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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
 
    ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
For the fiscal year ended December 31, 2023
 OR
        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)
Delaware46-5453215
(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
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

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act
Yes     No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.
Yes     No

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. o

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements
of the registrant included in the filing reflect the correction of an error to previously issued financial statements. o

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). o

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

The aggregate market value of common stock held by non-affiliates of the registrant on June 30, 2023, the last business day of the registrant's most recently completed second fiscal quarter, based on the closing price on that date of $6.96, was approximately $17 million. The registrant, solely for the purpose of this required presentation, deemed its Board of Directors and Executive Officers to be affiliates, and deducted their stockholdings in determining the aggregate market value.

There were 3,232,701 shares of Class A common stock, 4,000,000 shares of Class B common stock and 3,567,543 shares of Series A Preferred Stock outstanding as of February 27, 2024.

DOCUMENTS INCORPORATED BY REFERENCE

Certain information required by Part III of this Annual Report on Form 10-K will be disclosed in a Form 10-K/A or in a definitive Proxy Statement for an Annual Meeting of Shareholders (the “Proxy Statement”) no later than 120 days after December 31, 2023.



Table of Contents



Page No.
PART I
Items 1 & 2.Business and Properties 
Item 1A.Risk Factors 
Item 1B.Unresolved Staff Comments 
Item 1C.Cybersecurity
Item 3.Legal Proceedings 
Item 4.Mine Safety Disclosures
PART II
Item 5.Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Stock Performance Graph
Item 6.Reserved
Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations
Overview
Drivers of Our Business
Non-GAAP Performance Measures
Consolidated Results of Operations
Operating Segment Results
Liquidity and Capital Resources
Cash Flows
Summary of Contractual Obligations
Off-Balance Sheet Arrangements
Related Party Transactions
Critical Accounting Policies and Estimates
Contingencies
Item 7A.Quantitative and Qualitative Disclosures About Market Risk
Item 8.Financial Statements and Supplementary Data
Index to Consolidated Financial Statements
Item 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A.Controls and Procedures
Item 9B.Other Information
Item 9 C.Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
PART III
Item 10.Directors, Executive Officers and Corporate Governance
Item 11.Executive Compensation
Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13.Certain Relationships and Related Transactions, and Director Independence
Item 14.Principal Accounting Fees and Services
PART IV
Item 15.Exhibits, Financial Statement Schedules
Item 16.Form 10-K Summary
SIGNATURES







Cautionary Note Regarding Forward Looking Statements

This Annual Report on Form 10-K (this “Annual Report”) contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. These forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) can be identified by the use of forward-looking terminology including “may,” “should,” “likely,” “will,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” “plan,” “intend,” “project,” or other similar words. Forward-looking statements appear in a number of places in this Annual Report. All statements, other than statements of historical fact included in this Annual Report are forward-looking statements. The forward-looking statements include statements, regarding the impacts of 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 of and terms of capital, competition and government regulation and general economic conditions. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we cannot give any assurance that such expectations will prove correct.
The forward-looking statements in this Annual 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:
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 and covenants 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;
our ability to successfully obtain the requisite shareholder approval of and to consummate the merger and transactions contemplated by the Merger Agreement (as defined below) and other risks related thereto, including but not limited to, the occurrence of any event, change or other circumstances that could give rise to the termination of the Merger Agreement, the failure to satisfy other conditions to completion of the proposed merger, the failure of the proposed merger to close for any other reason, the outcome of any legal proceedings, regulatory proceedings or enforcement matters that may be instituted against us and others relating to the Merger Agreement or otherwise, the amount of the costs, fees, expenses and charges related to the proposed merger, the effect of the announcement of the proposed merger on our relationships with our contractual counterparties, operating results and business generally, the risk that the pendency of the proposed merger disrupts current plans and operations and the potential difficulties in employee retention as a result of the pendency of the proposed merger, risks related to disruption of management’s attention from our ongoing business operations due to the merger and transactions contemplated by the Merger Agreement; and
6


the “risk factors” described in "Item 1A— Risk Factors" of this Annual Report.


You should review the risk factors and other factors noted throughout or incorporated by reference in this Annual 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 Annual Report. Unless required by law, we disclaim any obligation to publicly update or revise these statements whether as a result of new information, future events or otherwise. It is not possible for us to predict all risks, nor can we assess the impact of all factors on the business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements.
Risk Factor Summary
Our business, financial condition, cash flows, results of operations and ability to pay dividends on our Class A common stock and Series A Preferred Stock could be materially and adversely affected by, and the price of our Class A common stock and Series A Preferred Stock could decline due to a number of factors, whether currently known or unknown, including but not limited to those summarized below. You should carefully consider the risk factors summarized below and described in more detail in Item 1A. — Risk Factors, together with the other information contained in this Annual Report.
Risks Related to Our Business and Our Industry
We are subject to commodity price risk.
Our financial results may be adversely impacted by weather conditions and changes in consumer demand.
Our risk management policies and hedging procedures may not mitigate risk as planned, and we may fail to fully or effectively hedge our commodity supply and price risk.
ESCOs face risks due to increased and rapidly changing regulations and increasing monetary fines by the state regulatory agencies.
The retail energy business is subject to a high level of federal, state and local regulations, which are subject to change.
Liability under the TCPA has increased significantly in recent years, and we face risks if we fail to comply.
We are, and in the future may become, involved in legal and regulatory proceedings and, as a result, may incur substantial costs.
Our business is dependent on retaining licenses in the markets in which we operate.
We may be subject to risks in connection with acquisitions, which could cause us to fail to realize many of the anticipated benefits of such acquisitions.
We have historically distributed a significant portion of our cash through regular quarterly dividends, and our ability to grow and make acquisitions with cash on hand could be limited.
We may not be able to manage our growth successfully.
Our financial results fluctuate on a seasonal, quarterly and annual basis.
We may have difficulty retaining our existing customers or obtaining a sufficient number of new customers, due to competition and for other reasons.
Increased collateral requirements in connection with our supply activities may restrict our liquidity.
We face risks related to health epidemics, pandemics and other outbreaks.
We are subject to direct credit risk for certain customers who may fail to pay their bills as they become due.
We depend on the accuracy of data in our information management systems, which subjects us to risks.
Cyberattacks and data security breaches could adversely affect our business.
Our success depends on key members of our management, the loss of whom could disrupt our business operations.
We rely on third party vendors for our customer acquisition verification, billing and transactions platform that exposes us to third party performance risk and other risk.
A large portion of our current customers are concentrated in a limited number of states, making us vulnerable to customer concentration risks.
Increases in state renewable portfolio standards or an increase in the cost of renewable energy credit and carbon offsets may adversely impact the price, availability and marketability of our products.
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Our access to marketing channels may be contingent upon the viability of our telemarketing and door-to-door agreements with our vendors.
Our vendors may expose us to risks.

Risks Related to Our Capital Structure and Capital Stock

Our indebtedness could adversely affect our ability to raise additional capital to fund our operations or pay dividends. It could also expose us to the risk of increased interest rates and limit our ability to react to changes in the economy or our industry as well as impact our cash available for distribution.
Our ability to pay dividends depends 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 are a holding company. Our sole material asset is our equity interest in Spark HoldCo, LLC ("Spark HoldCo") and we are accordingly dependent upon distributions from Spark HoldCo to pay dividends on the Class A common stock and Series A Preferred Stock.
The Class A common stock and Series A Preferred Stock are subordinated to our existing and future debt obligations.
Numerous factors may affect the trading price of the Class A common stock and Series A Preferred Stock.
There may not be an active trading market for the Class A common stock or Series A Preferred Stock, which may in turn reduce the market value and your ability to transfer or sell your shares of Class A common stock or Series A Preferred Stock.
Mr. Maxwell holds a substantial majority of the voting power of our common stock.
Holders of Series A Preferred Stock have extremely limited voting rights.
We have engaged in transactions with our affiliates in the past and expect to do so in the future. The terms of such transactions and the resolution of any conflicts that may arise may not always be in our or our stockholders’ best interests.
Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our Class A common stock.
Our amended and restated certificate of incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.
Future sales of our Class A common stock and Series A Preferred Stock in the public market could reduce the price of the Class A common stock and Series A Preferred Stock, and may dilute your ownership in us.
We have issued preferred stock and may continue to do so, and the terms of such preferred stock could adversely affect the voting power or value of our Class A common stock.
Our amended and restated certificate of incorporation limits the fiduciary duties of one of our directors and certain of our affiliates and restricts the remedies available to our stockholders for actions taken by Mr. Maxwell or certain of our affiliates that might otherwise constitute breaches of fiduciary duty.
The Series A Preferred Stock represent perpetual equity interests in us, and investors should not expect us to redeem the Series A Preferred Stock on the date the Series A Preferred Stock becomes redeemable by us or on any particular date afterwards.
The Series A Preferred Stock is not rated.
The Change of Control Conversion Right may make it more difficult for a party to acquire us or discourage a party from acquiring us.
Changes in the method of determining the Three-Month CME Term SOFR, or the replacement of Three-Month CME Term SOFR with an alternative reference rate, may adversely affect the floating dividend rate of our Series A Preferred Stock.
A substantial increase in the Three-Month CME Term SOFR Rate or an alternative rate could negatively impact our ability to pay dividends on the Series A Preferred Stock and Class A common stock.
We may not have sufficient earnings and profits in order for dividends on the Series A Preferred Stock to be treated as dividends for U.S. federal income tax purposes.
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You may be subject to tax if we make or fail to make certain adjustments to the conversion rate of the Series A Preferred Stock even though you do not receive a corresponding cash distribution.
We are a “controlled company” under NASDAQ Global Select Market rules, and as such we are entitled to an exemption from certain corporate governance standards of the NASDAQ Global Select Market, and you may not have the same protections afforded to shareholders of companies that are subject to all of the NASDAQ Global Market corporate governance requirements.
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PART I.


Items 1 & 2. Business and Properties

General
We are an independent retail energy services company founded in 1999 and are organized as a Delaware corporation that provides residential and commercial customers in competitive markets across the United States with an alternative choice for their natural gas and electricity. We purchase our electricity and natural gas supply from a variety of wholesale providers and bill our customers monthly for the delivery of electricity and natural gas based on their consumption at either a fixed or variable price. Electricity and natural gas are then distributed to our customers by local regulated utility companies through their existing infrastructure.
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.

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.

Our Operations

As of December 31, 2023, we operated in 104 utility service territories across 20 states and the District of Columbia and had approximately 335,000 residential customer equivalents (“RCEs”). An RCE is an industry standard measure of natural gas or electricity usage with each RCE representing annual consumption of 100 MMBtu of natural gas or 10 MWh of electricity. We serve natural gas customers in sixteen states (Arizona, California, Colorado, Connecticut, Florida, Illinois, Indiana, Maryland, Massachusetts, Michigan, Nevada, New Jersey, New York, Ohio, Pennsylvania and Virginia) and electricity customers in twelve states (Connecticut, Delaware, Illinois, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Ohio, Pennsylvania and Texas) and the District of Columbia using seven brands (Electricity Maine, Electricity N.H., Major Energy, Provider Power Mass, Respond Power, Spark Energy, and Verde Energy).

Customer Contracts and Product Offerings

Fixed and variable-price contracts

We offer a variety of fixed-price and variable-price service options to our natural gas and electricity customers. Under our fixed-price service options, our customers purchase natural gas and electricity at a fixed price over the life of the customer contract, which provides our customers with protection against increases in natural gas and electricity prices. Our fixed-price contracts typically have a term of one to two years for residential customers and up to four years for commercial customers, and most provide for an early termination fee in the event that the customer terminates service prior to the expiration of the contract term. In a typical market, we offer fixed-price electricity plans for 6, 12 and 24 months and fixed-price natural gas plans from 12 to 24 months, which may or may not provide for a monthly service fee and/or a termination fee, depending on the market and customer type. Our variable-price service options carry a month-to-month term and are priced based on our forecasts of underlying commodity prices and other market and business factors, including the competitive landscape in the market and the regulatory environment, and may also include a monthly service fee depending on the market and customer type. Our variable plans may or may not provide for a termination fee, depending on the market and customer type.



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The fixed/variable splits of our RCEs were as follows as of December 31, 2023:
37063707


Green products and renewable energy credits

The reduction of carbon emission has become a major focus around the world. We offer renewable and carbon neutral (“green”) products in several markets. Green energy products are a growing market opportunity and typically provide increased unit margins as a result of improved customer satisfaction. Renewable electricity products allow customers to choose electricity sourced from wind, solar, hydroelectric and biofuel sources, through the purchase of renewable energy credits (“RECs”). A REC is a market-based instrument that represents the realized renewable attributes of renewable-based power generation. When we procure RECs on behalf of our customers, we are claiming their share of renewable generation that was delivered to the electric grid, directly supporting renewable generators.

Carbon neutral natural gas products give customers the option to reduce or eliminate the carbon footprint associated with their energy usage through the purchase of carbon offset credits. These products typically provide for fixed or variable prices and generally follow the same terms as our other products with the added benefit of carbon reduction and reduced environmental impact.

We utilize RECs to offset customer volumes related to customers enrolled in renewable energy plans. As of December 31, 2023, approximately 25% of our customers utilized green products. Also, as a key element of our corporate rebranding and our commitment to sustainability, we began offsetting 100% of customer volume beginning in the second quarter of 2021, by procuring RECs on behalf of our customers.

In addition to the RECs we purchase to satisfy our voluntary requirements under the terms of our green contracts with our customers and to support our corporate sustainability initiatives, we must also purchase a specified number of RECs based on the amount of electricity we sell in a state in a year pursuant to individual state renewable portfolio standards. We forecast the price for the required RECs and incorporate this cost component into our customer pricing models.

Customer Acquisition and Retention

Our customer acquisition strategy consists of customer growth obtained through traditional sales channels complemented by customer portfolio and business acquisitions. We make decisions on how best to deploy capital based on a variety of factors, including cost to acquire customers, availability of opportunities and our view of commodity pricing in particular regions.

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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 one to 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.

As a result of the COVID-19 pandemic, certain public utility commissions, regulatory agencies, and other governmental authorities in all of our markets had issued orders that impacted the way we historically acquired customers, such as door to door marketing. Our reduced marketing resulted in significantly reduced customer acquisition costs during 2021 compared to historical amounts. As these orders expired in 2022, our customer acquisition costs with respect to door to door marketing increased during 2022 and 2023. We are unable to predict our future customer acquisition costs at this time. Please see “Item 1A—Risk Factors” in this “Annual Report.”

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.

Organic Growth

We use organic sales strategies to both maintain and grow our customer base by offering products providing options for term flexibility, price certainty, variable rates and/or green product offerings. We manage growth on a market-by-market basis by developing price curves in each of the markets we serve and create product offerings in which our targeted customer segments find value. The attractiveness of a product from a consumer’s standpoint is based on a variety of factors, including overall pricing, price stability, contract term, sources of generation and environmental impact and whether or not the contract provides for termination and other fees. Product pricing is also based on several other factors, including the cost to acquire customers in the market, the competitive landscape and supply issues that may affect pricing.

