to the affiliated entities or us based on estimates of percentage of departmental usage, wages or headcount. The total net amount direct billed and allocated to/(from) affiliates was $1.5 million and $1.2 million for the three months ended June 30, 2022 and 2021, respectively. The total net amount direct billed and allocated to/(from) affiliates was $1.6 million and $0.4 million for the six months ended June 30, 2022 and 2021, respectively. The Company would have incurred incremental costs of $0.5 million and $0.3 million for the three months ended June 30, 2022 and 2021, respectively, operating on a stand-alone basis. The Company would have incurred incremental costs of $0.8 million and $0.6 million for the six months ended June 30, 2022 and 2021, respectively, operating on a stand-alone basis.

General and administrative costs of zero and less than $0.1 million were recorded for the three months ended June 30, 2022 and 2021, respectively and zero and $0.1 million for the six months ended June 30, 2022 and 2021, respectively. The general and administrative costs relate to telemarketing activities performed by an affiliate.

Distributions to and Contributions from Affiliates

During three months ended June 30, 2022 and 2021, Spark HoldCo made distributions to affiliates of our Founder of $3.6 million and $3.8 million, respectively, for the payments of quarterly distribution on their respective Spark HoldCo units. During each of the three months ended June 30, 2022 and 2021, Spark HoldCo also made distributions to these affiliates for gross-up distributions of zero, in connection with distributions made between Spark HoldCo and Via Renewables, Inc. for payment of income taxes incurred by us.

During the six months ended June 30, 2022 and 2021, Spark HoldCo made distributions to affiliates of our Founder of $7.2 million and $7.6 million, respectively, for the payments of quarterly distribution on their respective Spark HoldCo units. During the six months ended June 30, 2022 and 2021, Spark HoldCo also made distributions to these affiliates for gross-up distributions of $0.1 million and $2.7 million, respectively, in connection with distributions made between Spark HoldCo and Via Renewables, Inc. for payment of income taxes incurred by us.

14. Segment Reporting

Our determination of reportable business segments considers the strategic operating units under which we make financial decisions, allocate resources and assess performance of our business. Our reportable business segments are retail electricity and retail natural gas. The retail electricity segment consists of electricity sales and transmission to residential and commercial customers, and related services. 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, 2022 and 2021, we recorded asset optimization revenues of $18.6 million and $7.8 million and asset optimization cost of revenues of $19.8 million and $7.9 million, respectively, and for the six months ended June 30, 2022 and 2021, we recorded asset optimization revenues of $45.8 million and $33.5 million

and asset optimization cost of revenues of $48.0 million and $33.8 million, respectively, which are presented on a net basis in asset optimization revenues.

We use retail gross margin to assess the performance of our operating segments. We define retail gross margin as gross profit less (i) net asset optimization (expenses) revenues, (ii) net (losses) gains on non-trading derivative instruments, (iii) net current period cash settlements on non-trading derivative instruments, and (iv) gains (losses) from non-recurring events (including non-recurring market volatility).

We deduct net (losses) gains on non-trading derivative instruments, excluding current period cash settlements, from the retail gross margin calculation in order to remove the non-cash impact of net gains and losses on these derivative instruments. We deduct net gains (losses) from non-recurring events (including non-recurring market volatility) to ensure retail gross margin reflects operating performance that is not distorted by non-recurring events or extreme market volatility. Retail gross margin should not be considered an alternative to, or more meaningful than, gross profit, its most directly comparable financial measure calculated and presented in accordance with GAAP.

Below is a reconciliation of retail gross margin to gross profit (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Reconciliation of Retail Gross Margin to Gross Profit






Total Revenue	$	97,099	$	82,195	$	224,253	$	195,200
Less:
Retail cost of revenues	61,702		36,176		130,409		158,344
Gross Profit	35,397		46,019		93,844		36,856
Less:
Net asset optimization expense	(1,248)		(114)		(2,152)		(254)
Net, gain on non-trading derivative instruments	12,067		18,898		55,983		25,952
Net, Cash settlements on non-trading derivative instruments	(8,679)		795		(21,999)		(394)
Non-recurring event - Winter Storm Uri	9,565		—		9,565		(64,900)
Retail Gross Margin	$	23,692	$	26,440	$	52,447	$	76,452

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


Three Months Ended June 30, 2022
	Retail Electricity (a)		Retail Natural Gas		Corporate and Other		Eliminations		Consolidated
Total Revenues	$	82,290	$	16,057	$	(1,248)	$	—	$	97,099
Retail cost of revenues	50,116		11,586		—		—		61,702
Gross Profit	$	32,174	$	4,471	$	(1,248)	$	—	$	35,397
Less:
Net asset optimization expense	—		—		(1,248)		—		(1,248)
Net, gain on non-trading derivative instruments	11,608		459		—		—		12,067
Current period settlements on non-trading derivatives	(5,710)		(2,969)		—		—		(8,679)
Non-recurring event - Winter Storm Uri Credit	9,565		—		—		—		9,565
Retail Gross Margin	$	16,711	$	6,981	$	—	$	—	$	23,692
Total Assets at June 30, 2022	$	1,699,835	$	59,286	$	316,595	$	(1,726,899)	$	348,817
Goodwill at June 30, 2022	$	117,813	$	2,530	$	—	$	—	$	120,343

(a) Retail Electricity includes related services.


Three Months Ended June 30, 2021
	Retail Electricity		Retail Natural Gas		Corporate and Other		Eliminations		Consolidated
Total revenues	$	71,689	$	10,620	$	(114)	$	—	$	82,195
Retail cost of revenues	31,203		4,973		—		—		36,176
Gross Profit	$	40,486	$	5,647	$	(114)	$	—	$	46,019
Less:
Net asset optimization expense	—		—		(114)		—		(114)
Net, gain on non-trading derivative instruments	17,694		1,204		—		—		18,898
Current period settlements on non-trading derivatives	1,141		(346)		—		—		795

Retail Gross Margin	$	21,651	$	4,789	$	—	$	—	$	26,440
Total Assets at December 31, 2021	$	1,527,456	$	7,320	$	311,556	$	(1,491,056)	$	355,276
Goodwill at December 31, 2021	$	117,813	$	2,530	$	—	$	—	$	120,343


Six Months Ended June 30, 2022
	Retail Electricity		Retail Natural Gas		Corporate and Other		Eliminations		Consolidated
Total revenues	$	170,331	$	56,074	$	(2,152)	$	—	$	224,253
Retail cost of revenues	96,276		34,133		—		—		130,409
Gross Profit	$	74,055	$	21,941	$	(2,152)	$	—	$	93,844
Less:
Net asset optimization expense	—		—		(2,152)		—		(2,152)
Net gain on non-trading derivatives	47,847		8,136		—		—		55,983
Current period settlements on non-trading derivatives	(17,254)		(4,745)		—		—		(21,999)
Non-recurring event - Winter Storm Uri	9,565		—		—		—		9,565
Retail Gross Margin	$	33,897	$	18,550	$	—	$	—	$	52,447
Total Assets at June 30, 2022	$	1,699,835	$	59,286	$	316,595	$	(1,726,899)	$	348,817
Goodwill at June 30, 2022	$	117,813	$	2,530	$	—	$	—	$	120,343


Six Months Ended June 30, 2021
	Retail Electricity		Retail Natural Gas		Corporate and Other		Eliminations		Consolidated
Total revenues	$	150,444	$	45,010	$	(254)	$	—	$	195,200
Retail cost of revenues	138,727		19,617		—		—		158,344
Gross Profit	$	11,717	$	25,393	$	(254)	$	—	$	36,856
Less:
Net asset optimization expense	—		—		(254)		—		(254)
Net gain on non-trading derivatives	24,399		1,553		—		—		25,952
Current period settlements on non-trading derivatives	(47)		(347)		—		—		(394)
Non-recurring Winter	(64,900)		—		—		—		(64,900)
Retail Gross Margin	$	52,265	$	24,187	$	—	$	—	$	76,452
Total Assets at December 31, 2021	$	1,527,456	$	7,320	$	311,556	$	(1,491,056)	$	355,276
Goodwill at December 31, 2021	$	117,813	$	2,530	$	—	$	—	$	120,343

15. Customer Acquisitions

Acquisition of Customer Books

In May 2021, we entered into a series of asset purchase agreements and agreed to acquire up to approximately 56,900 RCEs for a cash purchase price of up to a maximum of $11.5 million. These customers began transferring in August 2021, and are located in our existing markets. As of June 30, 2022, a total of $6.8 million was paid for approximately 45,000 RCEs ($9.2 million for acquired customer contracts, net of $2.3 million related holdbacks under the terms of the purchase agreement). In addition, approximately $2.3 million was released back to us for a reduction in RCEs to be acquired.