Once a product has been created for a particular market, we then develop a marketing campaign. We identify and acquire customers through a variety of sales channels, including our inbound customer care call center, outbound calling, online marketing, opt-in web-based leads, email, direct mail, door-to-door sales, affinity programs, direct sales, brokers and consultants. For residential customers, we have historically used indirect sales brokers, web based solicitation, door-to-door sales, outbound calling, and other methods. For 2023, the largest channels were direct sales, telemarketing and web-based sales. We typically use brokers or direct marketing to obtain C&I customers, which are typically larger and have greater natural gas and electricity requirements. At December 31, 2023, our customer base was 68% residential and 32% C&I customers. In our sales practices, we typically employ multiple vendors under short-term contracts and have not entered into any exclusive marketing arrangements with sales vendors. Our marketing team continuously evaluates the effectiveness of each customer acquisition channel and makes adjustments in order to achieve targeted growth and manage customer acquisition costs. We strive to maintain a disciplined approach to recovery of our customer acquisition costs within defined periods.

Acquisitions

We actively monitor acquisition opportunities that may arise in the domestic acquisition market, and seek to acquire portfolios of customers and broker book acquisitions, as well as retail energy companies utilizing some combination of cash and borrowings under our senior secured borrowing base credit facility ("Senior Credit Facility), the issuance of common or preferred stock, or other financing arrangements. Historically, our customer acquisition strategy has been executed using both third parties and through affiliated relationships. See “—Relationship with our Founder, Majority Shareholder and Chief Executive Officer” for a discussion of affiliate relationships.




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The following table provides a summary of our acquisitions over the past five years:
Company / PortfolioDate CompletedRCEsSegmentAcquisition Source
Customer Portfolio May 201960,000Natural Gas
Electricity
Third Party
Customer PortfolioMay 202145,000ElectricityThird Party
Customer PortfolioJuly 202133,000Natural GasThird Party
Customer Portfolio (1)
January 202269,000Natural Gas
Electricity
Third Party
Customer PortfolioAugust 202218,700Natural GasThird Party


(1) These RCEs are related to broker contracts we acquired as part of asset purchase agreements and are not included in our Retail RCEs.

Please see “Item 1A — Risk Factors” in this Annual Report for a discussion of risks related to our acquisition strategy and ability to finance such transactions.

Retaining customers and maximizing customer lifetime value

Following the acquisition of a customer, we devote significant attention to customer retention. We have developed a disciplined renewal communication process, which is designed to effectively reach our customers prior to the end of the contract term, and employ a team dedicated to managing this renewal communications process. Customers are contacted in each utility prior to the expiration of the customer's contract. We may contact the customer through additional channels such as outbound calls or email. We also apply a proprietary evaluation and segmentation process to optimize value to both us and the customer. We analyze historical usage, attrition rates and consumer behaviors to specifically tailor competitive products that aim to maximize the total expected return from energy sales to a specific customer, which we refer to as customer lifetime value.

We actively monitor unit margins from energy sales. We use this information to assess the results of products and to guide business decisions, including whether to engage in pro-active non-renewal of lower margin customers.

Commodity Supply

We hedge and procure our energy requirements from various wholesale energy markets, including both physical and financial markets, through short- and long-term contracts. Our in-house energy supply team is responsible for managing our commodity positions (including energy procurement, capacity, transmission, renewable energy, and resource adequacy requirements) within our risk management policies. We procure our natural gas and electricity requirements at various trading hubs, city-gates and load zones. When we procure commodities at trading hubs, we are responsible for delivery to the applicable local regulated utility for distribution.

In most markets, we hedge our electricity exposure with financial products and then purchase the physical power directly from the ISO for delivery. Alternatively, we may use physical products to hedge our electricity exposure rather than buying physical electricity in the day-ahead market from the ISO. During the year ended December 31, 2023, we transacted physical and financial settlements of electricity with approximately ten suppliers.

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We are assessed monthly for ancillary charges such as reserves and capacity in the electricity sector by the ISOs. For example, the ISOs will charge all retail electricity providers for monthly reserves that the ISO determines are necessary to protect the integrity of the grid. Many of the utilities we serve also allocate natural gas transportation and storage assets to us as a part of their competitive choice program. We are required to fill our allocated storage capacity with natural gas, which creates commodity supply and price risk. Sometimes we cannot hedge the volumes associated with these assets because they are too small compared to the much larger bulk transaction volumes required for trades in the wholesale market or it is not economically feasible to do so.

We periodically adjust our portfolio of purchase/sale contracts in the wholesale natural gas market based upon analysis of our forecasted load requirements. Natural gas is then delivered to the local regulated utility city-gate or other specified delivery point where the local regulated utility takes control of the natural gas and delivers it to individual customer locations. Additionally, we hedge our natural gas price exposure with financial products. During the year ended December 31, 2023, we transacted physical and financial settlements of natural gas with approximately 81 wholesale counterparties.

We also enter into back-to-back wholesale transactions to optimize our credit lines with third-party energy suppliers. With each of our third-party energy suppliers, we have certain contracted credit lines, which allow us to purchase energy supply from these counterparties. If we desire to purchase supply beyond these credit limits, we are required to post collateral in the form of either cash or letters of credit. As we begin to approach the limits of our credit line with one supplier, we may purchase energy supply from another supplier and sell that supply to the original counterparty in order to reduce our net position with that counterparty and open up additional credit to procure supply in the future. Our sales of gas pursuant to these activities also enable us to optimize our credit lines with third-party energy suppliers by decreasing our net buy position with those suppliers.

Asset Optimization

Part of our business includes asset optimization activities in which we identify opportunities in the wholesale natural gas markets in conjunction with our retail procurement and hedging activities. Many of the competitive pipeline choice programs in which we participate require us and other retail energy suppliers to take assignment of and manage natural gas transportation and storage assets upstream of their respective city-gate delivery points. In our allocated storage assets, we are obligated to buy and inject gas in the summer season (April through October) and sell and withdraw gas during the winter season (November through March). These injection and purchase obligations require us to take a seasonal long position in natural gas. Our asset optimization group determines whether market conditions justify hedging these long positions through additional derivative transactions. We also contract with third parties for transportation and storage capacity in the wholesale market and are responsible for reservation and demand charges attributable to both our allocated and third-party contracted transportation and storage assets. Our asset optimization group utilizes these allocated and third-party transportation and storage assets in a variety of ways to either improve profitability or optimize supply-side counterparty credit lines.

We frequently enter into spot market transactions in which we purchase and sell natural gas at the same point or we purchase natural gas at one location and ship it using our pipeline capacity for sale at another location, if we are able to capture a margin. We view these spot market transactions as low risk because we enter into the buy and sell transactions on a back-to-back basis. We also act as an intermediary for market participants who need assistance with short-term procurement requirements. Consumers and suppliers contact us with a need for a certain quantity of natural gas to be bought or sold at a specific location. When this occurs, we are able to use our contacts in the wholesale market to source the requested supply and capture a margin in these transactions.

Our risk policies require that optimization activities be limited to back-to-back purchase and sale transactions, or open positions subject to aggregate net open position limits, which are not held for a period longer than two months. Furthermore, all additional capacity procured outside of a utility allocation of retail assets must be approved by a risk committee. Hedges of our firm transportation obligations are limited to two years or less and hedging of interruptible capacity is prohibited.

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Risk Management

We operate under a set of corporate risk policies and procedures relating to the purchase and sale of electricity and natural gas, general risk management and credit and collections functions. Our in-house energy supply team is responsible for managing our commodity positions (including energy, capacity, transmission, renewable energy, and resource adequacy requirements) within our risk management policies. We attempt to increase the predictability of cash flows by following our hedging strategies.

Our risk committee has control and authority over all of our risk management activities. The risk committee establishes and oversees the execution of our credit risk management policy and our commodity risk policy. The risk management policies are reviewed at least annually by the risk management committee and such committee typically meets quarterly to assure that we have followed these policies. The risk committee also seeks to ensure the application of our risk management policies to new products that we may offer. The risk committee is comprised of our Chief Executive Officer and our Chief Financial Officer, who meet on a regular basis to review the status of the risk management activities and positions. Our risk team reports directly to our Chief Financial Officer and their compensation is unrelated to trading activity. Commodity positions are typically reviewed and updated daily based on information from our customer databases and pricing information sources. The risk policy sets volumetric limits on intra-day and end of day long and short positions in natural gas and electricity. With respect to specific hedges, we have established and approved a formal delegation of authority policy specifying each trader's authorized volumetric limits based on instrument type, lead time (time to trade flow), fixed price volume, index price volume and tenor (trade flow) for individual transactions. The risk team reports to the risk committee any hedging transactions that exceed these delegated transaction limits. The various risks we face in our risk management activities are discussed below.

Commodity Price and Volumetric Risk

Because our contracts require that we deliver full natural gas or electricity requirements to our customers and because our customers’ usage can be impacted by factors such as weather, we may periodically purchase more or less commodity than our aggregate customer volumetric needs. In buying or selling excess volumes, we may be exposed to commodity price volatility. In order to address the potential volumetric variability of our monthly deliveries for fixed-price customers, we implement various hedging strategies to attempt to mitigate our exposure.
 
Our commodity risk management strategy is designed to hedge substantially all of our forecasted volumes on our fixed-price customer contracts, as well as a portion of the near-term volumes on our variable-price customer contracts. We use both physical and financial products to hedge our fixed-price exposure. The efficacy of our risk management program may be adversely impacted by unanticipated events and costs that we are not able to effectively hedge, including abnormal customer attrition and consumption, certain variable costs associated with electricity grid reliability, pricing differences in the local markets for local delivery of commodities, unanticipated events that impact supply and demand, such as extreme weather, and abrupt changes in the markets for, or availability or cost of, financial instruments that help to hedge commodity price.

Variability in customer demand is primarily impacted by weather. We use utility-provided historical and/or forward projected customer volumes as a basis for our forecasted volumes and mitigate the risk of seasonal volume fluctuation for some customers by purchasing excess fixed-price hedges within our volumetric tolerances. Should seasonal demand exceed our weather-normalized projections, we may experience a negative impact on our financial results.

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From time to time, we also take further measures to reduce price risk and optimize our returns by: (i) maximizing the use of natural gas storage in our daily balancing market areas in order to give us the flexibility to offset volumetric variability arising from changes in winter demand; (ii) entering into daily swing contracts in our daily balancing markets over the winter months to enable us to increase or decrease daily volumes if demand increases or decreases; and (iii) purchasing out-of-the-money call options for contract periods with the highest seasonal volumetric risk to protect against steeply rising prices if our customer demands exceed our forecast. Being geographically diversified in our delivery areas also permits us, from time to time, to employ assets not being used in one area to other areas, thereby mitigating potential increased costs for natural gas that we otherwise may have had to acquire at higher prices to meet increased demand.

We utilize New York Mercantile Exchange (“NYMEX”) settled financial instruments to offset price risk associated with volume commitments under fixed-price contracts. The valuation for these financial instruments is calculated daily based on the NYMEX Exchange published closing price, and they are settled using the NYMEX Exchange’s published settlement price at their maturity.

Basis Risk

We are exposed to basis risk in our operations when the commodities we hedge are sold at different delivery points from the exposure we are seeking to hedge. For example, if we hedge our natural gas commodity price with Chicago basis but physical supply must be delivered to the individual delivery points of specific utility systems around the Chicago metropolitan area, we are exposed to the risk that prices may differ between the Chicago delivery point and the individual utility system delivery points. These differences can be significant from time to time, particularly during extreme, unforecasted cold weather conditions. Similarly, in certain of our electricity markets, customers pay the load zone price for electricity, so if we purchase supply to be delivered at a hub, we may have basis risk between the hub and the load zone electricity prices due to local congestion that is not reflected in the hub price. We attempt to hedge basis risk where possible, but hedging instruments are occasionally not economically feasible or available in the smaller quantities that we require.

Customer Credit Risk

Our credit risk management policies are designed to limit customer credit exposure. Credit risk is managed through participation in purchase of receivables ("POR") programs in utility service territories where such programs are available. In these markets, we monitor the credit ratings of the local regulated utilities and the parent companies of the utilities that purchase our customer accounts receivable. We also periodically review payment history and financial information for the local regulated utilities to ensure that we identify and respond to any deteriorating trends. In non-POR markets, we assess the creditworthiness of new applicants, monitor customer payment activities and administer an active collection program. Using risk models, past credit experience and different levels of exposure in each of the markets, we monitor our receivable aging, bad debt forecasts and actual bad debt expenses and adjust as necessary.

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In territories where POR programs have been established, the local regulated utility purchases our receivables, and then becomes responsible for billing and collecting payment from the customer. In return for their assumption of risk, we receive slightly discounted proceeds on the receivables sold. POR programs result in substantially all of our credit risk being linked to the applicable utility and not to our end-use customers in these territories. For the year ended December 31, 2023, approximately 55% of our retail revenues were derived from territories in which substantially all of our credit risk was directly linked to local regulated utility companies, all of which had investment grade ratings. During the same period, we paid these local regulated utilities a weighted average discount of approximately 1.0% of total revenues for customer credit risk. 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 subsequent collection efforts are unsuccessful, we return the account to the local regulated utility for termination of service to the extent the ability to terminate service has not been limited as a result of regulatory orders. Under these service programs, we are exposed to credit risk related to payment for services rendered during the time between when the customer is transferred to us by the local regulated utility and the time we return the customer to the utility for termination of service, which is generally one to two billing periods. We may also realize a loss on fixed-price customers in this scenario due to the fact that we will have already fully hedged the customer’s expected commodity usage for the life of the contract.

In non-POR markets (and in POR markets where we may choose to direct bill our customers), we manage customer credit risk through formal credit review in the case of commercial customers, and credit score screening, deposits and disconnection for non-payment, in the case of residential customers. Economic conditions may affect our customers’ ability to pay bills in a timely manner, which could increase customer delinquencies and may lead to an increase in credit loss expense. We maintain an allowance for credit loss, which represents our estimate of potential credit losses associated with accounts receivable from customers within these markets.

We assess the adequacy of the allowance for credit loss through review of an aging of customer accounts receivable and general economic conditions in the markets that we serve. Our bad debt expense for the year ended December 31, 2023 was $3.4 million, or 0.8% of retail revenues. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Drivers of Our Business—Customer Credit Risk” for a more detailed discussion of our bad debt expense for the year ended December 31, 2023.

We do not have high concentrations of sales volumes to individual customers. For the year ended December 31, 2023, our largest customer accounted for less than 1% of total retail energy sales.