As part of the acquisitions, we funded an escrow account, the balance of which is reflected as restricted cash in our consolidated balance sheet. As we acquire customers, we make payments to the sellers from the escrow account. As of June 30, 2022, the balance in the escrow account was $2.3 million, and these funds are expected to be released to the sellers as acquired customers transfer from the sellers to the Company in accordance with the asset purchase agreement, and any unallocated balance will be returned to the Company once the acquisition is complete.

In July 2021, we entered into an agreement to acquire up to approximately 50,000 RCEs and derivatives related to the customer load under a five-year contingent fee structure based on gas volume billed and collected for the acquired customer contracts. These customers began transferring in the fourth quarter of 2021, and are located in our existing markets. Due to the contingent fee structure, the cost of the RCEs will be recognized when probable and reasonably estimable.

Acquisition of Broker Books

In January 2022, we entered into an asset purchase agreement and agreed to acquire the rights to broker contracts for approximately 1,000 customer meters for a cash price of $0.4 million, which was paid upon execution of the contract.

In January 2022, we entered into an asset purchase agreement to acquire the rights to broker contracts for approximately 900 customer meters for a cash price of $0.6 million, pending certain conditions to close. We paid approximately $0.3 million as a deposit at the time the asset purchase agreement was executed. The conditions to close were met in June 2022, at which time approximately $0.3 million was paid to the seller.

16. Subsequent Events

Declaration of Dividends

On July 20, 2022, we declared a quarterly dividend of $0.18125 per share to holders of record of our Class A common stock on September 1, 2022, which will be paid on September 15, 2022.

On July 20, 2022, we also declared a quarterly cash dividend in the amount of $0.568125 per share to holders of record of the Series A Preferred Stock on October 3, 2022. The dividend will be paid on October 17, 2022.

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 2021 Form 10-K filed with the Securities and Exchange Commission (“SEC”) on March 3, 2022. Results of operations and cash flows for the three and six months ended June 30, 2022 are not necessarily indicative of results to be attained for any other period. See "Cautionary Note Regarding Forward-Looking Statements" and "Risk Factors."

Overview

We are an independent retail energy services company founded in 1999 that provides residential and commercial customers in competitive markets across the United States with an alternative choice for natural gas and electricity. We purchase our natural gas and electricity supply from a variety of wholesale providers and bill our customers monthly for the delivery of natural gas and electricity based on their consumption at either a fixed or variable price. Natural gas and electricity are then distributed to our customers by local regulated utility companies through their existing infrastructure. As of June 30, 2022, we operated in 102 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, 2022 and 2021, approximately 84% and 87%, respectively, of our retail revenues were derived from the sale of electricity.

•Retail Natural Gas Segment. In this segment, we purchase natural gas supply through physical and financial transactions with market counterparties and supply natural gas to residential and commercial consumers pursuant to fixed-price and variable-price contracts. For the three months ended June 30, 2022 and 2021, approximately 16% and 13%, respectively, of our retail revenues were derived from the sale of natural gas.

Recent Developments

Senior Credit Facility and Subordinated Debt Facility

On June 30, 2022, we entered into a Credit Agreement (the “Senior Credit Facility”), with Woodforest National Bank, as administrative agent, swing bank, swap bank, issuing bank, joint-lead arranger, sole bookrunner and syndication agent, BOKF, NA (d/b/a/ Bank of Texas), as joint-lead arranger and issuing bank, and the other financial institutions party thereto, which replaced our prior credit agreement. The Senior Credit Facility allows us to borrow up to $195.0 million on a revolving basis in the form of working capital loans, loans to fund acquisitions, swingline loans and letters of credit. The Senior Credit Facility expires on June 30, 2025. The Senior Credit Facility revised the Fixed Charge Coverage Ratio and Maximum Senior Secured Leverage Ratio under our prior credit agreement. Refer to Note 9 "Debt" for discussion of the material terms of our Senior Credit Facility.

In connection with entering into Senior Credit Facility, we entered into an amended and restated subordinated promissory note (the “Subordinated Debt Facility”), which allows us to draw advances in increments of no less than $1.0 million per advance up to $25.0 million through January 31, 2026. Borrowings are at the discretion of Retailco. Advances thereunder accrue interest at an annual rate equal to the prime rate as published by the Wall Street Journal plus two percent (2.0%) from the date of the advance. Refer to Note 9 "Debt" for discussion of the material terms of our Subordinated Debt Facility.

Winter Storm Uri Credit from ERCOT

In June 2022, we received $9.6 million from ERCOT related to PURA Subchapter N Securitization financing. We accounted for the proceeds received as the recovery of costs of sales and services from a vendor, reflected as a reduction of retail cost of revenues within our consolidated statements of operations for the quarter ended June 30, 2022, as that is where the initial costs compensated for were recorded.

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, 2022:


RCEs:
(In thousands)	March 31, 2022	Additions	Attrition	June 30, 2022	% Increase (Decrease)
Retail Electricity	275	11	29	257	(7)%
Retail Natural Gas	112	5	6	111	(1)%
Total Retail	387	16	35	368	(5)%



RCEs:
(In thousands)	December 31, 2021	Additions	Attrition	June 30, 2022	% Increase (Decrease)
Retail Electricity	298	25	66	257	(14)%
Retail Natural Gas	110	14	13	111	1%
Total Retail	408	39	79	368	(10)%

The following table details our count of RCEs by geographical location as of June 30, 2022:


RCEs by Geographic Location:
(In thousands)	Electricity	% of Total	Natural Gas	% of Total	Total	% of Total
New England	76	31%	14	13%	90	24%
Mid-Atlantic	94	37%	59	53%	153	42%
Midwest	24	9%	20	17%	44	12%
Southwest	63	23%	18	17%	81	22%
Total	257	100%	111	100%	368	100%

The geographical locations noted above include the following states:

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

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

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

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

Across our market areas, we have operated under a number of different retail brands. We currently operate under six retail brands.

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 Acquisition

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

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

During the three months ended June 30, 2022, we added approximately 16,000 RCEs primarily through our various organic sales channels. We expect to acquire customers organically in future periods but it will be slower in the near term, however we expect this number to increase on a monthly basis.

During the three months ended June 30, 2022, we did not add any RCEs as a result of asset purchase agreements. Our ability to realize returns from acquisitions that are acceptable to us is dependent on our ability to successfully identify, negotiate, finance and integrate acquisitions. We will continue to evaluate potential acquisitions during the remainder of 2022.

While we remain focused on organic sales and identifying customer portfolio and business acquisitions, we cannot ensure that our RCE count will remain at current levels or grow. Our RCE count, as well as the margins we earn on our customers, contribute to our overall profitability, cash flow and ability to pay dividends on our Class A common stock and Series A Preferred Stock.