Counterparty Credit Risk in Wholesale Markets

We do not independently produce natural gas and electricity and depend upon third parties for our supply, which exposes us to wholesale counterparty credit risk in our retail and asset optimization activities. If the counterparties to our supply contracts are unable to perform their obligations, we may suffer losses, including those that occur as a result of being unable to secure replacement supplies of natural gas or electricity on a timely or cost-effective basis or at all. At December 31, 2023, approximately $2.1 million of our total exposure of $2.8 million was either with a non-investment grade counterparty or otherwise not secured with collateral or a guarantee.

Operational Risk

As with all companies, we are at risk from cyber-attacks (breaches, unauthorized access, misuse, computer viruses, or other malicious code or other events) that could materially adversely affect our business, or otherwise cause interruptions or malfunctions in our operations. We mitigate these risks through multiple layers of security controls including policy, hardware, and software security solutions. We also have engaged third parties to assist with both external and internal vulnerability scans and continually enhance awareness through employee education and accountability. During 2023, we did not experience any material loss related to cyber-attacks or other information security breaches.

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

We have historically leveraged our relationship with affiliates of our founder, majority shareholder and Chief Executive Officer, W. Keith Maxwell III, to execute our strategy, including sourcing acquisitions, financing, and operations support. Mr. Maxwell owns NG&E, which was formed for the purpose of purchasing retail energy companies and retail customer books that may ultimately be resold to us. This relationship has afforded us access to opportunities that may not have otherwise been available to us due to our size and availability of capital.

We may engage in additional transactions with NG&E in the future and expect that any such transactions would be funded by a combination of cash, subordinated debt, or the issuance of securities. Actual consideration paid for the assets would depend, among other things, on our capital structure and liquidity at the time of any transaction. Although we believe our Founder would be incentivized to offer us additional acquisition opportunities, he and his affiliates are under no obligation to do so, and we are under no obligation to buy assets from them. Any acquisition activity involving NG&E or any other affiliate of Mr. Maxwell will be subject to negotiation and approval by a special committee of our Board of Directors consisting solely of independent directors. Please see “Item 1A — Risk Factors” in this Annual Report for risks related to acquisitions and transactions with our affiliates.

On December 29, 2023, we entered into a merger agreement (the “Merger Agreement”) with Retailco, LLC, a Texas limited liability company (“Retailco”), and NuRetailco LLC, a Delaware limited liability company and wholly-owned subsidiary of Retailco (“Merger Sub”), whereby all of our Class A common stock (except for as described below), will be acquired by Retailco for $11.00 per share.

Retailco is an entity owned by TxEx, which is wholly owned by Mr. Maxwell.

The transaction will be effected by a merger of Merger Sub, with and into the Company, with the Company surviving the merger. Under the terms of the Merger Agreement, all of our Class A common stock, except for shares of Class A common stock for which appraisal rights have been properly and validly exercised under Delaware law and certain additional shares, including those held by the Company or any of its subsidiaries (or held in the Company’s treasury), Retailco or Merger Sub or any of their respective subsidiaries, or Mr. Maxwell, and any person or entity controlled by him, will be converted into the right to receive the cash consideration.

The Class A common stock, currently traded under the symbol VIA, will cease to trade on NASDAQ upon consummation of the transaction. We expect that the Series A Preferred Stock, currently traded under the symbol VIASP, will continue to trade on NASDAQ following the transaction. Accordingly, Via Renewables will remain subject to the reporting requirements of the Exchange Act.

The transaction was negotiated on behalf of the Company by a Special Committee of its Board of Directors with the assistance of independent financial and legal advisors. The Special Committee is comprised of entirely disinterested and independent directors. Following the Special Committee’s unanimous recommendation in support of the merger, the Company’s Board of Directors (other than Mr. Maxwell) approved the Merger Agreement and recommended that the Company’s stockholders adopt and approve the Merger Agreement and the merger.

The merger is subject to approval by a majority of shareholders of the issued and outstanding shares of the Company’s Class A common stock and Class B common stock. In addition, the merger is subject to a non-waivable requirement of approval by the holders of at least a majority of the issued and outstanding Class A common stock and Class B common stock not owned by Mr. Maxwell and his affiliated entities or the directors, officers or their immediate family members. Mr. Maxwell and affiliated entities have entered into a support agreement to vote their shares in favor of the transaction and against any competing transaction. The Merger Agreement is not subject to a financing condition, but is subject to customary closing conditions. The transaction is expected to close in the second quarter of 2024.

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Competition

The markets in which we operate are highly competitive. Our primary competition comes from the incumbent utility and other independent retail energy companies. In the electricity sector, these competitors include larger, well-capitalized energy retailers such as Calpine Energy Solutions, LLC, Constellation Corporation, NRG Energy, Inc. and Vistra Corp. We also compete with small local retail energy providers in the electricity sector that are focused exclusively on certain markets. Each market has a different group of local retail energy providers. In the natural gas sector, our national competitors are primarily NRG, Inc. Energy and Constellation Energy Corporation. Our national competitors generally have diversified energy platforms with multiple marketing approaches and broad geographic coverage similar to us. Competition in each market is based primarily on product offering, price and customer service. The number of competitors in our markets varies. In well-established markets in the Northeast and Texas we have hundreds of competitors, while in other markets the competition is limited to several participants. Markets that offer POR programs are generally more competitive than those markets in which retail energy providers bear customer credit risk.

Our ability to compete depends on our ability to convince customers to switch to our products and services, renew services with customers upon expiration of their contract terms, and our ability to offer products at attractive prices. Many local regulated utilities and their affiliates may possess the advantages of name recognition, longer operating histories, long-standing relationships with their customers and access to financial and other resources, which could pose a competitive challenge to us. As a result of our competitors' advantages, many customers of these local regulated utilities may decide to stay with their longtime energy provider if they have been satisfied with their service in the past. In addition, competitors may choose to offer more attractive short-term pricing to increase their market share.

Seasonality of Our Business

Our overall operating results fluctuate substantially on a seasonal basis depending on: (i) the geographic mix of our customer base; (ii) the relative concentration of our commodity mix; (iii) weather conditions, which directly influence the demand for natural gas and electricity and affect the prices of energy commodities; and (iv) variability in market prices for natural gas and electricity. These factors can have material short-term impacts on monthly and quarterly operating results, which may be misleading when considered outside of the context of our annual operating cycle.

Our accounts payable and accounts receivable are impacted by seasonality due to the timing differences between when we pay our suppliers for accounts payable versus when we collect from our customers on accounts receivable. We typically pay our suppliers for purchases of natural gas on a monthly basis and electricity on a weekly basis. However, it takes approximately two months from the time we deliver the electricity or natural gas to our customers before we collect from our customers on accounts receivable attributable to those product deliveries. This timing difference affects our cash flows, especially during peak cycles in the winter and summer months.

Natural gas accounted for approximately 25% of our retail revenues for the year ended December 31, 2023, which exposes us to a high degree of seasonality in our cash flows and income earned throughout the year as a result of the high concentration of heating load in the winter months. We utilize a considerable amount of cash from operations and borrowing capacity to fund working capital, which includes inventory purchases from April through October each year. We sell our natural gas inventory during the months of November through March of each year. We expect that the significant seasonality impacts to our cash flows and income will continue in future periods.

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Regulatory Environment

We operate in the highly regulated natural gas and electricity retail sales industry in all of our respective jurisdictions, and must comply with the legislation and regulations in these jurisdictions in order to maintain our licenses to operate. We must also comply with the applicable regulations in order to obtain the necessary licenses in jurisdictions in which we plan to compete. Licensing requirements vary by state, but generally involve regular, standardized reporting in order to maintain a license in good standing with the state commission responsible for regulating retail electricity and gas suppliers. We believe there is potential for changes to state legislation and regulatory measures addressing licensing requirements that may impact our business model in the applicable jurisdictions. In addition, as further discussed below, our marketing activities and customer enrollment procedures are subject to rules and regulations at the state and federal levels, and failure to comply with requirements imposed by federal and state regulatory authorities could impact our licensing in a particular market. See "Risk Factors—We face risks due to increasing regulation of the retail energy industry at the state level."

New Jersey and Connecticut

Certain state commissions have begun efforts to restrict the ability of retail suppliers to “pass through” costs to customers associated with certain changes in law or regulatory requirements. For example, on January 22, 2019, the New Jersey Board of Public Utilities (“NJ BPU”) sent a cease and desist letter to third party suppliers (“TPS”) in New Jersey instructing that a TPS may not charge a customer rate that is higher than the fixed rate applicable during the period for which that rate was fixed. The letter notified TPS that such increases were prohibited and instructed TPS to refund customers amounts charged in excess of the applicable fixed rate. Parties have challenged the NJ BPU’s letter and it is not clear at this time whether refunds will be required. Similarly, the Connecticut Public Utilities Regulatory Authority (“PURA”) opened a docket after receiving complaints regarding increases by suppliers to certain fixed-price supplier contracts due to change in law triggers. PURA will consider whether suppliers’ actions constitute unfair and deceptive trade practices or otherwise violates applicable laws. These state actions provide examples where the Company may be required to assume costs that it otherwise would pass on to customers under its change in law provisions and potentially provide refunds to certain customers.

Other Regulations

Our marketing efforts to consumers, including but not limited to telemarketing, door-to-door sales, direct mail and online marketing, are subject to consumer protection regulation including state deceptive trade practices acts, Federal Trade Commission ("FTC") marketing standards, and state utility commission rules governing customer solicitations and enrollments, among others. By way of example, telemarketing activity is subject to federal and state do-not-call regulation and certain enrollment standards promulgated by state regulators. Door-to-door sales are governed by the FTC’s “Cooling-Off Rule" as well as state-specific regulation in many jurisdictions. In markets in which we conduct customer credit checks, these checks are subject to the requirements of the Fair Credit Reporting Act. Violations of the rules and regulations governing our marketing and sales activity could impact our license to operate in a particular market, result in suspension or otherwise limit our ability to conduct marketing activity in certain markets, and potentially lead to private actions against us. Moreover, there is potential for changes to legislation and regulatory measures applicable to our marketing measures that may impact our business models.

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We partially rely on lead generators for our telemarketing sales channel. Applicable laws over the years have become more restrictive in our ability to telemarket to potential customers. Most recently, a law was passed by the FCC that lead generators, when obtaining a consumer’s prior express written consent to robocall or robotext the consumer soliciting their business, can only obtain a single seller at a time on the comparison shopping websites that often are the source of lead generation. Specifically, in December 2023, the FCC, adopted rules, pursuant to Federal Communications Commission (FCC 23-107): In the Matter of Targeting and Eliminating Unlawful Text Messages, CG Docket No. 21-402; Rules and Regulations Implementing the Telephone Consumer Protection Act of 1991, CG Docket No. 02-278; Advanced Methods to Target and Eliminate Unlawful Robocalls, CG Docket No. 17-59, Second Report and Order, Second Further Notice of Proposed Rulemaking, and Waiver Order (December 13, 2023) that could impact our ability to obtain, and increase the cost of, sales leads for our telemarketing channel.

Recent interpretations of the Telephone Consumer Protection Act of 1991 (the “TCPA”) by the Federal Communications Commission (“FCC”) have introduced confusion regarding what constitutes an “autodialer” for purposes of determining compliance under the TCPA. Also, additional restrictions have been placed on wireless telephone numbers making compliance with the TCPA more costly. See “Risk Factors—Risks Related to Our Business and Our Industry—Liability under the TCPA has increased significantly in recent years, and we face risks if we fail to comply.”

As compliance with the federal TCPA regulations and state telemarketing regulations becomes increasingly costly and as door-to-door marketing becomes increasingly risky both from a regulatory compliance perspective, and from the risk of such activities drawing class action litigation claims, we and our peers who rely on these sales channels will find it more difficult than in the past to engage in direct marketing efforts. In response to these risks, we are experimenting with new technologies, such as a web-based application to process door-to-door sales enrollments with direct input by the consumer. This application can be accessed using tablets or any smart phone device, which enhances and expands the opportunities to market directly to customers.

Our participation in natural gas and electricity wholesale markets to procure supply for our retail customers and hedge pricing risk is subject to regulation by the Commodity Futures Trading Commission (the "CFTC"), including regulation pursuant to the Dodd-Frank Wall Street Reform and Consumer Protection Act. In order to sell electricity, capacity and ancillary services in the wholesale electricity markets, we are required to have market-based rate authorization, also known as “MBR Authorization,” from the Federal Energy Regulatory Commission ("FERC"). We are required to make status update filings to FERC to disclose any affiliate relationships and quarterly filings to FERC regarding volumes of wholesale electricity sales in order to maintain our MBR Authorization. We are also required to seek prior approval by FERC to the extent any direct or indirect change in control occurs with respect to entities that hold MBR Authorization.

The transportation and sale for resale of natural gas in interstate commerce are regulated by agencies of the U.S. federal government, primarily FERC under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and regulations issued under those statutes. FERC regulates interstate natural gas transportation rates and service conditions, which affects our ability to procure natural gas supply for our retail customers and hedge pricing risk. Since 1985, FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. FERC’s orders do not attempt to directly regulate natural gas retail sales. As a shipper of natural gas on interstate pipelines, we are subject to those interstate pipelines' tariff requirements and FERC regulations and policies applicable to shippers.

Changes in law and to FERC policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines, and we cannot predict what future action FERC will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas marketers and local regulated utilities with which we compete.

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In December 2007, FERC issued Order 704, a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing. Under Order 704, wholesale buyers and sellers of more than 2.2 million MMBtus of physical natural gas in the previous calendar year, including natural gas gatherers and marketers, are required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. Order 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting complies with FERC’s policy statement on price reporting. As a wholesale buyer and seller of natural gas, we are subject to the reporting requirements of Order 704.

Employees

As of December 31, 2023, we employed 160 full-time employees. Our employees are not represented by a collective bargaining unit. We have not experienced any strikes or work stoppages and consider our relations with our employees to be satisfactory.

We are dedicated to attracting and retaining talent across a variety of backgrounds, with varying experiences, perspectives and ideas, while having an inclusive culture. As of December 31, 2023, approximately 48% of our workforce was male and 52% female. We encourage and support the development of our employees wherever possible, and seek to fill positions through promotions and transfers within the organization. Continued learning and career development is advanced through ongoing performance and development conversations with employees and internally developed training programs.

We provide competitive compensation and benefits programs to our employees. These programs include, subject to eligibility policies, a 401(k) Plan, healthcare and insurance benefits, long term incentive awards in the form of restricted stock units to certain employees, health savings and flexible spending accounts, paid time off, family leave and employee assistance programs.

We strive to be a good corporate citizen by being involved with numerous local community and charitable organizations through financial contributions and volunteer events. To encourage volunteerism, we offer paid time off to employees to volunteer in the community during work hours.

Facilities

Our corporate headquarters is located in Houston, Texas.