Customer Acquisition Costs

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

We strive to maintain a disciplined approach to recovery of our customer acquisition costs within a 12-month period. We capitalize and amortize our customer acquisition costs over a two-year period, which is based on our estimate of the expected average length of a customer relationship. We factor in the recovery of customer acquisition costs in determining which markets we enter and the pricing of our products in those markets. Accordingly, our results are significantly influenced by our customer acquisition costs. Changes in customer acquisition costs from period to period reflect our focus on growing organically versus growth through acquisitions. We are currently focused on growing through organic sales channels; however, we continue to evaluate opportunities to acquire customers through acquisitions and pursue such acquisitions when it makes sense economically or strategically.

Customer Attrition

Customer attrition occurs primarily as a result of: (i) customer initiated switches; (ii) residential moves; (iii) disconnection resulting from customer payment defaults; and (iv) proactive non-renewal of contracts. Average monthly customer attrition for the three months ended June 30, 2022 and 2021 was 3.1% and 3.3%, respectively.

Our customer attrition was slightly lower than the prior year because of our pro-active non-renewal of some of the larger C&I customers in the prior year, which did not re-occur in 2022. Although customer attrition was slightly lower during the second quarter of 2022, we are unable to predict the ultimate impact on overall customer attrition over the remainder of the year, at this time.

Customer Credit Risk

Our bad debt expense for the three months ended June 30, 2022 and 2021 was 1.8% and 0.3%, respectively, and our bad debt expense for the six months ended June 30, 2022 and 2021 was 1.9% and (0.4)% respectively, for non-purchase of receivable market ("non-POR") revenues. As the Company has increased sales activities in non-POR markets in 2022, we have experienced an increase in bad debt expense during the three and six months ended June 30, 2022.

Gross Profit

The profit earned between the price we are able to charge customers for retail electricity and natural gas and the cost to serve customers is a key component of the results of our operations. Prices we are able to charge customers for retail electricity and natural gas vary with market conditions, and are subject to regulatory restrictions in many of the markets we serve. Costs to serve customers are tied closely to gas and power commodity markets, which exposes us to significant variability and uncertainties.

Weather Conditions

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

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

Winter Storm Uri

During the first quarter of 2021, the U.S. experienced Winter Storm Uri, an unprecedented storm bringing extreme cold temperatures to the central U.S., including Texas. As a result of increased power demand for customers across the state of Texas and power generation disruptions during the weather event, power and ancillary costs in the ERCOT service area reached or exceeded maximum allowed clearing prices. For the three months ended March 31, 2021, we recorded a net loss of approximately $64.4 million as a direct result of Winter Storm Uri. Although our hedge position was 120% of our forecasted demand in Texas for the month of February, we were still required to purchase power at unprecedented prices for an extended period of time during the storm. These price caps imposed by ERCOT for the duration of the storm and beyond have never been experienced in any deregulated market in which we serve. The policies imposed on the electricity markets by ERCOT related to pricing resulted in overall negative impact on our electricity unit margin for 2021.

Asset Optimization

Our asset optimization opportunities primarily arise during the winter heating season when demand for natural gas is typically at its highest. Given the opportunistic nature of these activities and because we account for these

activities using the mark to market method of accounting, we experience variability in our earnings from our asset optimization activities from year to year.

Net asset optimization resulted in a loss of $1.2 million and $0.1 million for the three months ended June 30, 2022 and 2021, respectively.

Non-GAAP Performance Measures

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


	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands)	2022		2021		2022		2021
Adjusted EBITDA (1)(2)	$	13,346	$	14,372	$	24,135	$	47,039
Retail Gross Margin (3)(4)	$	23,692	$	26,440	$	53,275	$	76,452

(1) Adjusted EBITDA for the six months ended June 30, 2021 includes a $60.0 million add back related to Winter Storm Uri. Adjusted EBITDA for the three and six months ended June 30, 2021 includes a deduction of $2.2 million related to a non-recurring legal settlement (recovery), the expense for which was added back in 2019.

(2) Adjusted EBITDA for the three and six months ended June 30, 2022 includes a deduction of $5.2 million related to proceeds received under an ERCOT (Winter Storm Uri) securitization mechanism in June 2022. See further discussion below.

(3) Retail Gross Margin for the six months ended June 30, 2021 includes a $64.9 million add back related to Winter Storm Uri. See discussion below.

(4) Retail Gross Margin for the three and six months ended June 30, 2022 includes a deduction of $9.6 million related to proceeds received under an ERCOT (Winter Storm Uri) securitization mechanism in June 2022. See further discussion below.

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

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

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

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

As our Senior Credit Facility is considered a material agreement and Adjusted EBITDA is a key component of our material covenants, we consider our covenant compliance to be material to the understanding of our financial condition and/or liquidity. Our lenders under our Senior Credit Facility allowed $60.0 million of the $64.9 million pre-tax storm loss incurred in the first quarter of 2021 to be added back as a non-recurring item in the calculation of Adjusted EBITDA for our Debt Covenant Calculations. We received a $0.4 million credit from ERCOT for winter storm related losses during the third quarter of 2021, resulting in a net pre-tax storm loss of $64.4 million for the year ended December 31, 2021. In June 2022, we received $9.6 million from ERCOT related to PURA Subchapter N Securitization financing. For consistent presentation of the financial impact of Winter Storm Uri, $5.2 million of

the $9.6 million is reflected as non-recurring items reducing Adjusted EBITDA for the three and six months ended June 30, 2022.

We believe that the presentation of Adjusted EBITDA provides information useful to investors in assessing our performance and results of operations and that Adjusted EBITDA is also useful for an understanding of our financial condition and/or liquidity due to its use in covenants in our Senior Credit Facility. Adjusted EBITDA is a supplemental financial measure that management and external users of our consolidated financial statements, such as industry analysts, investors, commercial banks and rating agencies, use to assess the following:

•our operating performance as compared to other publicly traded companies in the retail energy industry, without regard to financing methods, capital structure, historical cost basis and specific items not reflective of ongoing operations;

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

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

•our compliance with financial debt covenants. (Refer to Note 9 "Debt" to Part I, Item 1 of this Report for discussion of the material terms of our Senior Credit Facility, including the covenant requirements for our Minimum Fixed Charge Coverage Ratio, Maximum Total Leverage Ratio, and Maximum Senior Secured Leverage Ratio.)

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


	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands)	2022		2021		2022		2021
Reconciliation of Adjusted EBITDA to net income (loss):
Net income (loss)	$	12,534	$	24,796	$	43,560	$	(2,764)
Depreciation and amortization	4,936		5,413		10,120		11,449
Interest expense	1,820		1,552		3,127		2,863
Income tax expense	2,730		3,674		8,774		2,139
EBITDA	22,020		35,435		65,581		13,687
Less:
Net, gain on derivative instruments	12,397		18,904		57,460		25,928
Net cash settlements on derivative instruments	(8,708)		795		(21,844)		(390)
Customer acquisition costs	1,394		243		2,590		456
Plus:
Non-cash compensation expense	1,571		1,104		1,922		1,571
Non-recurring event - Winter Storm Uri	(5,162)		—		(5,162)		60,000
Non-recurring legal settlement	—		(2,225)		—		(2,225)
Adjusted EBITDA	$	13,346	$	14,372	$	24,135	$	47,039

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)	2022		2021		2022		2021
Reconciliation of Adjusted EBITDA to net cash provided by operating activities:
Net cash provided by operating activities	$	8,361	$	32,800	$	12,944	$	9,168
Amortization of deferred financing costs	(468)		(258)		(713)		(517)
Bad debt expense	(809)		(134)		(1,833)		113
Interest expense	1,820		1,552		3,127		2,863
Income tax expense	2,730		3,674		8,774		2,139
Non-recurring event - Winter Storm Uri	(5,162)		—		(5,162)		60,000

Non-recurring legal settlement	—		(2,225)		—		(2,225)
Changes in operating working capital
Accounts receivable, prepaids, current assets	(9,928)		(20,058)		(9,373)		(31,761)
Inventory	2,283		965		409		(400)
Accounts payable and accrued liabilities	15,221		8,059		20,798		12,857
Other	(702)		(10,003)		(4,836)		(5,198)
Adjusted EBITDA	$	13,346	$	14,372	$	24,135	$	47,039
Cash Flow Data:
Net cash provided by operating activities	$	8,361	$	32,800	$	12,944	$	9,168
Net cash used in investing activities	$	(1,562)	$	(543)	$	(5,160)	$	(1,063)
Net cash (used in) provided by financing activities	$	(15,056)	$	(9,208)	$	(37,581)	$	24,751

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

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

We have historically included the financial impact of weather variability in the calculation of Retail Gross Margin. We will continue this historical approach, but during the first quarter of 2021 we added back the $64.9 million net financial loss incurred related to Winter Storm Uri, as described above, in the calculation of Retail Gross Margin because the extremity of the Texas storm combined with the impact of unprecedented pricing mechanisms ordered by ERCOT is considered unusual, infrequent, and non-recurring in nature. In June 2022, we received $9.6 million from ERCOT related to PURA Subchapter N Securitization financing. The $9.6 million is reflected as a non-recurring item reducing Retail Gross Margin for the three and six months ended June 30, 2022 for consistent presentation of the financial impacts of Winter Storm Uri.

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


	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands)	2022		2021		2022		2021
Reconciliation of Retail Gross Margin to Gross Profit




Total Revenue	$	97,099	$	82,195	$	224,253	$	195,200
Less:
Retail cost of revenues	61,702		36,176		130,409		158,344
Gross Profit	35,397		46,019		93,844		36,856
Less:
Net asset optimization (expense) revenues	(1,248)		(114)		(2,152)		(254)
Gain on non-trading derivative instruments	12,067		18,898		55,983		25,952
Cash settlements on non-trading derivative instruments	(8,679)		795		(21,999)		(394)
Non-recurring event - Winter Storm Uri	9,565		—		9,565		(64,900)
Retail Gross Margin	$	23,692	$	26,440	$	52,447	$	76,452
Retail Gross Margin - Retail Electricity Segment (1)(2)	$	16,711	$	21,651	$	33,897	$	52,265
Retail Gross Margin - Retail Natural Gas Segment	$	6,981	$	4,789	$	18,550	$	24,187

(1) Retail Gross Margin - Retail Electricity Segment for the six months ended June 30, 2021 includes a $64.9 million add back related to Winter Storm Uri.

(2) Retail Gross Margin for the three and six months ended June 30, 2022 includes a deduction of $9.6 million related to proceeds received under an ERCOT (Winter Storm Uri) securitization mechanism in June 2022. See further discussion above.

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 gross profit. 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 gross profit, and are defined differently by different companies in our industry, our definition of Adjusted EBITDA and Retail Gross Margin may not be comparable to similarly titled measures of other companies.

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

Consolidated Results of Operations

Three and Six Months Ended June 30, 2022 Compared to Three and Six Months Ended June 30, 2021


(In Thousands)	Three Months Ended June 30,						Six Months Ended June 30,
	2022			2021			2022			2021
Revenues:
Retail revenues	$	98,347		$	82,309		$	226,405		$	195,454
Net asset optimization (expense) revenues	(1,248)			(114)			(2,152)			(254)
Total Revenues	97,099			82,195			224,253			195,200
Operating Expenses:
Retail cost of revenues	61,702			36,176			130,409			158,344
General and administrative expense	13,583			10,663			28,518			23,334
Depreciation and amortization	4,936			5,413			10,120			11,449
Total Operating Expenses	80,221			52,252			169,047			193,127
Operating income	16,878			29,943			55,206			2,073
Other (expense)/income:
Interest expense	(1,820)			(1,552)			(3,127)			(2,863)
Interest and other income	206			79			255			165
Total other expense	(1,614)			(1,473)			(2,872)			(2,698)
Income (loss) before income tax expense	15,264			28,470			52,334			(625)
Income tax expense	2,730			3,674			8,774			2,139
Net income (loss)	$	12,534		$	24,796		$	43,560		$	(2,764)
Other Performance Metrics:
Adjusted EBITDA (1) (2) (3)	$	13,346		$	14,372		$	24,135		$	47,039
Retail Gross Margin (1) (4) (5)	$	23,692		$	26,440		$	53,275		$	76,452
Customer Acquisition Costs	$	1,394		$	243		$	2,590		$	456
Average Monthly RCE Attrition	3.1		%	3.3		%	3.4		%	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.

(2) Adjusted EBITDA for six months ended June 30, 2021 includes a $60.0 million add back related to Winter Storm Uri and Adjusted EBITDA for three and six months ended June 30,2021 includes a deduction of $2.2 million non-recurring legal settlement related to an add back in 2019.

(3) Adjusted EBITDA for the three and six months ended June 30, 2022 includes a deduction of $5.2 million non-recurring credit related to Winter Storm Uri add back in 2021.

(4) Retail Gross Margin for the six months ended June 30, 2021 includes a $64.9 million add back related to Winter Storm Uri.

(5) Retail Gross Margin for the three and six months ended June 30, 2022 includes a deduction of $9.6 million non-recurring credit related to Winter Storm Uri add back in 2021.

Three Months Ended June 30, 2022 Compared to Three Months Ended June 30, 2021

Total Revenues. Total revenues for the three months ended June 30, 2022 were approximately $97.1 million, an increase of approximately $14.9 million, or 18%, from approximately $82.2 million for the three months ended June 30, 2021, as indicated in the table below (in millions). This increase was primarily due to higher natural gas volumes sold as a result of larger natural gas customer book, and an increase in electricity rates unit revenue per MWh in the second quarter of 2022 as compared to the second quarter of 2021.


Change in electricity volumes sold	$	(1.2)
Change in natural gas volumes sold	5.7
Change in electricity unit revenue per MWh	11.8

Change in natural gas unit revenue per MMBtu	(0.3)
Change in net asset optimization revenue	(1.1)
Change in total revenues	$	14.9

Retail Cost of Revenues. Total retail cost of revenues for the three months ended June 30, 2022 was approximately $61.7 million, an increase of approximately $25.5 million, or 70%, from approximately $36.2 million for the three months ended June 30, 2021, as indicated in the table below (in millions). This increase was primarily due to higher electricity costs and a change in the fair value of our derivative portfolio in the second quarter of 2022 as compared to first quarter of 2021, partially offset by Winter Storm Uri credit from ERCOT in the second quarter of 2022.


Change in electricity volumes sold	$	(0.9)
Change in natural gas volumes sold	3.1
Change in electricity unit cost per MWh	16.5
Change in electricity unit cost per MWh - Winter Storm Uri	(9.6)
Change in natural gas unit cost per MMBtu	—
Change in value of retail derivative portfolio	16.4
Change in retail cost of revenues	$	25.5

General and Administrative Expense. General and administrative expense for the three months ended June 30, 2022 was approximately $13.6 million, an increase of approximately $2.9 million, or 27%, as compared to $10.7 million for the three months ended June 30, 2021. This increase was primarily attributable to higher employee costs and increased bad debt expense.

Depreciation and Amortization Expense. Depreciation and amortization expense for the three months ended June 30, 2022 was approximately $4.9 million, a decrease of approximately $0.5 million, or 9%, from approximately $5.4 million for the three months ended June 30, 2021. 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, 2022 was approximately $1.4 million, an increase of $1.2 million, or 600%, from approximately $0.2 million for the three months ended June 30, 2021 primarily due to increased sales activity in the second quarter of 2022 as compared to second quarter of 2021. The low customer acquisition cost in 2021 was primarily due to limitation on our ability to use door-to-door marketing as a result of COVID-19 and a reduction in targeted organic customer acquisitions as we focused our efforts to improve our organic sales channels, including vendor selection and sales quality.