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Available Information

Our website is located at www.viarenewables.com. We make available our periodic reports and other information filed with or furnished to the Securities and Exchange Commission (the “SEC”), including our annual reports on Form 10-K, our quarterly reports on Form 10-Q, our current reports on Form 8-K, and all amendments to those reports, free of charge through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Any materials filed with the SEC may be read and copied at the SEC’s website at www.sec.gov.
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Item 1A. Risk Factors

Our business, financial condition, cash flows, results of operations and ability to pay dividends on our Class A common stock and Series A Preferred Stock could be materially and adversely affected by, and the price of our Class A common stock and Series A Preferred Stock could decline due to a number of factors, whether currently known or unknown, including but not limited to those described below. You should carefully consider these risk factors together with the other information contained in this Annual Report.
Risks Related to Our Business and Our Industry
We are subject to commodity price risk.

Our financial results are largely dependent on the prices at which we can acquire the commodities we resell. The prevailing market prices for natural gas and electricity are unpredictable and tend to fluctuate substantially. Changes in market prices for natural gas and electricity may result from many factors that are outside of our control, including:
weather conditions; including extreme weather conditions, seasonal fluctuations, and the effects of climate change;
demand for energy commodities and general economic conditions;
disruption of natural gas or electricity transmission or transportation infrastructure or other constraints or inefficiencies;
reduction or unavailability of generating capacity, including temporary outages, mothballing, or retirements;
the level of prices and availability of natural gas and competing energy sources, including the impact of changes in environmental regulations impacting suppliers;
the creditworthiness or bankruptcy or other financial distress of market participants;
changes in market liquidity;
natural disasters, wars, embargoes, acts of terrorism and other catastrophic events;
significant changes in the pricing methods in the wholesale markets in which we operate;
changes in regulatory policies concerning how markets are structured, how compensation is provided for service, and the kinds of different services that can or must be offered;
federal, state, foreign and other governmental regulation and legislation; and
demand side management, conservation, alternative or renewable energy sources.

For example, in February 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 Electric Reliability Counsel of Texas (“ERCOT”) service area experienced extreme volatility and price increases beyond the maximum allowed clearing prices. Less extreme price fluctuations can also occur as a result of routine winter weather fluctuations.

In the event of price fluctuations, we may not be able to pass along changes to the prices we pay to acquire commodities to our customers as such pricing fluctuations can attract consumer class actions as well as state and federal regulatory actions.
Our financial results may be adversely impacted by weather conditions and changes in consumer demand.

Weather conditions directly influence the demand for and availability of natural gas and electricity and affect the prices of energy commodities. Generally, on most utility systems, demand for natural gas peaks in the winter and demand for electricity peaks in the summer. Typically, when winters are warmer or summers are cooler, demand for energy is lower than expected, resulting in less natural gas and electricity consumption than forecasted. When demand is below anticipated levels due to weather patterns, we may be forced to sell excess supply at prices below our acquisition cost, which could result in reduced margins or even losses.
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Conversely, when winters are colder or summers are warmer, consumption may outpace the volumes of natural gas and electricity against which we have hedged, and we may be unable to meet increased demand with storage or swing supply. In these circumstances, such as with winter storm Uri, we may experience reduced margins or even losses if we are required to purchase additional supply at higher prices. We may fail to accurately anticipate demand due to fluctuations in weather or to effectively manage our supply in response to a fluctuating commodity price environment.

Further, extreme weather conditions such as hurricanes, droughts, heat waves, winter storms and severe weather associated with climate change could cause these seasonal fluctuations to be more pronounced. Destruction caused by severe weather events, such as hurricanes, tornadoes, severe thunderstorms, snow and ice storms, can result in lost operating revenues.
Our risk management policies and hedging procedures may not mitigate risk as planned, and we may fail to fully or effectively hedge our commodity supply and price risk.
To provide energy to our customers, we purchase commodities in the wholesale energy markets, which are often highly volatile. Our commodity risk management strategy is designed to hedge substantially all of our forecasted volumes on our fixed-price customer contracts, as well as a portion of the near-term volumes on our variable-price customer contracts. We use both physical and financial products to hedge our exposure. The efficacy of our risk management program may be adversely impacted by unanticipated events and costs that we are not able to effectively hedge, including abnormal customer attrition and consumption, certain variable costs associated with electricity grid reliability, pricing differences in the local markets for local delivery of commodities, unanticipated events that impact supply and demand, such as extreme weather, and abrupt changes in the markets for, or availability or cost of, financial instruments that help to hedge commodity price.
We are exposed to basis risk in our operations when the commodities we hedge are sold at different delivery points from the exposure we are seeking to hedge. For example, if we hedge our natural gas commodity price with Chicago basis but physical supply must be delivered to the individual delivery points of specific utility systems around the Chicago metropolitan area, we are exposed to basis risk between the Chicago basis and the individual utility system delivery points. These differences can be significant from time to time, particularly during extreme, unforecasted cold weather conditions. Similarly, in certain of our electricity markets, customers pay the load zone price for electricity, so if we purchase supply to be delivered at a hub, we may have basis risk between the hub and the load zone electricity prices due to local congestion that is not reflected in the hub price. We attempt to hedge basis risk where possible, but hedging instruments are sometimes not economically feasible or available in the smaller quantities that we require.
Additionally, assumptions that we use in establishing our hedges may reduce the effectiveness of our hedging instruments. Considerations that may affect our hedging policies include, but are not limited to, human error, assumptions about customer attrition, the relationship of prices at different trading or delivery points, assumptions about future weather, and our load forecasting models.
Our derivative instruments are subject to mark-to-market accounting requirements and are recorded on the consolidated balance sheet at fair value with changes in fair value resulting from fluctuations in the underlying commodity prices immediately recognized in earnings. As a result, the Company’s quarterly and annuals results are subject to significant fluctuations caused by the changes in market price.
In addition, we incur costs monthly for ancillary charges such as reserves and capacity in the electricity sector by ISOs. For example, the ISOs will charge all retail electricity providers for monthly reserves that the ISO determines are necessary to protect the integrity of the grid. We may be unable to fully pass the higher cost of ancillary reserves and reliability services through to our customers, and increases in the cost of these ancillary reserves and reliability services could negatively impact our results of operations.
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Many of the natural gas utilities we serve allocate a share of transportation and storage capacity to us as a part of their competitive market operations. We are required to fill our allocated storage capacity with natural gas, which creates commodity supply and price risk. Sometimes we cannot hedge the volumes associated with these assets because they are too small compared to the much larger bulk transaction volumes required for trades in the wholesale market or it is not economically feasible to do so. In some regulatory programs or under some contracts, this capacity may be subject to recall by the utilities, which could have the effect of us being required to access the spot market to cover such a recall.
ESCOs face risks due to increased and rapidly changing regulations and increasing monetary fines by the state regulatory agencies.

The retail energy industry is highly regulated. Regulations may be changed or reinterpreted and new laws and regulations applicable to our business could be implemented in the future. To the extent that the competitive restructuring of retail electricity and natural gas markets is reversed, altered or discontinued, such changes could have a detrimental impact on our business and overall financial condition.
Some states are beginning to increase their regulation of their retail electricity and natural gas markets in an effort to increase consumer disclosures and ensure marketing practices are not misleading to consumers. In addition, the fines against ESCOs that regulators are seeking have increased dramatically in recent years. For example, in late 2022 PURA and the Connecticut Office of Consumer Counsel issued to our subsidiary, Verde, a Notice of Violation and Assessment of Penalty proposing civil penalties, restitution payments to certain customers and a multi-year suspension from the Connecticut market in connection with violations of Connecticut’s marketing requirements for energy suppliers.

The retail energy business is subject to a high level of federal, state and local regulations, which are subject to change.

Many governmental bodies regulate aspects of our operations, and our failure to comply with these legal requirements can result in substantial penalties. In addition, new laws and regulations, including executive orders, or changes to or new interpretations of existing laws and regulations by courts or regulatory authorities occur regularly, but are difficult to predict. Changes under a new president, administration and Congress in the U.S. are also difficult to predict. Any such variation could negatively impact the retail energy business, including our business, could substantially increase costs to achieve compliance or otherwise could have a material adverse effect on our cash flow, results of operations and financial condition.
For example, many electricity markets have rate caps, and changes to these rate caps by regulators can impact future price exposure. Similarly, regulatory changes can result in new fees or charges that may not have been anticipated when existing retail contracts were drafted, which can create financial exposure. Our ability to manage cost increases that result from regulatory changes will depend, in part, on how the “change in law provisions” of our contracts are interpreted and enforced, among other factors.

Additionally, regulations that do not directly relate to ESCOs could impact us. For example, we have historically used third-party lead generators to identify potential customers for our telemarketing sales channel. In December 2023, the FCC adopted rules that could limit the ability of third-party lead generators to identify large numbers of potential customers. If the number of potential customers is reduced, or if it becomes more difficult or costly to identify potential telemarketing targets, our ability to maintain our RCE count based on our telemarketing sales could be impacted. Please see “Regulatory Environment—Other Regulations.”







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Liability under the TCPA has increased significantly in recent years, and we face risks if we fail to comply.

Our outbound telemarketing efforts and use of mobile messaging to communicate with our customers, which has increased in recent years, subjects us to regulation under the TCPA. Over the last several years, companies have been subject to significant liabilities as a result of violations of the TCPA, including penalties, fines and damages under class action lawsuits. Our failure to effectively monitor and comply with our activities that are subject to the TCPA could result in significant penalties and the adverse effects of having to defend and ultimately suffer liability in a class action lawsuit related to such non-compliance. We are also subject to liability under the TCPA for actions of our third party vendors who are engaging in outbound telemarketing efforts on our behalf. The issue of vicarious liability for the actions of third parties in violation of the TCPA remains unclear and has been the subject of conflicting precedent in the federal appellate courts. There can be no assurance that we may be subject to significant damages as a result of a class action lawsuit for actions of our vendors that we may not be able to control.

We are, and in the future may become, involved in legal and regulatory proceedings and, as a result, may incur substantial costs.

We are subject to lawsuits, claims and regulatory proceedings arising in the ordinary course of our business from time to time, including several purported class action lawsuits involving sales practices, telemarketing and TCPA claims, as well as contract disclosure claims and breach of contract claims. These are in various stages and are subject to substantial uncertainties concerning the outcome.

A negative outcome for any of these matters could result in significant costs, may divert management's attention from other business issues or harm our reputation with customers.

For additional information regarding the nature and status of certain proceedings, see Note 13 "Commitments and Contingencies" to the audited consolidated financial statements.
Our business is dependent on retaining licenses in the markets in which we operate.
Our business model is dependent on continuing to be licensed in existing markets. We may have a license revoked or not be granted a renewal of a license, or our license could be adversely conditioned or modified (e.g., by increased bond posting obligations). For example, recently, an ESCO was banned by the Public Utilities Commission of Ohio from operating in Ohio for five years in response to allegations of misleading and deceptive marketing practices.

We may be subject to risks in connection with acquisitions, which could cause us to fail to realize many of the anticipated benefits of such acquisitions.

We have grown our business in part through strategic acquisition opportunities from third parties and from affiliates of our majority shareholder and may continue to do so in the future. Achieving the anticipated benefits of these transactions depends in part upon our ability to identify accretive acquisition targets, accurately assess the benefits and risks of the acquisition prior to undertaking it, and the ability to integrate the acquired businesses in an efficient and effective manner. When we identify an acquisition candidate, there is a risk that we may be unable to negotiate terms that are beneficial to us. Additionally, even if we identify an accretive acquisition target, the successful acquisition of that business requires estimating anticipated cash flow and accretive value, evaluating potential regulatory challenges, retaining customers and assuming liabilities. The accuracy of these estimates is inherently uncertain and our assumptions may be incorrect.

Furthermore, when we make an acquisition, we may not be able to accomplish the integration process smoothly or successfully. The integration process could take longer than anticipated and could result in the loss of valuable employees, the disruption of our business, processes and systems or inconsistencies in standards, controls, procedures, practices, policies, compensation arrangements, distraction of management and significant costs, any of which could adversely affect our ability to achieve the anticipated benefits of the acquisitions. Further, we may have difficulty addressing possible differences in corporate cultures and management philosophies.
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In many of our acquisition agreements, we are entitled to indemnification from the counterparty for various matters, including breaches of representations, warranties and covenants, tax matters, and litigation proceedings. We generally obtain security to provide assurances that the counterparty could perform its indemnification obligations, which may be in the form of escrow accounts, payment withholding or other methods. However, to the extent that we do not obtain security, or the security turns out to be inadequate, there is a risk that the counterparty may fail to perform on its indemnification obligations, which could result in the losses being incurred by us.

Our ability to grow at levels experienced historically may be constrained if the market for acquisition candidates is limited and we are unable to make acquisitions of portfolios of customers and retail energy companies on commercially reasonable terms.

We have historically distributed a significant portion of our cash through dividends, and our ability to grow and make acquisitions with cash on hand could be limited.

We have historically distributed a significant portion of our cash through dividends to holders of our Class A common stock and dividends on our Series A Preferred Stock. In the future, we may also distribute a significant amount of cash through dividends. As such, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations, and we may have to rely upon external financing sources, including the issuance of debt, equity securities, convertible subordinated notes and borrowings under our Senior Credit Facility and Subordinated Facility. These sources may not be available, and our ability to grow and maintain our business may be limited.

We may have liquidity needs that would prevent us from continuing our historical practice as it relates to the payment of dividends on our Series A Preferred Stock. The primary factor that would lead to a change in the dividend policy would be decreased liquidity due to decreasing customer book.

We may not be able to manage our growth successfully.

The growth of our operations will depend upon our ability to expand our customer base in our existing markets and to enter new markets in a timely manner at reasonable costs, organically or through acquisitions. In order for us to recover expenses incurred in entering new markets and obtaining new customers, we must attract and retain customers on economic terms and for extended periods. Customer growth depends on several factors outside of our control, including economic and demographic conditions, such as population changes, job and income growth, housing starts, new business formation and the overall level of economic activity. We may experience difficulty managing our growth and implementing new product offerings, integrating new customers and employees, and complying with applicable market rules and the infrastructure for product delivery.

State regulations may adversely impact customer acquisition and renewal revenue and profitability, and organic growth. For example, New York State limits the types of services energy retailer marketers may offer new customers or renewals, in terms of pricing for non-renewable commodities and renewable product offerings.

Expanding our operations also may require continued development of our operating and financial controls and may place additional stress on our management and operational resources. We may be unable to manage our growth and development successfully.