Six Months Ended June 30, 2022 Compared to Six Months Ended June 30, 2021

Total Revenues. Total revenues for the six months ended June 30, 2022 were approximately $224.3 million, an increase of approximately $29.1 million, or 15%, from approximately $195.2 million for the six months ended June 30, 2021, as indicated in the table below (in millions). This increase was primarily due to a higher natural gas volumes sold as a result of larger natural gas customer book, and an increase in electricity unit revenue per MWh in 2022 as compared to 2021.


Change in electricity volumes sold	$	6.4
Change in natural gas volumes sold	13.3
Change in electricity unit revenue per MWh	14.4
Change in electricity unit revenue per MMBtu - Winter Storm Uri	(0.9)
Change in natural gas unit revenue per MMBtu	(2.2)
Change in net asset optimization revenue (expense)	(1.9)
Change in total revenues	$	29.1

Retail Cost of Revenues. Total retail cost of revenues for the six months ended June 30, 2022 was approximately $130.4 million, a decrease of approximately $27.9 million, or 18%, from approximately $158.3 million for the six months ended June 30, 2021, as indicated in the table below (in millions). This decrease was primarily due to electricity supply costs related to winter storm Uri in 2021 that did not re-occur in 2022 and winter storm Uri credit received from ERCOT in 2022, partially offset by increase in electricity supply costs due to higher commodity price environment in 2022.


Change in electricity volumes sold	$	4.1
Change in natural gas volumes sold	6.1
Change in electricity unit cost per MWh	35.2
Change in electricity unit cost per MWh - Winter Storm Uri	(75.4)
Change in natural gas unit cost per MMBtu	10.6
Change in value of retail derivative portfolio	(8.5)
Change in retail cost of revenues	$	(27.9)

General and Administrative Expense. General and administrative expense for the six months ended June 30, 2022 was approximately $28.5 million, an increase of approximately $5.2 million, or 22%, as compared to $23.3 million for the six months ended June 30, 2021. This increase was primarily attributable to higher employee costs and higher bad debt expense.

Depreciation and Amortization Expense. Depreciation and amortization expense for the six months ended June 30, 2022 was approximately $10.1 million, a decrease of approximately $1.3 million, or 11%, from approximately $11.4 million for the six months ended June 30, 2021. 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, 2022 was approximately $2.6 million, an increase of approximately $2.1 million, or 420%, from approximately $0.5 million for the six months ended June 30, 2021. The low customer acquisition cost in 2021 was primarily due to limitation on our ability to use door-to-door marketing as a result of COVID-19 and a reduction in targeted organic customer acquisitions as we focused our efforts to improve our organic sales channels, including vendor selection and sales quality.

Operating Segment Results


(in thousands, except volume and per unit operating data)	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021

Retail Electricity Segment
Total Revenues	$	82,290	$	71,689	$	170,331	$	150,444
Retail Cost of Revenues	50,116		31,203		96,276		138,727

Less: Net gain on non-trading derivatives, net of cash settlements	5,898		18,835		30,593		24,352
Non-recurring event - Winter Storm Uri	9,565		—		9,565		(64,900)
Retail Gross Margin (1) — Electricity	$	16,711	$	21,651	$	33,897	$	52,265
Volumes — Electricity (MWhs) (3)	603,497		614,000		1,288,649		1,236,127
Retail Gross Margin (2) (4) — Electricity per MWh	$	27.69	$	35.26	$	26.30	$	42.28

Retail Natural Gas Segment
Total Revenues	$	16,057	$	10,620	$	56,074	$	45,010
Retail Cost of Revenues	11,586		4,973		34,133		19,617

Less: Net (loss) gain on non-trading derivatives, net of cash settlements	(2,510)		858		3,391		1,206
Retail Gross Margin (1) — Gas	$	6,981	$	4,789	$	18,550	$	24,187
Volumes — Gas (MMBtus)	1,943,494		1,268,051		6,600,612		5,097,525
Retail Gross Margin (2) — Gas per MMBtu	$	3.59	$	3.78	$	2.81	$	4.75

(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 its most directly comparable financial measures presented in accordance with GAAP.

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

(3) Excludes volumes (8,402 MWhs) related to Winter Storm Uri impact for the six months ended June, 30, 2021.

(4) Retail Gross Margin - Electricity per MWh excludes Winter Storm Uri impact for the six months ended June 30, 2021.

Three Months Ended June 30, 2022 Compared to Three Months Ended June 30, 2021

Retail Electricity Segment

Total revenues for the Retail Electricity Segment for the three months ended June 30, 2022 were approximately $82.3 million, an increase of approximately $10.6 million, or 15%, from approximately $71.7 million for the three months ended June 30, 2021. This increase was largely due to higher retail electricity prices, which resulted in an increase of $11.8 million, offset by decrease in electricity volume of $1.2 million.

Retail cost of revenues for the Retail Electricity Segment for the three months ended June 30, 2022 were approximately $50.1 million, an increase of approximately $18.9 million, or 61%, from approximately $31.2 million for the three months ended June 30, 2021. This increase was primarily due to an increase in supply costs of $16.5 million, offset by an increase in volume due to smaller customer book, resulting in an decrease of $0.9 million, a decrease in supply cost of $9.6 million related to winter storm Uri in credit received in 2022, and a change in the value of our retail derivative portfolio used for hedging, which resulted in an increase of $12.9 million.

Retail gross margin for the Retail Electricity Segment for the three months ended June 30, 2022 was approximately $16.7 million, a decrease of approximately $5.0 million, or 23%, from approximately $21.7 million for the three months ended June 30, 2021, as indicated in the table below (in millions).


Change in volumes sold	$	(0.5)

Change in unit margin per MWh	(4.5)

Change in retail electricity segment retail gross margin	$	(5.0)

Retail Natural Gas Segment

Total revenues for the Retail Natural Gas Segment for the three months ended June 30, 2022 were approximately $16.0 million, an increase of approximately $5.4 million, or 51%, from approximately $10.6 million for the three months ended June 30, 2021. This increase was primarily attributable to higher volumes sold, which increased total revenues by $5.7 million offset by a decrease of $0.3 million related to lower natural gas rates.

Retail cost of revenues for the Retail Natural Gas Segment for the three months ended June 30, 2022 were approximately $11.6 million, an increase of $6.6 million, or 132%, from approximately $5.0 million for the three months ended June 30, 2021. This increase was primarily due to higher volumes resulting in an increase of $3.1 million, and a change in the value of our derivative portfolio used for hedging, which resulted in an increase of $3.5 million.

Retail gross margin for the Retail Natural Gas Segment for the three months ended June 30, 2022 was approximately $7.0 million, an increase of approximately $2.2 million, or 46%, from approximately $4.8 million for the three months ended June 30, 2021, as indicated in the table below (in millions).


Change in volumes sold	$	2.6
Change in unit margin per MMBtu	(0.4)
Change in retail natural gas segment retail gross margin	$	2.2

Six Months Ended June 30, 2022 Compared to Six Months Ended June 30, 2021

Retail Electricity Segment

Total revenues for the Retail Electricity Segment for the six months ended June 30, 2022 were approximately $170.3 million, an increase of approximately $19.9 million, or 13%, from approximately $150.4 million for the six months ended June 30, 2021. This increase was largely due to an increase in volumes, resulting in an increase of $6.4 million. This was partially offset by higher revenue rates which resulted in an increase of $14.4 million and a decrease of $0.9 million related to electricity revenue due to winter storm Uri in 2021 that did not re-occur in 2022.

Retail cost of revenues for the Retail Electricity Segment for the six months ended June 30, 2022 was approximately $96.3 million, a decrease of approximately $42.4 million, or 31%, from approximately $138.7 million for the six months ended June 30, 2021. This decrease was primarily due to a decrease in supply costs of $75.4 million related to winter storm Uri in 2021 that did not re-occur in 2022, a credit of $9.6 million related to winter storm Uri received in 2022 from ERCOT, and a decrease of $6.3 million due to a change in the value of our retail derivative portfolio used for hedging. This was offset by an increase in electricity costs of $35.2 million due to higher commodity price environment in 2022 and higher electricity volumes sold resulting in an increase of $4.1 million.

Retail gross margin for the Retail Electricity Segment for the six months ended June 30, 2022 was approximately $33.9 million, a decrease of approximately $18.4 million, or 35%, from approximately $52.3 million for the six months ended June 30, 2021, as indicated in the table below (in millions).


Change in volumes sold	$	(0.5)
Change in gross margin - Winter Storm Uri	(64.9)
Change in unit margin per MWh	47.0
Change in retail electricity segment retail gross margin	$	(18.4)

Retail Natural Gas Segment

Total revenues for the Retail Natural Gas Segment for the six months ended June 30, 2022 were approximately $56.1 million, an increase of approximately $11.1 million, or 25%, from approximately $45.0 million for the six months ended June 30, 2021. This increase was primarily attributable to an increase in volumes of $13.3 million, partially offset by lower rates, which resulted in a decrease in total revenues of $2.2 million.

Retail cost of revenues for the Retail Natural Gas Segment for the six months ended June 30, 2022 was approximately $34.1 million, an increase of approximately $14.5 million, or 74%, from approximately $19.6 million for the six months ended June 30, 2021. The increase of $6.1 million was related to higher volumes and an increase of $10.6 million was related to higher supply costs. This was offset by $2.2 million due to a change in the value of our derivative portfolio used for hedging.

Retail gross margin for the Retail Natural Gas Segment for the six months ended June 30, 2022 was approximately $18.6 million, a decrease of approximately $5.6 million, or 23%, from approximately $24.2 million for the six months ended June 30, 2021, as indicated in the table below (in millions).


Change in volumes sold	$	7.0
Change in unit margin per MMBtu	(12.6)
Change in retail natural gas segment retail gross margin	$	(5.6)

Liquidity and Capital Resources

Overview

Our primary sources of liquidity are cash generated from operations and borrowings under our Senior Credit Facility. Our principal liquidity requirements are to meet our financial commitments, finance current operations, fund organic growth and/or acquisitions, service debt and pay dividends. Our liquidity requirements fluctuate with our customer count, 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. Estimating our liquidity requirements is highly dependent on then-current market conditions, forward prices for natural gas and electricity, market volatility and our then existing capital structure and requirements.

We believe that cash generated from operations and our available liquidity sources will be sufficient to sustain current operations and to pay required taxes. Our ability to pay dividends to the holders of the Class A common stock and the Series A Preferred Stock in the future will ultimately depend on our RCE count, margins, profitability and cash flow, and the covenants under our Senior Credit Facility, which we are unable to predict at this time.

Liquidity Position

The following table details our available liquidity as of June 30, 2022:


($ in thousands)	June 30, 2022
Cash and cash equivalents	$	43,196
Senior Credit Facility Availability (1)	22,914

Subordinated Debt Facility Availability (2)	5,000
Total Liquidity	$	71,110

(1) Reflects amount of Letters of Credit that could be issued based on existing covenants as of June 30, 2022.

(2) The availability of the Subordinated Facility is dependent on our Founder's discretion. See "—Sources of Liquidity —Subordinated Debt Facility."

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

Cash Flows

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


	Six Months Ended June 30,
	2022		2021
Net cash provided by operating activities	$	12,944	$	9,168
Net cash used in investing activities	$	(5,160)	$	(1,063)
Net cash (used in) provided by financing activities	$	(37,581)	$	24,751

Six Months Ended June 30, 2022 Compared to the Six Months Ended June 30, 2021

Cash Flows Provided by Operating Activities. Cash flows provided by operating activities for the six months ended June 30, 2022 increased by $3.8 million compared to the six months ended June 30, 2021. The increase was primarily the result of higher net income in 2022 coupled with other changes in working capital for the six months ended June 30, 2022, non-recurring Winter Storm Uri related costs of $64.9 million for the six months ended June

30, 2021, which did not re-occur in 2022, and $9.6 million credit received in for the six months ended June 30, 2022 from ERCOT related to winter storm Uri.

Cash Flows Used in Investing Activities. Cash flows used in investing activities increased by $4.1 million for the six months ended June 30, 2022. The increase was primarily the result of increases relating to customer acquisitions during the six months ended June 30, 2022.

Cash Flows Used in Financing Activities. Cash flows used in financing activities increased by $62.3 million for the six months ended June 30, 2022, primarily due to an increase in net paydown of our Senior Credit Facility of $75.0 million, offset by an increase in sub-debt borrowing of $10.0 million during the six months ended June 30, 2022.

Sources of Liquidity and Capital Resources

Senior Credit Facility

On June 30, 2022, we entered into the Senior Credit Facility, with Woodforest National Bank, as administrative agent, swing bank, swap bank, issuing bank, joint-lead arranger, sole bookrunner and syndication agent, BOKF, NA (d/b/a/ Bank of Texas), as joint-lead arranger and issuing bank, and the other financial institutions party thereto, which replaced our prior credit agreement. The Senior Credit Facility allows us to borrow up to $195.0 million on a revolving basis in the form of working capital loans, loans to fund acquisitions, swingline loans and letters of credit. The Senior Credit Facility expires on June 30, 2025. The Senior Credit Facility revised the Fixed Charge Coverage Ratio and Maximum Senior Secured Leverage Ratio under our prior credit agreement.

As of June 30, 2022, we had total commitments of $195.0 million under the Senior Credit Facility, of which $127.1 million was outstanding, including $32.1 million of outstanding letters of credit.

For a description of the terms and conditions of our Senior Credit Facility, including descriptions of the interest rate, commitment fee, covenants and terms of default, please see Note 9 "Debt" in the notes to our condensed consolidated financial statements.

As of June 30, 2022, we were in compliance with the covenants under our Senior Credit Facility. Based upon existing covenants as of June 30, 2022, we had availability to borrow up to $22.9 million under the Senior Credit Facility.

The covenants under our Senior Credit Facility impact our ability to pay dividends on our Class A common stock and Series A Preferred Stock.

Amended and Restated Subordinated Debt Facility

In connection with entering into the Senior Credit Facility, we entered into an amended and restated subordinated promissory note (the “Subordinated Debt Facility”), which allows us to draw advances in increments of no less than $1.0 million per advance up to $25.0 million through January 31, 2026. Borrowings are at the discretion of Retailco. Advances thereunder accrue interest at an annual rate equal to the prime rate as published by the Wall Street Journal plus two percent (2.0%) from the date of the advance.

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. As of June 30, 2022, there was $20.0 million outstanding borrowings under the Subordinated Debt Facility, and availability to borrow up to $5.0 million under the Subordinated Debt Facility. See Note 9 "Debt" for further information regarding the Subordinated Debt Facility.

Uses of Liquidity and Capital Resources

Repayment of Current Portion of Senior Credit Facility

Our Senior Credit Facility matures in June 2025, 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, 2022 was $95.0 million. The current variable interest rate on the facility at June 30, 2022 was 5.04%.

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, 2022 and 2021, we spent a total of $1.4 million and $0.2 million, respectively, on organic customer acquisitions.