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Our financial results fluctuate on a seasonal, quarterly and annual basis.
Our overall operating results fluctuate substantially on a seasonal, quarterly and annual basis depending on: (1) the geographic mix of our customer base; (2) the relative concentration of our commodity mix; (3) weather conditions, which directly influence the demand for natural gas and electricity and affect the prices of energy commodities; and (4) variability in market prices for natural gas and electricity. These factors can have material short-term impacts on monthly and quarterly operating results, which may be misleading when considered outside of the context of our annual operating cycle. In addition, our accounts payable and accounts receivable are impacted by seasonality due to the timing differences between when we pay our suppliers for accounts payable versus when we collect from our customers on accounts receivable. We typically pay our suppliers for purchases of natural gas on a monthly basis and electricity on a weekly basis. However, it takes approximately two months from the time we deliver the electricity or natural gas to our customers before we collect from our customers on accounts receivable attributable to those product deliveries. This timing difference could affect our cash flows, especially during peak cycles in the winter and summer months. Furthermore, as a result of the seasonality of our business, we may reserve a portion of our excess cash available for distribution in the first and fourth quarters in order to fund our second and third quarter distributions.
Additionally, we enter into a variety of financial derivative and physical contracts to manage commodity price risk, and we use mark-to-market accounting to account for this hedging activity. Under the mark-to-market accounting method, changes in the fair value of our hedging instruments that are not qualifying or not designated as hedges under accounting rules are recognized immediately in earnings. As a result of this accounting treatment, changes in the forward prices of natural gas and electricity cause volatility in our quarterly and annual earnings, which we are unable to fully anticipate.
We could also incur volatility from quarter to quarter associated with gains and losses on settled hedges relating to natural gas held in inventory if we choose to hedge the summer-winter spread on our retail allocated storage capacity. We typically purchase natural gas inventory and store it from April to October for withdrawal from November through March. Since a portion of the inventory is used to satisfy delivery obligations to our fixed-price customers over the winter months, we hedge the associated price risk using derivative contracts. Any gains or losses associated with settled derivative contracts are reflected in the statement of operations as a component of retail cost of sales and net asset optimization.
We may have difficulty retaining our existing customers or obtaining a sufficient number of new customers, due to competition and for other reasons.
The markets in which we compete are highly competitive, and we may face difficulty retaining our existing customers or obtaining new customers due to competition. We encounter significant competition from local regulated utilities or their retail affiliates and traditional and new retail energy providers. Competitors may offer different products, lower prices, and other incentives, which may attract customers away from our business. Many of these competitors or potential competitors are larger than us, have access to more significant capital resources, have stronger vendor relationships, have more well-established brand names and have larger existing installed customer bases.
Additionally, existing customers may switch to other retail energy service providers during their contract terms in the event of a significant decrease in the retail price of natural gas or electricity in order to obtain more favorable prices. Although we generally have a right to collect a termination fee from each customer on a fixed-price contract who terminates their contract early, we may not be able to collect the termination fees in full or at all. Our variable-price contracts can typically be terminated by our customers at any time without penalty. We may be unable to obtain new customers or maintain our existing customers due to competition or otherwise.


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Increased collateral requirements in connection with our supply activities may restrict our liquidity.
Our contractual agreements with certain local regulated utilities and our supplier counterparties require us to maintain restricted cash balances or letters of credit as collateral for credit risk or the performance risk associated with the future delivery of natural gas or electricity. These collateral requirements may increase as we grow our customer base. Collateral requirements will increase based on the volume or cost of the commodity we purchase in any given month and the amount of capacity or service contracted for with the local regulated utility. Significant changes in market prices also can result in fluctuations in the collateral that local regulated utilities or suppliers require.
The effectiveness of our operations and future growth depend in part on the amount of cash and letters of credit available to enter into or maintain these contracts. The cost of these arrangements may be affected by changes in credit markets, such as interest rate spreads in the cost of financing between different levels of credit ratings. These liquidity requirements may be greater than we anticipate or are able to meet.

We face risks related to health epidemics, pandemics and other outbreaks.

Epidemics, widespread illness or other major health crises, such as COVID-19, may adversely affect the United States' economic growth, demand for natural gas and electricity in our key markets as well as the ability of various employees, customers, contractors, suppliers and other business partners to fulfill their obligations, which could have a material adverse effect on our business, financial condition or results of operations. Actions taken by governmental authorities and third parties to contain and mitigate the risk of spread of any major public health crisis, including COVID-19, may negatively impact our business, including a disruption of or change to our operating plans.

We are subject to direct credit risk for certain customers who may fail to pay their bills as they become due.
We bear direct credit risk related to customers located in markets that have not implemented POR programs as well as indirect credit risk in those POR markets that pass collection efforts along to us after a specified non-payment period. For the year ended December 31, 2023, customers in non-POR markets represented approximately 45% of our retail revenues. We generally have the ability to terminate contracts with customers in the event of non-payment, but in most states in which we operate we cannot disconnect their natural gas or electricity service. In POR markets where the local regulated utility has the ability to return non-paying customers to us after specified periods, we may realize a loss for one to two billing periods until we can terminate these customers’ contracts. We may also realize a loss on fixed-price customers in this scenario due to the fact that we will have already fully hedged the customer’s expected commodity usage for the life of the contract and we also remain liable to our suppliers of natural gas and electricity for the cost of our supply commodities. Furthermore, in the Texas market, we are responsible for billing the distribution charges for the local regulated utility and are at risk for these charges, in addition to the cost of the commodity, in the event customers fail to pay their bills. Changing economic factors, such as rising unemployment rates and energy prices also result in a higher risk of customers being unable to pay their bills when due.

We depend on the accuracy of data in our information management systems, which subjects us to risks.
We depend on the accuracy and timeliness of our information management systems for billing, collections, consumption and other important data. We rely on many internal and external sources for this information, including:
our marketing, pricing and customer operations functions; and
various local regulated utilities and ISOs for volume or meter read information, certain billing rates and billing types (e.g., budget billing) and other fees and expenses.
Inaccurate or untimely information, which may be outside of our direct control, could result in:
inaccurate and/or untimely bills sent to customers;
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incorrect tax remittances;
reduced effectiveness and efficiency of our operations;
inability to adequately hedge our portfolio;
increased overhead costs;
inaccurate accounting and reporting of customer revenues, gross margin and accounts receivable activity;
inaccurate measurement of usage rates, throughput and imbalances;
customer complaints; and
increased regulatory scrutiny.
We are also subject to disruptions in our information management systems arising out of events beyond our control, such as natural disasters, pandemics, epidemics, failures in hardware or software, power fluctuations, telecommunications and other similar disruptions.

Cyberattacks and data security breaches could adversely affect our business.

Cybersecurity risks have increased in recent years as a result of the proliferation of new technologies and the increased sophistication, magnitude and frequency of cyberattacks and data security breaches. A cyber-attack on our information management systems or those of our vendors could severely disrupt business operations, preventing us from billing and collecting revenues, and could result in significant expenses to investigate and repair security breaches or system damage, lead to litigation, fines, other remedial action, heightened regulatory scrutiny, diminished customer confidence and damage to our reputation. Although we maintain cyber-liability insurance that covers certain damage caused by cyber events, it may not be sufficient to cover us in all circumstances.
Our success depends on key members of our management, the loss of whom could disrupt our business operations.
We depend on the continued employment and performance of key management personnel. A number of our senior executives have substantial experience in consumer and energy markets that have undergone regulatory restructuring and have extensive risk management and hedging expertise. We believe their experience is important to our continued success. We do not maintain key life insurance policies for our executive officers. Our key executives may not continue in their present roles and may not be adequately replaced.

We rely on third party vendors for our customer acquisition verification, billing and transactions platform that exposes us to third party performance risk and other risk.
We have outsourced our back office customer billing and transactions platforms to third party vendors, and we rely heavily on the continued performance of the vendors under our current outsourcing agreement. Our vendors may fail to operate in accordance with the terms of the outsourcing agreement, be subject to cyber-security attacks, or a bankruptcy or other event may prevent them from performing under our outsourcing agreement.
A large portion of our current customers are concentrated in a limited number of states, making us vulnerable to customer concentration risks.
As of December 31, 2023, approximately 59% of our RCEs were located in five states. Specifically, 21%, 11%, 11%, 8% and 7% of our customers on an RCE basis were located in PA, TX, NY, NJ, and MA, respectively. If we are unable to increase our market share across other competitive markets or enter into new competitive markets effectively, we may be subject to continued or greater customer concentration risk. The states that contain a large percentage of our customers could reverse regulatory restructuring or change the regulatory environment in a manner that causes us to be unable to operate economically in that state.

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Increases in state renewable portfolio standards or an increase in the cost of renewable energy credit and carbon offsets may adversely impact the price, availability and marketability of our products.

Pursuant to state renewable portfolio standards, we must purchase a specified amount of RECs based on the amount of electricity we sell in a state in a year. In addition, we have contracts with certain customers that require us to purchase RECs or carbon offsets and as part of sustainability efforts have made a corporate commitment to fully offset 100% of customer volume beginning on April 1, 2021 with RECS or carbon offsets. If a state increases its renewable portfolio standards, the demand for RECs within that state will increase and therefore the market price for RECs could increase. We attempt to forecast the price for the required RECs and carbon offsets at the end of each month and incorporate this forecast into our customer pricing models, but the price paid for RECs and carbon offsets may be higher than forecasted. We may be unable to fully pass the higher cost of RECs through to our customers, and increases in the price of RECs may decrease our results of operations and affect our ability to compete with other energy retailers that have not contracted with customers to purchase RECs or carbon offsets. Further, a price increase for RECs or carbon offsets may require us to decrease the renewable portion of our energy products, which may result in a loss of customers. A further reduction in benefits received by local regulated utilities from production tax credits in respect of renewable energy may adversely impact the availability to us, and marketability by us, of renewable energy under our brands.
Our access to marketing channels may be contingent upon the viability of our telemarketing and door-to-door agreements with our vendors.

Our vendors are essential to our telemarketing and door-to-door sales activities. Our ability to increase revenues in the future will depend significantly on our access to high quality vendors. If we are unable to attract new vendors and retain existing vendors to achieve our marketing targets, our growth may be materially reduced. There can be no assurance that competitive conditions will allow these vendors and their independent contractors to continue to successfully sign up new customers. Further, if our products are not attractive to, or do not generate sufficient revenue for our vendors, we may lose our existing relationships. In addition, the decline in landlines reduces the number of potential customers that may be reached by our telemarketing efforts and, as a result, our telemarketing sales channel may become less viable and we may be required to use more door-to-door marketing. Door-to-door marketing is continually under scrutiny by state regulators and legislators, which may lead to new rules and regulations that impact our ability to use these channels.

Our vendors may expose us to risks.

We are subject to reputational risks that may arise from the actions of our vendors and their independent contractors that are wholly or partially beyond our control, such as violations of our marketing policies and procedures as well as any failure to comply with applicable laws and regulations. If our vendors engage in marketing practices that are not in compliance with local laws and regulations, we may be in breach of applicable laws and regulations that may result in regulatory proceedings, disadvantageous conditioning of our energy retailer license, or the revocation of our energy retailer license. Unauthorized activities in connection with sales efforts by agents of our vendors, including calling consumers in violation of the TCPA and predatory door-to-door sales tactics and fraudulent misrepresentation could subject us to class action lawsuits against which we will be required to defend. Such defense efforts will be costly and time consuming. In addition, the independent contractors of our vendors may consider us to be their employer and seek compensation.
We rely on third party vendors for our customer billing and transactions platform that exposes us to third party performance risk and cyber-security risk. We have outsourced our back office customer verification, billing and transactions platforms to third party vendors, and we rely heavily on the continued performance of the vendors under our current outsourcing agreement. Our vendors may fail to operate in accordance with the terms of the outsourcing agreement or a bankruptcy or other event may prevent them from performing under our outsourcing agreement.

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Risks Related to Our Capital Structure and Capital Stock

Our indebtedness could adversely affect our ability to raise additional capital to fund our operations or pay dividends. It could also expose us to the risk of increased interest rates and limit our ability to react to changes in the economy or our industry as well as impact our cash available for distribution.
We have $97.0 million of indebtedness outstanding and $24.3 million in issued letters of credit under our Senior Credit Facility, and no indebtedness outstanding under our Subordinated Facility as of December 31, 2023. Debt we incur under our Senior Credit Facility, Subordinated Facility or otherwise could have negative consequences, including:
increasing our vulnerability to general economic and industry conditions;
requiring cash flow from operations to be dedicated to the payment of principal and interest on our indebtedness, therefore reducing or eliminating our ability to pay dividends to holders of our Class A common stock and Series A Preferred Stock, or to use our cash flow to fund our operations, capital expenditures and future business opportunities;
limiting our ability to fund future acquisitions or engage in other activities that we view as in our long-term best interest;
restricting our ability to make certain distributions with respect to our capital stock and the ability of our subsidiaries to make certain distributions to us, in light of restricted payment and other financial covenants, including requirements to maintain certain financial ratios, in our credit facilities and other financing agreements;
exposing us to the risk of increased costs due to changes in interest rates because certain of our borrowings are at variable rates of interest;
limiting our ability to obtain additional financing for working capital including collateral postings, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes; and
limiting our ability to adjust to changing market conditions and placing us at a competitive disadvantage compared to our competitors who have less debt.
If we are unable to satisfy financial covenants in our debt instruments, it could result in an event of default that, if not cured or waived, may entitle the lenders to demand repayment or enforce their security interests. Our Senior Credit Facility will mature in June 30, 2025, and we cannot assure that we will be able to negotiate a new credit arrangement on commercially reasonable terms.
In addition, our ability to arrange financing and the costs of such capital, are dependent on numerous factors, including:
general economic and capital market conditions;
credit availability from banks and other financial institutions;
investor confidence;
our financial performance and the financial performance of our subsidiaries;
our level of indebtedness and compliance with covenants in debt agreements;
maintenance of acceptable credit ratings;
cash flow; and
provisions of tax and securities laws that may impact raising capital.

We may not be successful in obtaining additional capital for these or other reasons. The failure to obtain additional capital from time to time may have a material adverse effect on its business and operations.
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Our ability to pay dividends depends 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 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;
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. 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 Series A Preferred Stock during the period.

Each new share of Series A Preferred Stock issued increases the cash required to continue to pay cash dividends. Any 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, future dividends are 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 dividends to the holders of the Series A Preferred Stock. Even if we are permitted to pay such dividends on the Series A Preferred Stock, our Board of Directors may elect to reduce or eliminate the dividends on the Series A Preferred Stock to maintain cash balances for operations or for other reasons. Any reduction or elimination of cash dividends on our Series A Preferred Stock will likely materially and adversely affect the price of the Series A Preferred Stock.

We are a holding company. Our sole material asset is our equity interest in Spark HoldCo, LLC ("Spark HoldCo") and we are accordingly dependent upon distributions from Spark HoldCo to pay dividends on the Series A Preferred Stock.

We are a holding company and have no material assets other than our equity interest in Spark HoldCo, and have no independent means of generating revenue. Therefore, we depend on distributions from Spark HoldCo to meet our debt service and other payment obligations, and to pay dividends on our Series A Preferred Stock. Spark HoldCo or its subsidiaries may be restricted from making distributions to us under applicable law or regulation or under the terms of their financing arrangements, or may otherwise be unable to provide such funds.

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The Class A common stock and Series A Preferred Stock are subordinated to our existing and future debt obligations.
The Class A common stock and Series A Preferred Stock are subordinated to all of our existing and future indebtedness (including indebtedness outstanding under the Senior Credit Facility). Therefore, if we become bankrupt, liquidate our assets, reorganize or enter into certain other transactions, assets will be available to pay our obligations with respect to the Series A Preferred Stock only after we have paid all of our existing and future indebtedness in full. The Class A common stock will only receive assets to the extent all existing and future indebtedness and obligations under the Series A Preferred Stock is paid in full. If any of these events were to occur, there may be insufficient assets remaining to make any payments to holders of the Series A Preferred Stock or Class A common stock.

Additionally, none of our subsidiaries have guaranteed or otherwise become obligated with respect to the Class A common stock or Series A Preferred Stock. As a result, the Class A common stock and Series A Preferred Stock effectively rank junior to all existing and future indebtedness and other liabilities of our subsidiaries, including our operating subsidiaries, and any capital stock of our subsidiaries not held by us. Accordingly, our right to receive assets from any of our subsidiaries upon our bankruptcy, liquidation or reorganization, and the right of holders of shares of Class A common stock and Series A Preferred Stock to participate in those assets, is also structurally subordinated to claims of that subsidiary’s creditors, including trade creditors. Even if we were a creditor of any of our subsidiaries, our rights as a creditor would be subordinate to any security interest in the assets of that subsidiary and any indebtedness of that subsidiary senior to that held by us.
Numerous factors may affect the trading price of the Class A common stock and Series A Preferred Stock.

The trading price of the Class A common stock and Series A Preferred Stock may depend on many factors, some of which are beyond our control. Additionally, the market price of our Class A common stock and Series A Preferred Stock may be highly volatile and may fluctuate substantially as a result of a number of factors. The following factors are beyond our control and could affect our stock price:
the pending merger, and if it is completed;
the impact of our reverse stock split on our common stock;
the announcement of the elimination, suspension, reduction or reinstatement of dividends on Class A common stock and Series A Preferred Stock;
the public reaction to our press releases, our other public announcements and our filings with the SEC;
trading volumes of the Class A common stock and Series A Preferred Stock;
prevailing interest rates;
the market for similar securities;
general economic and financial market conditions;
our issuance of debt or other preferred equity securities; and
our financial condition, results of operations and prospects.

These and other factors may cause the market price and demand for our Class A common stock and Series A Preferred Stock to fluctuate substantially, which may adversely affect the trading price of our Class A common stock and Series A Preferred Stock. In the past, when the market price of a stock has been volatile, holders of that stock have often instituted securities class action litigation against the company that issued the stock. If any of our stockholders brought a lawsuit against us, we could incur substantial defense costs. Such a lawsuit could also divert the time and attention of our management from our business. Trading prices and corresponding market value of Class A common stock and Series A Preferred Stock may also impact our ability to satisfy continued listing standards of The Nasdaq Global Select Market, or a particular tier of The Nasdaq exchanges.

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One of the factors that will influence the price of the Class A common stock and Series A Preferred Stock will be the distribution yield of the securities (as a percentage of the then market price of the securities) relative to market interest rates. Increases in market interest rates, which have been at low levels relative to historical rates, may lead prospective purchasers of shares of Class A common stock or Series A Preferred Stock to expect a higher distribution yield, and cause them to sell their Class A common stock or Series A Preferred Stock. Accordingly, higher market interest rates could cause the market price of the Class A common stock and Series A Preferred Stock to decrease.

In addition, over the last several years, prices of equity securities in the U.S. trading markets have been experiencing extreme price fluctuations. As a result of these and other factors, investors holding our Class A common stock and Series A Preferred Stock may experience a decrease in the value of their securities, which could be substantial and rapid, and could be unrelated to our financial condition, performance or prospects.
There may not be an active trading market for the Class A common stock or Series A Preferred Stock, which may in turn reduce the market value and your ability to transfer or sell your shares of Class A common stock or Series A Preferred Stock.
There are no assurances that there will be an active trading market for our Class A common stock or Series A Preferred Stock. The liquidity of any market for the Class A common stock and Series A Preferred Stock depends upon the number of stockholders, our results of operations and financial condition, the market for similar securities, the interest of securities dealers in making a market in the Class A common stock and Series A Preferred Stock, and other factors. To the extent that an active trading market is not maintained, the liquidity and trading prices for the Class A common stock and Series A Preferred Stock may be harmed.
Furthermore, because the Series A Preferred Stock does not have any stated maturity and is not subject to any sinking fund or mandatory redemption, stockholders seeking liquidity will be limited to selling their respective shares of Series A Preferred Stock in the secondary market. Active trading markets for the Series A Preferred Stock may not exist at such times, in which case the trading price of your shares of our Series A Preferred Stock could be reduced and your ability to transfer such shares could be limited.
Mr. Maxwell holds a substantial majority of the voting power of our common stock.

Holders of Class A 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 our certificate of incorporation and bylaws. Mr. Maxwell beneficially owns approximately 65.0% of the combined voting power (excluding treasury shares) of the Class A and Class B common stock as of December 31, 2023 through his direct and indirect ownership in us.
Affiliated owners are entitled to act separately with respect to their investment in us, and they have the ability to elect all of the members of our board of directors, and thereby to control our management and affairs. In addition, affiliates are able to determine the outcome of all matters requiring Class A common stock and Class B common stock shareholder approval, including mergers and other material transactions, and are able to cause or prevent a change in the composition of our board of directors or a change in control of our company that could deprive our stockholders of an opportunity to receive a premium for their Class A common stock as part of a sale of our company. The existence of a significant shareholder, such as Mr. Maxwell, may also have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other stockholders to approve transactions that they may deem to be in the best interests of our company.
So long as affiliates continue to control a significant amount of our common stock, they will continue to be able to strongly influence all matters requiring shareholder approval, regardless of whether other stockholders believe that a potential transaction is in their own best interests. In any of these matters, the interests of affiliates may differ or conflict with the interests of our other stockholders. Moreover, this concentration of stock ownership may also adversely affect the trading price of our Class A common stock or Series A Preferred Stock to the extent investors perceive a disadvantage in owning stock of a company with a controlling shareholder.
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Holders of Series A Preferred Stock have extremely limited voting rights.
Voting rights of holders of shares of Series A Preferred Stock are extremely limited. Our Class A common stock and our Class B common stock are the only classes of our securities carrying full voting rights. Holders of the Series A Preferred Stock generally have no voting rights. As of April 15, 2022, we have the option to redeem our Series A Preferred Stock.
We have engaged in transactions with our affiliates in the past and expect to do so in the future. The terms of such transactions and the resolution of any conflicts that may arise may not always be in our or our stockholders’ best interests.

We have engaged in transactions and expect to continue to engage in transactions with affiliated companies. We have acquired companies and books of customers from our affiliates and may do so in the future. We will continue to enter into back-to-back transactions for purchases of commodities and derivatives on behalf of our affiliate. We will also continue to pay certain expenses on behalf of several of our affiliates for which we will seek reimbursement. We will also continue to share our corporate headquarters with certain affiliates. We cannot assure that our affiliates will reimburse us for the costs we have incurred on their behalf or perform their obligations under any of these contracts.
Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our Class A common stock.

Our amended and restated certificate of incorporation authorizes our board of directors to issue preferred stock without shareholder approval. On August 5, 2022, we filed a registration statement under the Securities Act on Form S-3 allowing us to offer and sell, from time to time, among other securities, shares of preferred stock. The registration statement was declared effective on August 16, 2022. The election by our board of directors to issue preferred stock with anti-takeover provisions could make it more difficult for a third party to acquire us.
In addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders. Among other things, our amended and restated certificate of incorporation and amended and restated bylaws:
provide for our board of directors to be divided into three classes of directors, with each class as nearly equal in number as possible, serving staggered three year terms. Our staggered board may tend to discourage a third party from making a tender offer or otherwise attempting to obtain control of us, because it generally makes it more difficult for shareholders to replace a majority of the directors;
provide that the authorized number of directors may be changed only by resolution of the board of directors;
provide that all vacancies in our board, including newly created directorships, may, except as otherwise required by law or, if applicable, the rights of holders of a series of preferred stock, be filled by the affirmative vote of a majority of directors then in office, even if less than a quorum;
provide our board of directors the ability to authorize undesignated preferred stock. This ability makes it possible for our board of directors to issue, without shareholder approval, preferred stock with voting or other rights or preferences that could impede the success of any attempt to change control of us. These and other provisions may have the effect of deferring hostile takeovers or delaying changes in control or management of our company;
provide that at any time after the first date upon which Mr. Maxwell no longer beneficially owns more than fifty percent of the outstanding Class A common stock and Class B common stock, any action required or permitted to be taken by the shareholders must be effected at a duly called annual or special meeting of shareholders and may not be effected by any consent in writing in lieu of a meeting of such shareholders, subject to the rights of the holders of any series of preferred stock with respect to such series (prior to such time, such actions may be taken without a meeting by written consent of holders of the outstanding stock having not less than the minimum number of votes that would be necessary to authorize or take such action at a meeting);
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provide that at any time after the first date upon which Mr. Maxwell no longer beneficially owns more than fifty percent of the outstanding Class A common stock and Class B common stock, special meetings of our shareholders may only be called by the board of directors, the chief executive officer or the chairman of the board (prior to such time, special meetings may also be called by our Secretary at the request of holders of record of fifty percent of the outstanding Class A common stock and Class B common stock);
provide that our amended and restated certificate of incorporation and amended and restated bylaws may be amended by the affirmative vote of the holders of at least two-thirds of our outstanding stock entitled to vote thereon;
provide that our amended and restated bylaws can be amended by the board of directors; and
establish advance notice procedures with regard to shareholder proposals relating to the nomination of candidates for election as directors or new business to be brought before meetings of our shareholders. These procedures provide that notice of shareholder proposals must be timely given in writing to our corporate secretary prior to the meeting at which the action is to be taken. These requirements may preclude shareholders from bringing matters before the shareholders at an annual or special meeting.
In addition, in our amended and restated certificate of incorporation, we have elected not to be subject to the provisions of Section 203 of the Delaware General Corporation Law (the “DGCL”) regulating corporate takeovers until the date on which Mr. Maxwell no longer beneficially owns in the aggregate more than fifteen percent of the outstanding Class A common stock and Class B common stock. On and after such date, we will be subject to the provisions of Section 203 of the DGCL.
Our amended and restated certificate of incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.

Our amended and restated certificate of incorporation provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim against us or any director or officer or other employee of ours arising pursuant to any provision of the DGCL, our amended and restated certificate of incorporation or our bylaws, or (iv) any action asserting a claim against us or any director or officer or other employee of ours that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. This exclusive forum provision would not apply to suits brought to enforce any liability or duty created by the Securities Act or the Exchange Act or any other claim for which the federal courts have exclusive jurisdiction. To the extent that any such claims may be based upon federal law claims, Section 27 of the Exchange Act creates exclusive federal jurisdiction over all suits brought to enforce any duty or liability created by the Exchange Act or the rules and regulations thereunder. Furthermore, Section 22 of the Securities Act creates concurrent jurisdiction for federal and state courts over all suits brought to enforce any duty or liability created by the Securities Act or the rules and regulations thereunder.

Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of our amended and restated certificate of incorporation described in the preceding sentence. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our amended and restated certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.
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Future sales of our Class A common stock and Series A Preferred Stock in the public market could reduce the price of the Class A common stock and Series A Preferred Stock, and may dilute your ownership in us.

On August 5, 2022, we filed a registration statement under the Securities Act on Form S-3 registering the primary offer and sale, from time to time, of Class A common stock, preferred stock, depositary shares and warrants. The registration statement also registers the Class A common stock held by our affiliates, Retailco and NuDevco (including Class A common stock that may be obtained upon conversion of Class B common stock). All of the shares of Class A common stock held by Retailco and NuDevco and registered on the registration statement may be immediately resold. The registration statement was declared effective on August 16, 2022.
We cannot predict the size of future issuances of our Class A common stock or securities convertible into Class A common stock or the effect, if any, that future issuances or sales of shares of our Class A common stock will have on the market price of our Class A common stock. Sales of substantial amounts of our Class A common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our Class A common stock.

We may also in the future sell additional shares of preferred stock, including shares of Series A Preferred Stock, on terms that may differ from those we have previously issued. Such shares could rank on parity with or, subject to the voting rights referred to above (with respect to issuances of new series of preferred stock), senior to the Series A Preferred Stock as to distribution rights or rights upon liquidation, winding up or dissolution. The subsequent issuance of additional shares of Series A Preferred Stock, or the creation and subsequent issuance of additional classes of preferred stock on parity with the Series A Preferred Stock, could dilute the interests of the holders of Series A Preferred Stock, and could affect our ability to pay distributions on, redeem or pay the liquidation preference on the Series A Preferred Stock. Any issuance of preferred stock that is senior to the Series A Preferred Stock would not only dilute the interests of the holders of Series A Preferred Stock, but also could affect our ability to pay distributions on, redeem or pay the liquidation preference on the Series A Preferred Stock.
Furthermore, subject to compliance with the Securities Act or exemptions therefrom, employees who have received Class A common stock as equity awards may also sell their shares into the public market.
We have issued preferred stock and may continue to do so, and the terms of such preferred stock could adversely affect the voting power or value of our Class A common stock.

Our certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our Class A common stock with respect to dividends and distributions, as our board of directors may determine. Through December 31, 2023, we have issued an aggregate of 3,567,543 shares of Series A Preferred Stock.
The terms of the preferred stock we offer or sell could adversely impact the voting power or value of our Class A common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock, such as the Series A Preferred Stock, could affect the residual value of the Class A common stock.




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Our amended and restated certificate of incorporation limits the fiduciary duties of one of our directors and certain of our affiliates and restricts the remedies available to our stockholders for actions taken by Mr. Maxwell or certain of our affiliates that might otherwise constitute breaches of fiduciary duty.
Our amended and restated certificate of incorporation contains provisions that we renounce any interest in existing and future investments in other entities by, or the business opportunities of, NuDevco Partners, LLC, NuDevco Partners Holdings, LLC and Mr. Maxwell, or any of their officers, directors, agents, shareholders, members, affiliates and subsidiaries (other than a director or officer who is presented an opportunity solely in his capacity as a director or officer). Because of this provision, these persons and entities have no obligation to offer us those investments or opportunities that are offered to them in any capacity other than solely as an officer or director. If one of these persons or entities pursues a business opportunity instead of presenting the opportunity to us, we will not have any recourse against such person or entity for a breach of fiduciary duty.
The Series A Preferred Stock represent perpetual equity interests in us, and investors should not expect us to redeem the Series A Preferred Stock on the date the Series A Preferred Stock becomes redeemable by us or on any particular date afterwards.