Capital Expenditures

Our capital requirements each year are relatively low and generally consist of minor purchases of equipment or information system upgrades and improvements. Capital expenditures for the six months ended June 30, 2022 and 2021 included $1.1 million and $1.1 million, respectively, related to information systems improvements.

Dividends and Distributions

During the six months ended June 30, 2022, we paid dividends to holders of our Class A common stock for the quarters ended December 31, 2021 and March 31, 2022 of $0.18125 per share or $5.7 million in the aggregate. In order to pay our stated dividends to holders of our Class A common stock, our subsidiary, Spark HoldCo is required to make corresponding distributions to holders of Class B common stock (our non-controlling interest holders). As a result, during the six months ended June 30, 2022, Spark HoldCo made distributions of $7.2 million to our non-controlling interest holders related to the dividend payments to holders of our Class A common stock.

For the six months ended June 30, 2022, we paid $3.9 million of dividends to holders of our Series A Preferred Stock, and as of June 30, 2022, we had accrued $1.7 million related to dividends to holders of our Series A Preferred Stock, which we paid on July 15, 2022. On and after April 15, 2022, the Series A Preferred Stock will accrue dividends at an annual rate equal to the sum of (a) Three-Month LIBOR (if it then exists), or an alternative reference rate as of the applicable determination date and (b) 6.578%, based on the $25.00 liquidation preference per share of the Series A Preferred Stock. For the full year ended December 31, 2022, taking into consideration the amount of dividends already paid and estimating future dividends using the stated most recent dividend rate paid on the Series A Preferred Stock, we would be required to pay dividends of $7.7 million in the aggregate based on the Series A Preferred Stock outstanding as of June 30, 2022.

On July 20, 2022, our Board of Directors declared a quarterly cash dividend in the amount of $0.18125 per share to holders of our Class A common stock and $0.568125 per share for the Series A Preferred Stock for the second quarter of 2022. Dividends on Class A common stock will be paid on September 15, 2022 to holders of record on September 1, 2022, and Series A Preferred Stock dividends will be paid on October 17, 2022 to holders of record on October 3, 2022.

Our future dividend policy is within the discretion of our Board of Directors, and will depend upon our operations, our financial condition, capital requirements and investment opportunities, the performance of our business, cash flows, RCE counts and the margins we receive, as well as restrictions under our Senior Credit Facility. The Board of Directors may be required to reduce or eliminate quarterly cash distributions, including the quarterly dividends to the holders of the Class A common stock and/or Series A Preferred Stock. Even if we are permitted to pay such dividends on the Class A common stock and Series A Preferred Stock, our Board of Directors may elect to reduce or eliminate the dividends on the Class A common stock and Series A Preferred Stock to maintain cash balances for operations or for other reasons. Similarly, even if our business generates cash in excess of our current annual dividend, we may reinvest such excess cash flows in our business and not increase the dividends payable to holders of our Class A common stock.

Off-Balance Sheet Arrangements

As of June 30, 2022, we had no material "off-balance sheet arrangements."

Related Party Transactions

For a discussion of related party transactions, see Note 13 "Transactions with Affiliates" to Part I, Item 1 of this Report.

Critical Accounting Policies and Estimates

Our critical accounting policies and estimates are described in “Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” in our 2021 Form 10-K. There have been no changes to these policies and estimates since the date of our 2021 Form 10-K.

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

Contingencies

In the ordinary course of business, we may become party to lawsuits, administrative proceedings and governmental investigations, including regulatory and other matters. Except as described in Note 12 "Commitments and Contingencies" to Part I, Item 1 of this Report, as of June 30, 2022, management did not believe that any of our outstanding lawsuits, administrative proceedings or investigations could result in a material adverse effect. Liabilities for loss contingencies arising from claims, assessments, litigation, fines, penalties and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. For a discussion of the status of current legal and regulatory matters, see Note 12 "Commitments and Contingencies" to Part I, Item 1 of this Report.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Commodity Price Risk

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

Our net gain/(loss) on our non-trading derivative instruments, net of cash settlements, was $3.4 million and $19.7 million for three months ended June 30, 2022 and 2021 and $34.0 million and $25.6 million for the six months ended June 30, 2022 and 2021, 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 2021 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, 2022, our Gas Non-Trading Fixed Price Open Position (hedges net of retail load) was a short position of 202,073 MMBtu. An increase of 10% in the market prices (NYMEX) from their June 30, 2022 levels would have decreased the fair market value of our net non-trading energy portfolio by less than $0.1 million. Likewise, a decrease of 10% in the market prices (NYMEX) from their June 30, 2022 levels would have increased the fair market value of our non-trading energy derivatives by less than $0.1 million. As of June 30, 2022, our Electricity Non-Trading Fixed Price Open Position (hedges net of retail load) was a long position of 351,401 MWhs. An increase of 10% in the forward market prices from their June 30, 2022 levels would have increased the fair market value of our net non-trading energy portfolio by $3.0 million. Likewise, a decrease of 10% in the forward market prices from their June 30, 2022 levels would have decreased the fair market value of our non-trading energy derivatives by $3.0 million.

Credit Risk

In many of the utility services territories where we conduct business, Purchase of Receivables ("POR programs") have been established, whereby the local regulated utility purchases our receivables, and becomes responsible for billing the customer and collecting payment from the customer. These POR programs result in substantially all of our credit risk being with the utility and not to our end-use customers in these territories. Approximately 57% and 56% 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, 2022 and 2021 and 61% and 60% for the six months ended June 30, 2022 and 2021, respectively, all of which had investment grade ratings as of such date. We paid these local regulated utilities a weighted average discount of 0.9%, for both the three months ended June 30,

2022 and 2021 and 1.0% and 0.8% for the six months ended June 30, 2022 and 2021, 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 as we will have already fully hedged the customer’s expected commodity usage for the life of the contract.

In non-POR markets (and in POR markets where we may choose to direct bill our customers), we manage customer credit risk through formal credit review in the case of commercial customers, and credit score screening, deposits and disconnection for non-payment, in the case of residential customers. Economic conditions 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, 2022 and 2021 was 1.8% and 0.3% of non-POR market retail revenues, respectively and our bad debt expense for the six months ended June 30, 2022 and 2021 was 1.9% and (0.4)% 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, 2022.

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, 2022, approximately $14.6 million of our total exposure of $36.9 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, 2022.

Interest Rate Risk

We are exposed to fluctuations in interest rates under our variable-price debt obligations, including our Senior Credit Facility and our Series A Preferred Stock.

At June 30, 2022, we were co-borrowers under the Senior Credit Facility, under which $95.0 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, 2022, a 1.0% increase in interest rates would have resulted in additional annual interest expense of approximately $1.0 million.

On and after April 15, 2022, our Series A Preferred Stock accrue dividends at an annual rate equal to the sum of (a) Three-Month LIBOR (if it then exists), or an alternative reference rate as of the applicable determination date and (b) 6.578%, based on the $25.00 liquidation preference per share of the Series A Preferred Stock. On July 20, 2022, our Board of Directors declared a quarterly cash dividend in the amount of $0.568125 per share for the Series A Preferred Stock for the second quarter of 2022 for an aggregate amount of $2.0 million for the quarter. Based on the Series A Preferred Stock outstanding on June 30, 2022, a 1.0% increase in interest rates would have resulted in additional dividends of less than $0.1 million for the quarter.

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. Based on this evaluation, management concluded that our disclosure controls and procedures were effective as of June 30, 2022.

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, 2022 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

See Note 12 "Commitments and Contingencies" to Part I, Item 1 of this Report, which is incorporated by reference into this Part II, Item 1, for a description of certain ligation, legal proceedings, and regulatory matters.

Item 1A. Risk Factors.

Security holders and potential investors in our securities should carefully consider the risk factors under "Item 1A— Risk Factors" in our 2021 Form 10-K. Except as described below, there has been no material change in our risk factors from those described in the 2021 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.