The Series A Preferred Stock represents a perpetual equity interest in us, and the securities have no maturity or mandatory redemption date and are not redeemable at the option of investors under any circumstances. As a result, unlike our indebtedness, the Series A Preferred Stock will not give rise to a claim for payment of a principal amount at a particular date. As a result, holders of the Series A Preferred Stock may be required to bear the financial risks of an investment in the Series A Preferred Stock for an indefinite period of time. In addition, the Series A Preferred Stock will rank junior to all our current and future indebtedness (including indebtedness outstanding under the Senior Credit Facility) and other liabilities. The Series A Preferred Stock will also rank junior to any other preferred stock ranking senior to the Series A Preferred Stock we may issue in the future with respect to assets available to satisfy claims against us.
The Series A Preferred Stock is not rated.

We have not sought to obtain a rating for the Series A Preferred Stock, and the Series A Preferred Stock may never be rated. It is possible, however, that one or more rating agencies might independently determine to assign a rating to the Series A Preferred Stock or that we may elect to obtain a rating of the Series A Preferred Stock in the future. In addition, we may elect to issue other securities for which we may seek to obtain a rating. If any ratings are assigned to the Series A Preferred Stock in the future or if we issue other securities with a rating, such ratings, if they are lower than market expectations or are subsequently lowered or withdrawn, could adversely affect the market for or the market value of the Series A Preferred Stock. Ratings only reflect the views of the issuing rating agency or agencies and such ratings could at any time be revised downward or withdrawn entirely at the discretion of the issuing rating agency. A rating is not a recommendation to purchase, sell or hold any particular security, including the Series A Preferred Stock. Ratings do not reflect market prices or suitability of a security for a particular investor and any future rating of the Series A Preferred Stock may not reflect all risks related to us and our business, or the structure or market value of the Series A Preferred Stock.
The Change of Control Conversion Right may make it more difficult for a party to acquire us or discourage a party from acquiring us.

The Change of Control Conversion Right of the Series A Preferred Stock provided in the Certificate of Designation may have the effect of discouraging a third party from making an acquisition proposal for us or of delaying, deferring or preventing certain of our change of control transactions under circumstances that otherwise could provide the holders of our Series A Preferred Stock with the opportunity to realize a premium over the then-current market price of such equity securities or that stockholders may otherwise believe is in their best interests.


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Changes in the method of determining the Three-Month CME Term SOFR, or the replacement of Three-Month CME Term SOFR with an alternative reference rate, may adversely affect interest rates under the floating dividend rate of our Series A Preferred Stock.

Under the Certificate of Designation of the Series A Preferred Stock, dividends on the Series A Preferred Stock accrue at a floating rate equal to the sum of: (a) Three-Month LIBOR Rate as calculated on each applicable determination date, plus (b) 6.578%. LIBOR was a basic rate of interest widely used as a global reference for setting interest rates on loans and payment rates on other financial instruments, and ceased publication on June 30, 2023.

In accordance with the Adjustable Interest Rate (LIBOR) Act (the “LIBOR Act”) and the final regulations promulgated pursuant thereto by the Board of Governors of the Federal Reserve System (“Board”), the LIBOR Act specifies that the replacement benchmark rate on the Series A Preferred Stock following Three-Month LIBOR’s end of publication on June 30,2023 is Three-Month CME Term SOFR, as administered by CME Group Benchmark Administration, Ltd. (or any successor administrator), plus a tenor spread adjustment of 0.26161%.

New methods of calculating Three-Month CME Term SOFR or other reforms could cause the dividend rate on our Series A Preferred Stock to be materially different than expected, which could have an adverse effect on our business, financial position, and results of operations, and our ability to pay dividends on the Series A Preferred Stock.

A substantial increase in the Three-Month CME Term SOFR Rate or an alternative rate could negatively impact our ability to pay dividends on the Series A Preferred Stock.

A substantial increase in the Three-Month CME Term SOFR Rate, or a substantial increase in the alternative reference rate, could negatively impact our ability to pay dividends on the Series A Preferred Stock. If we are unable to pay dividends on the Series A Preferred Stock, the market value of the Series A Preferred Stock could be materially adversely impacted.
We may not have sufficient earnings and profits in order for dividends on the Series A Preferred Stock to be treated as dividends for U.S. federal income tax purposes.

The dividends payable by us on the Series A Preferred Stock may exceed our current and accumulated earnings and profits, as calculated for U.S. federal income tax purposes. If this occurs, it will result in the amount of the dividends that exceed such earnings and profits being treated for U.S. federal income tax purposes first as a return of capital to the extent of the beneficial owner’s adjusted tax basis in the Series A Preferred Stock, and the excess, if any, over such adjusted tax basis as gain from the sale or exchange of property, which generally results in capital gain. Such treatment will generally be unfavorable for corporate beneficial owners and may also be unfavorable to certain other beneficial owners.
You may be subject to tax if we make or fail to make certain adjustments to the conversion rate of the Series A Preferred Stock even though you do not receive a corresponding cash distribution.

The Conversion Rate as defined in the Certificate of Designation for the Series A Preferred Stock is subject to adjustment in certain circumstances. A failure to adjust (or to adjust adequately) the Conversion Rate after an event that increases your proportionate interest in us could be treated as a deemed taxable dividend to you. If you are a non-U.S. holder, any deemed dividend may be subject to U.S. federal withholding tax at a 30% rate, or such lower rate as may be specified by an applicable treaty, which may be set off against subsequent payments on the Series A Preferred Stock.

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We are a “controlled company” under NASDAQ Global Select Market rules, and as such we are entitled to an exemption from certain corporate governance standards of the NASDAQ Global Select Market, and you may not have the same protections afforded to shareholders of companies that are subject to all of the NASDAQ Global Market corporate governance requirements.
We qualify as a “controlled company” within the meaning of NASDAQ Global Select Market corporate governance standards because an affiliated holder controls more than 50% of our voting power. Under NASDAQ Global Select Market rules, a company of which more than 50% of the voting power is held by an individual, a group or another company is a “controlled company” and may elect not to comply with certain corporate governance requirements.

Although our board of directors has established a nominating and corporate governance committee and a compensation committee of independent directors, it may determine to eliminate these committees at any time. If these committees were eliminated, you may not have the same protections afforded to shareholders of companies that are subject to all of NASDAQ Global Select Market corporate governance requirements.

Item 1B. Unresolved Staff Comments

None.

Item 1C. Cybersecurity

Risk management and strategy

Via Renewables, Inc. recognizes the critical importance of developing, implementing, and maintaining robust cybersecurity measures to safeguard our information systems and protect the confidentiality, integrity, and availability of our data.

Managing Material Risks & Integrated Overall Risk Management

Via Renewables, Inc. has strategically integrated cybersecurity risk management into our broader risk management framework to promote a company-wide culture of cybersecurity risk management. This integration ensures that cybersecurity considerations are an integrated part of our decision-making processes at every level. Our risk management team works closely with our IT department to continuously evaluate and address cybersecurity risks in alignment with our business objectives and operational needs.

Engage Third parties on Risk Management

Recognizing the complexity and evolving nature of cybersecurity threats, Via Renewables, Inc. engages with a range of external experts, including cybersecurity assessors, consultants and auditors in evaluating and testing our risk management systems. These partnerships enable us to leverage specialized knowledge and insights, ensuring our cybersecurity strategies and processes remain at the forefront of industry best practices.

Oversee Third-party Risk

Because we are aware of the risks associated with third-party service providers, Via Renewables, Inc. implements stringent processes to oversee and manage these risks. We conduct thorough security assessments of all third-party providers before engagement and maintain ongoing monitoring to ensure compliance with our cybersecurity standards. This approach is designed to mitigate risks related to data breaches or other security incidents originating from third parties.

Risks from Cybersecurity Threats

We have not encountered cybersecurity challenges that have materially impaired our operations or financial standing.


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Governance

The Board of Directors is acutely aware of the critical nature of managing risks associated with cybersecurity threats. The Board has established a robust oversight mechanism to ensure effective governance in managing risks associated by cybersecurity threats because we recognize the significant of these threats to our operations integrity and stakeholder confidence.

Board of Directors Oversight

The Audit Committee is central to the Board’s oversight of cybersecurity risks and bears the primary responsibility for this domain. The Audit Committee is composed of board members with diverse expertise including, risk management, technology, and finance, equipping them to oversee cybersecurity risks effectively.

Management’s Role Managing Risk

The Chief Operating Officer plays a pivotal role in informing the Audit Committee on cybersecurity risks. The Chief Operating Officer provides comprehensive briefings to the Audit Committee on a regulatory basis, with a minimum frequency of once per year. These briefings encompass a broad range of topics including:
Current cybersecurity landscape and emerging threats;
Status of ongoing cybersecurity initiatives and strategies;
Incident reports and learnings from any cybersecurity events; and
Compliance with regulatory requirements and industry standards.

In addition to our scheduled meetings, the Audit Committee and Chief Operating Officer maintain an ongoing dialogue regarding emerging or potential cybersecurity risks. Together, they receive updates on any significant developments in the cybersecurity domain, ensuring the Board’s oversight is proactive and responsive. The Audit Committee actively participates in strategic decisions related to cybersecurity, offering guidance and approval for major initiatives. This involvement ensures that cybersecurity considerations are integrated into the broader strategic objectives of Via Renewables, Inc. The Audit Committee conducts an annual review of the Company’s cybersecurity program and the effectiveness of its risk management strategies. This review helps in identifying areas for improvement and ensuring the alignment of cybersecurity efforts with the overall risk management framework.

Risk Management Personnel

Primary responsibility for assessing, monitoring and managing our cybersecurity risk rests with the Director of Infrastructure. With over 26 years of experience in the field of cybersecurity, the Director of Infrastructure brings a wealth of expertise to his role. His in-depth knowledge and experience are instrumental in developing and executing our cybersecurity strategies. Our Director of Infrastructure oversees our governance programs, tests our compliance with standards, remediates known risks, and leads our employee training program.

Monitor Cybersecurity Incidents

The Director of Infrastructure is continually informed about the latest developments in cybersecurity, including potential threats and innovative risk management techniques. This ongoing knowledge acquisition is crucial for the effective prevention, detection, mitigation, and remediation of cybersecurity incidents. The Director of Infrastructure implements and oversees processes for the regulatory monitoring of our information systems. This includes the deployment of advanced security measures and regular system audits to identify potential vulnerabilities. In the event of a cybersecurity incident, the Director of Infrastructure is equipped with a well-defined incident response plan. This plan includes immediate actions to mitigate the impact and long-term strategies for remediation and prevention of future incidents.




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Reporting to the Board of Directors

The Director of Infrastructure, in his capacity, regularly informs the Chief Financial Officer (CFO) and Chief Operating Officer (COO) of all aspects related to cybersecurity risks and incidents. The CFO and COO regularly inform the Chief Executive Officer (CEO) of such risk and incidents. This ensures that the highest levels of management are kept abreast of the cybersecurity posture and potential risks facing Via Renewables, Inc. Furthermore, significant cybersecurity mattes, and strategic risk management decisions are escalated to the Board of Directors, ensuring that they have comprehensive oversight and can provide guidance on critical cybersecurity issues.

Item 3. Legal Proceedings

We are the subject of lawsuits and claims arising in the ordinary course of business from time to time. Management cannot predict the ultimate outcome of such lawsuits and claims. While the lawsuits and claims are asserted for amounts that may be material, should an unfavorable outcome occur, management does not currently expect that any currently pending matters will have a material adverse effect on our financial position or results of operations except as described in Part II, Item 8 “Financial Statements and Supplementary Data,” Note 13 "Commitments and Contingencies" to the audited consolidated financial statements, which are incorporated herein by reference.

Item 4. Mine Safety Disclosures.

Not applicable.
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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our Class A common stock is traded on the NASDAQ Global Select Market under the symbol “VIA." There is no public market for our Class B common stock. On February 27, 2024, we had we had three holders of record of our Class A common stock and two holders of record of our Class B common stock, excluding the Company, and stockholders for whom shares are held in “nominee” or “street name.” Shareholders of record, excluding Cede & Co. and the Company, held an aggregate of 94 shares.

Dividends

We have historically paid a cash dividend each quarter to holders of our Class A common stock to the extent we have cash available for distribution and are permitted to do so under the terms of our Senior Credit Facility, as well as paid dividends to the holders of our Series A Preferred Stock. In April 2023, we announced a suspension of the dividend on the Class A common stock. Our ability to pay dividends depends on certain factors, including the terms of our Senior Credit Facility, the performance of our business, cash flows, RCE counts and the margins we receive. Please see “Item 1A – Risk Factors” in this Annual Report for risks related to our ability to pay dividends.

Recent Sales of Unregistered Equity Securities

We have not sold any unregistered equity securities other than as previously reported.

Issuer Purchases of Equity Securities

We did not repurchase any equity securities between October 1, 2023 and December 31, 2023.

Stock Performance Graph

The following graph compares the quarterly performance of our Class A common stock to the NASDAQ Composite Index ("NASDAQ Composite") and the Dow Jones U.S. Utilities Index ("IDU"). The chart assumes that the value of the investment in our Class A common stock and each index was $100 at December 31, 2018 and that all dividends were reinvested. The stock performance shown on the graph below is not indicative of future price performance.

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1695

The performance graph above and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act or the Exchange Act, except to the extent that we specifically incorporate it by reference.
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Item 6. Reserved

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ITEM 7. 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 consolidated financial statements and the related notes thereto included elsewhere in this Annual Report. In this Annual Report, the terms “Via," "Via Renewables," "Spark Energy," “Company,” “we,” “us” and “our” refer collectively to Via Renewables, Inc. and its subsidiaries.
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 December 31, 2023, we operated in 104 utility service territories across 20 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 years ended December 31, 2023, 2022 and 2021, approximately 75%, 76% and 81%, 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 years ended December 31, 2023, 2022 and 2021, approximately 25%, 24% and 19%, respectively, of our retail revenues were derived from the sale of natural gas.

Recent Developments

On December 29, 2023, we entered into a merger agreement (the “Merger Agreement”) with Retailco, LLC, a Texas limited liability company (“Retailco”), and NuRetailco LLC, a Delaware limited liability company and wholly-owned subsidiary of Retailco (“Merger Sub”), whereby all of our Class A common stock (except for as described below), will be acquired by Retailco for $11.00 per share.

Retailco is an entity owned by TxEx, which is wholly owned by Mr. Maxwell.

The transaction will be effected by a merger of Merger Sub, with and into the Company, with the Company surviving the merger. Under the terms of the Merger Agreement, all of our Class A common stock, except for shares of Class A common stock for which appraisal rights have been properly and validly exercised under Delaware law and certain additional shares, including those held by the Company or any of its subsidiaries (or held in the Company’s treasury), Retailco or Merger Sub or any of their respective subsidiaries, or Mr. Maxwell, and any person or entity controlled by him, will be converted into the right to receive the cash consideration.