Our ability to pay dividends in the future will depend on many factors, including the performance of our business, cash flows, RCE counts and the margins we receive, as well as restrictions under our Senior Credit Facility.

We cannot assure you that we will be able to continue paying our targeted quarterly dividend to the holders of our Class A common stock or dividends to the holders of our Series A Preferred Stock in the future. The amount of our cash available for distribution principally depends upon the amount of cash we generate from our operations, which fluctuates from quarter to quarter based on, among other things:

•changes in commodity prices, which may be driven by a variety of factors, including, but not limited to, weather conditions, seasonality and demand for energy commodities and general economic conditions;

•our RCE count and the margins we receive;

•the level and timing of customer acquisition costs we incur;

•the level of our operating and general and administrative expenses;

•seasonal variations in revenues generated by our business;

•our debt service requirements and other liabilities;

•fluctuations in our working capital needs;

•our ability to borrow funds and access capital markets;

•restrictions contained in our debt agreements (including our Senior Credit Facility);

•management of customer credit risk;

•abrupt changes in regulatory policies; and,

•other business risks affecting our cash flows.

As a result of these and other factors, we cannot guarantee that we will have sufficient cash generated from operations to pay the dividends on our Series A Preferred Stock or to pay a specific level of cash dividends to holders of our Class A common stock. Further, we could be prevented from paying cash dividends under Delaware law if certain capital requirements are not met, and may be further restricted by covenants in our Senior Credit Facility.

The amount of cash available for distribution depends primarily on our cash flow, and is not solely a function of profitability, which is affected by non-cash items. We may incur other expenses or liabilities during a period that could significantly reduce or eliminate our cash available for distribution and, in turn, impair our ability to pay dividends to holders of our Class A common stock and Series A Preferred Stock during the period. Additionally, the dividends paid on Series A Preferred Stock reduce the amount of cash we have available to pay dividends on our Class A common stock.

Each new share of Class A common stock and Series A Preferred Stock issued increases the cash required to continue to pay cash dividends. Any Class A common stock or preferred stock (whether Series A Preferred Stock or a new series of preferred stock) that may in the future be issued to finance acquisitions, upon exercise of stock options or otherwise, would have a similar effect.

Finally, our future dividend policy is within the discretion of our Board of Directors, and will depend upon our operations, our financial condition, capital requirements and investment opportunities, the performance of our business, cash flows, RCE counts and the margins we receive, as well as restrictions under our Senior Credit Facility. The Board of Directors may be required to reduce or eliminate quarterly cash distributions, including the quarterly dividends to the holders of the Class A common stock and/or Series A Preferred Stock. Even if we are permitted to pay such dividends on the Class A common stock and Series A Preferred Stock, our Board of Directors may elect to reduce or eliminate the dividends on the Class A common stock and Series A Preferred Stock to maintain cash balances for operations or for other reasons. Similarly, even if our business generates cash in excess of our current annual dividend, we may reinvest such excess cash flows in our business and not increase the dividends payable to holders of our Class A common stock. Any reduction or elimination of cash dividends on our Class A common stock or Series A Preferred Stock will likely materially and adversely affect the price of the Class A common stock and Series A Preferred Stock.

Item 6. Exhibits

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

INDEX TO EXHIBITS

Incorporated by Reference

Exhibit

Exhibit Description

Form

Exhibit Number

Filing Date

SEC File No.

2.1#

Membership Interest Purchase Agreement, by and among Spark Energy, Inc., Spark HoldCo, LLC, Provider Power, LLC, Kevin B. Dean and Emile L. Clavet, dated as of May 3, 2016.

10-Q

2.1

5/5/2016

001-36559

2.2#

Membership Interest Purchase Agreement, by and among Spark Energy, Inc., Spark HoldCo, LLC, Retailco, LLC and National Gas & Electric, LLC, dated as of May 3, 2016.

10-Q

2.2

5/5/2016

001-36559

2.3#

Amendment No. 1 to the Membership Interest Purchase Agreement, dated as of July 26, 2016, by and among Spark Energy, Inc., Spark HoldCo, LLC, Provider Power, LLC, Kevin B. Dean and Emile L. Clavet.

8-K

2.1

8/1/2016

001-36559

2.4#

Membership Interest and Stock Purchase Agreement, by and among Spark Energy, Inc., CenStar Energy Corp. and Verde Energy USA Holdings, LLC, dated as of May 5, 2017.

10-Q

2.4

5/8/2017

001-36559

2.5

First Amendment to the Membership Interest and Stock Purchase Agreement, dated July 1, 2017, by and among Spark Energy, Inc., CenStar Energy Corp., and Verde Energy USA Holdings, LLC.

8-K

2.1

7/6/2017

001-36559

2.6#

Agreement to Terminate Earnout Payments, effective January 12, 2018, by and among Spark Energy, Inc., CenStar Energy Corp., Woden Holdings, LLC (fka Verde Energy USA Holdings, LLC), Verde Energy USA, Inc., Thomas FitzGerald, and Anthony Menchaca.

8-K

2.1

1/16/2018

001-36559

2.7#

Asset Purchase Agreement, dated March 7, 2018, by and between Spark HoldCo, LLC and National Gas & Electric, LLC.

10-K

2.7

3/9/2018

001-36559

2.8#

Asset Purchase Agreement, by and between Spark HoldCo, LLC, Starion Energy Inc., Starion Energy NY Inc., and Starion Energy PA Inc., dated October 19, 2018.

8-K

2.1

10/25/2018

001-36559

2.9

First Amendment to Asset Purchase Agreement, by and between Spark HoldCo, LLC, Starion Energy Inc., Starion Energy NY Inc., and Starion Energy PA, Inc., effective May 1, 2020.

10-Q

2.9

8/5/2020

001-36559

3.1

Amended and Restated Certificate of Incorporation of Via Renewables, Inc., as amended through August 6, 2021

10-Q

3.1

11/4/2021

001-36559

3.2

Second Amended and Restated Bylaws of Via Renewables, Inc

8-K

3.1

8/9/2021

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

3/14/2017

001-36559

4.2

Class A Common Stock Certificate

S-1

4.1

6/30/2014

333-196375

10.1#

Credit Agreement, dated June 30, 2022, by and among Via Renewables, Inc., Spark HoldCo, LLC, and the other subsidiaries of Via Renewables, Inc. and Spark HoldCo, LLC party thereto, as co-borrowers, Woodforest National Bank, as administrative agent, swing bank, swap bank, issuing bank, joint-lead arranger, sole bookrunner and syndication agent, BOKF, NA (d/b/a/ Bank of Texas), as joint-lead arranger and issuing bank, and the other financial institutions party thereto.

8-K

10.1

7/7/2022

333-196375

10.2

Amended and Restated Subordinated Promissory Note (Note No. 7), dated June 30, 2022, by and among Via Renewables, Inc., Spark HoldCo, LLC and Retailco, LLC.

8-K

10.2

7/7/2022

333-196375

31.1*

Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.

31.2*

Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.

32**

Certifications pursuant to 18 U.S.C. Section 1350.

101.INS*

XBRL Instance Document – the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL

101.SCH*

Inline XBRL Taxonomy Extension Schema Document.

101.CAL*

Inline XBRL Taxonomy Extension Calculation Linkbase Document.

101.LAB*

Inline XBRL Taxonomy Extension Label Linkbase Document.

101.PRE*

Inline XBRL Taxonomy Extension Presentation Linkbase Document.

101.DEF*

Inline XBRL Taxonomy Extension Definition Linkbase Document.

104*

Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101.INS)

* Filed herewith

** Furnished herewith

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

† Compensatory plan or arrangement

SIGNATURES

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

Via Renewables, Inc.

August 4, 2022

/s/ Mike Barajas

Mike Barajas

Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)