The Class A common stock, currently traded under the symbol VIA, will cease to trade on NASDAQ upon consummation of the transaction. We expect that the Series A Preferred Stock, currently traded under the symbol VIASP, will continue to trade on NASDAQ following the transaction. Accordingly, Via Renewables will remain subject to the reporting requirements of the Exchange Act.

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The transaction was negotiated on behalf of the Company by a Special Committee of its Board of Directors with the assistance of independent financial and legal advisors. The Special Committee is comprised of entirely disinterested and independent directors. Following the Special Committee’s unanimous recommendation in support of the merger, the Company’s Board of Directors (other than Mr. Maxwell) approved the Merger Agreement and recommended that the Company’s stockholders adopt and approve the Merger Agreement and the merger.

The merger is subject to approval by a majority of shareholders of the issued and outstanding shares of the Company’s Class A common stock and Class B common stock. In addition, the merger is subject to a non-waivable requirement of approval by the holders of at least a majority of the issued and outstanding Class A common stock and Class B common stock not owned by Mr. Maxwell and his affiliated entities or the directors, officers or their immediate family members. Mr. Maxwell and affiliated entities have entered into a support agreement to vote their shares in favor of the transaction and against any competing transaction. The Merger Agreement is not subject to a financing condition, but is subject to customary closing conditions. The transaction is expected to close in the second quarter of 2024.

Drivers of Our Business

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

Customer Growth

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

We measure our number of customers using residential customer equivalents ("RCEs"). The following table shows our RCEs by segment as of December 31, 2023, 2022 and 2021:
RCEs:
December 31,
(In thousands)202320222021
Retail Electricity217201298
Retail Natural Gas118130110
Total Retail335331408

The following table details our count of RCEs by geographical location as of December 31, 2023:
RCEs by Geographic Location:
(In thousands)Electricity % of TotalNatural Gas % of TotalTotal % of Total
New England6429%1210%7623%
Mid-Atlantic9544%5143%14644%
Midwest209%2017%4012%
Southwest3818%3530%7321%
Total217100%118100%335100%

The geographical locations noted above include the following states:

New England - Connecticut, Maine, Massachusetts and New Hampshire;
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Mid-Atlantic - Delaware, Maryland (including the District of Columbia), New Jersey, New York, Pennsylvania and Virginia;
Midwest - Illinois, Indiana, Michigan and Ohio; and
Southwest - Arizona, California, Colorado, Florida, Nevada and Texas.

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 year ended December 31, 2023, we added approximately 140,000 RCEs through our various organic sales channels. Following the COVID-19 pandemic we have continued to focus on refining our existing sales channels and carefully growing both door to door and telemarketing sales while remaining focused on sales quality.

We expect our customer growth to continue to increase, however, we are unable to predict the ultimate effect of market conditions on our organic sales, financial results, cash flows, and liquidity at this time.

In December 2023, the FCC adopted rules that could limit the ability of third-party lead generators to identify large numbers of potential customers. If the number of potential customers is reduced, or if it becomes more difficult or costly to identify potential telemarketing targets, our ability to maintain our RCE count based on our telemarketing sales could be impacted.

We continue to target customer growth and seek to increase our customer growth to more historical levels. However, market conditions and regulatory constraints are making this increasingly difficult, and we are unable to predict future organic sales volumes at this time

We also acquire companies and portfolios of customers through both external and affiliated channels. During the year ended December 31, 2023, we did not add any RCEs through acquisitions or asset purchase agreements. Refer to Note 16 “Customer Acquisitions” for further discussion. 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 2024.

RCE Activity

The following table shows our RCE activity during the years ended December 31, 2023, 2022 and 2021.
(In thousands)Retail ElectricityRetail Natural GasTotal% Net Annual Increase (Decrease)
December 31, 202030397400
   Additions11047157
   Attrition(115)(34)(149)
December 31, 20212981104082%
Additions404686
Attrition(137)(26)(163)
December 31, 2022201130331(19)%
Additions11822140
Attrition(102)(34)(136)
December 31, 20232171183351%

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Customer attrition occurs primarily as a result of: (i) customer initiated switches; (ii) residential moves (iii) disconnection resulting from customer payment defaults and (iv) pro-active non-renewal of contracts. Average monthly attrition rates during 2023, 2022 and 2021 were as follows:
Year EndedQuarter Ended
December 31December 31September 30June 30March 31
20213.3%3.4%2.4%3.3%4.2%
20223.8%4.2%4.0%3.1%3.7%
20233.4%3.3%3.1%3.1%3.9%


Customer attrition during the year ended December 31, 2022 was higher than the year ended December 31, 2021 due to the sharp increase in commodity prices across the industry.

Customer attrition for the year ended December 31, 2023 was lower than the year ended ended December 31, 2022 prior year due to a decrease in commodity prices across the industry in 2023, compared to 2022.

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. For each of the three years ended December 31, 2023, customer acquisition costs were as follows:
Year Ended December 31,
(In thousands)202320222021
Customer Acquisition Costs$6,736 $5,870 $1,415 

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

As described above, certain public utility commissions, regulatory agencies, and other governmental authorities in all of our markets had issued orders that impacted the way we have historically acquired customers, such as door to door marketing. Our reduced marketing resulted in significantly reduced customer acquisition costs during the twelve months ended December 31, 2021, compared to historical amounts.

Our gradual increase of marketing efforts as restrictions were lifted resulted in increased marketing and customer acquisition costs. Customer acquisition costs with respect to door to door marketing returned back to pre-Covid-19 historic levels in 2022 and 2023.






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Customer Credit Risk

Approximately 55% of our revenues are derived from customers in utilities where customer credit risk is borne by the utility in exchange for a discount on amounts billed. Where we have customer credit risk, we record bad debt based on an estimate of uncollectible amounts. Our bad debt expense on non-POR revenues was as follows:
Year Ended December 31,
202320222021
Total Non-POR Bad Debt as Percent of Revenue1.7 %3.0 %0.2 %

During the year ended December 31, 2023, we experienced lower credit loss expense versus 2022. We increased sales activities in non-POR markets in 2023 and focused on collection efforts, we have experienced a decrease in credit loss expense.

During the year ended December 31, 2022, we experienced higher credit loss expense versus 2021 primarily due to the Company increasing sales activities in non-POR markets and the impact of increased defaults on customer billings, in part due to higher natural gas and electricity prices.

For the years ended December 31, 2023, 2022 and 2021, approximately 55%, 59% and 59%, respectively, of our retail revenues were collected through POR programs where substantially all of our credit risk was with local regulated utility companies. As of December 31, 2023, 2022 and 2021, all of these local regulated utility companies had investment grade ratings. During these same periods, we paid these local regulated utilities a weighted average discount of approximately 1.0%, 0.9% and 0.9%, respectively, of total revenues for customer credit risk protection.

Weather Conditions

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

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

Winter Storm Uri

During the first quarter of 2021, the U.S. experienced winter storm Uri, an unprecedented storm bringing extreme cold temperatures to the central U.S., including Texas. As a result of increased power demand for customers across the state of Texas and power generation disruptions during the weather event, power and ancillary costs in the ERCOT service area reached or exceeded maximum allowed clearing prices. As of December 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. In June 2022, we received $9.6 million from ERCOT related to PURA Subchapter N Financing, resulting in a positive impact on our electricity unit margin in 2022.

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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 $7.3 million, $2.3 million of $4.2 million for the years ended December 31, 2023, 2022 and 2021, respectively.
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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. These measures for the three years ended December 31, 2023 were as follows:
 Year Ended December 31,
(in thousands)202320222021
Adjusted EBITDA (1)(2)(3)
$56,855 $51,793 $80,657 
Retail Gross Margin (4)(5)
$136,650 $114,815 $132,534 
(1) Adjusted EBITDA for the year ended December 31, 2021 includes a $60.0 million add back related to winter storm Uri and also includes a deduction of $2.2 million non-recurring legal settlement related to an add back in 2019. See discussion below.
(2) Adjusted EBITDA for the year ended December 31, 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) Adjusted EBITDA for the year ended December 31, 2023 includes a $0.8 million add back related to merger agreement expense.
(4) Retail Gross Margin for the year ended December 31, 2021 includes a $0.5 million reduction related to the winter storm Uri credit settlements received and year ended December 31, 2021 includes a $64.4 million add back related to winter storm Uri. See discussion below.
(5) Retail Gross Margin for year ended December 31, 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.

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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 are allowing merger related costs to be added back as non-recurring items in the calculation of Adjusted EBITDA for our Debt covenant calculations. We incurred merger related costs of $0.8 million during the fourth quarter of 2023, which are reflected as an add back in the calculation of Adjusted EBITDA for the year ended December 31, 2023. Our lenders under our Senior Credit Facility also 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 year ended December 31, 2022.

We believe that the presentation of Adjusted EBITDA provides information useful to investors in assessing our liquidity and financial condition and results of operations and that Adjusted EBITDA is also useful to investors as a financial indicator of our ability to incur and service debt, pay dividends and fund capital expenditures. Adjusted EBITDA is a supplemental financial measure that management and external users of our consolidated financial statements, such as industry analysts, investors, commercial banks and rating agencies, use to assess the following:
 
our operating performance as compared to other publicly traded companies in the retail energy industry, without regard to financing methods, capital structure or historical cost basis;
the ability of our assets to generate earnings sufficient to support our proposed cash dividends;
our ability to fund capital expenditures (including customer acquisition costs) and incur and service debt; and
our compliance with financial debt covenants. (Refer to Note 9 "Debt" in the Company’s audited consolidated financial statements 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.
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  Year Ended December 31,
(in thousands)202320222021
Reconciliation of Adjusted EBITDA to Net Income (Loss):
Net income (loss)$26,105 $11,203 $(5,413)
Depreciation and amortization9,102 16,703 21,578 
Interest expense9,334 7,204 4,926 
Income tax expense11,142 6,483 5,266 
EBITDA55,683 41,593 26,357 
Less:
Net, (loss) gain on derivative instruments(71,493)17,821 21,200 
Net, cash settlements on derivative instruments66,632 (35,801)(15,692)
Customer acquisition costs6,736 5,870 1,415 
       Plus:
       Non-cash compensation expense2,295 3,252 3,448 
Non-recurring event - winter storm Uri— (5,162)60,000 
       Non-recurring legal and regulatory settlements— — (2,225)
Merger agreement expense752 — — 
Adjusted EBITDA
$56,855 $51,793 $80,657 































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The following table presents a reconciliation of Adjusted EBITDA to net cash provided by operating activities for each of the periods indicated.
 Year Ended December 31,
(in thousands)202320222021
Reconciliation of Adjusted EBITDA to net cash provided by operating activities:
Net cash provided by operating activities$49,315 $16,207 $12,702 
Amortization of deferred financing costs(825)(1,125)(997)
Bad debt expense(3,442)(6,865)(445)
Interest expense9,334 7,204 4,926 
Income tax expense11,142 6,483 5,266 
Non-recurring event - winter storm Uri— (5,162)60,000 
Non-recurring legal settlement— — (2,225)
Merger agreement expense752 — — 
Changes in operating working capital
Accounts receivable, prepaids, current assets(17,159)34,731 (5,117)
Inventory(1,281)2,423 486 
Accounts payable, accrued liabilities, current liabilities15,206 (884)11,253 
Other(6,187)(1,219)(5,192)
Adjusted EBITDA$56,855 $51,793 $80,657 
Cash Flow Data:
Cash flows provided by operating activities$49,315 $16,207 $12,702 
Cash flows used in investing activities$(1,435)$(6,871)$(6,510)
Cash flows used in financing activities $(40,636)$(49,305)$(2,556)

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 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 year ended December 31, 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.
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  Year Ended December 31,
(in thousands)202320222021
Reconciliation of Retail Gross Margin to Gross Profit:
Total Revenues$435,192 $460,493 $393,485 
Less:
Retail cost of revenues310,744 357,096 323,219 
Gross Profit$124,448 $103,397 $70,266 
Less:
Net asset optimization expense(7,326)(2,322)(4,243)
Net, (loss) gain on non-trading derivative instruments(70,304)17,305 22,130 
Net, cash settlements on non-trading derivative instruments65,428 (35,966)(15,752)
Non-recurring event - winter storm Uri — 9,565 (64,403)
Retail Gross Margin$136,650 $114,815 $132,534 
Retail Gross Margin - Retail Electricity Segment (1)(2)
$87,566 $82,749 $96,009 
Retail Gross Margin - Retail Natural Gas Segment$47,489 $32,066 $36,525 
Retail Gross Margin - Other$1,595 $— $— 
(1) Retail Gross Margin for the year ended December 31, 2021 includes a $0.5 million reduction related to the winter storm Uri credit settlements received and includes a $64.4 million add back related to winter storm Uri.
(2) Retail Gross Margin for year ended December 31, 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.

Our non-GAAP financial measures of Adjusted EBITDA and Retail Gross Margin should not be considered as alternatives to 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 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.

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Consolidated Results of Operations
(In Thousands)Year Ended December 31,
202320222021
Revenues:
Retail revenues$439,360 $462,815 $397,728 
Net asset optimization expense(7,326)(2,322)(4,243)
Other revenue3,158 — — 
Total Revenues435,192 460,493 393,485 
Operating Expenses:
Retail cost of revenues310,744 357,096 323,219 
General and administrative expense68,874 61,933 44,279 
Depreciation and amortization9,102 16,703 21,578 
Total Operating Expenses388,720 435,732 389,076 
Operating income46,472 24,761 4,409 
Other (expense)/income:
Interest expense(9,334)(7,204)(4,926)
Interest and other income109 129 370 
Total Other (Expenses)/Income(9,225)(7,075)(4,556)
Income (loss) before income tax expense37,247 17,686 (147)
Income tax expense 11,142 6,483 5,266 
Net income (loss)$26,105 $11,203 $(5,413)
Other Performance Metrics:
   Adjusted EBITDA (1) (2) (5)
$56,855 $51,793 $80,657 
   Retail Gross Margin (1) (3)(4)
$136,650 $114,815 $132,534 
   Customer Acquisition Costs$6,736 $5,870 $1,415 
   RCE Attrition3.4 %3.8 %3.3 %
Distributions paid to Class B non-controlling unit holders and dividends paid to Class A common shareholders$(7,182)$(26,014)$(28,423)

(1) Adjusted EBITDA and Retail Gross Margin are non-GAAP financial measures. See " — Non-GAAP Performance Measures" for a reconciliation of Adjusted EBITDA and Retail Gross Margin to their most directly comparable GAAP financial measures.
(2) Adjusted EBITDA for the year ended December 31, 2021 includes a $60.0 million add back related to winter storm Uri and a deduction of $2.2 million non-recurring legal settlement related to an add back in 2019.
(3) Retail Gross Margin for the year ended December 31, 2021 includes a $0.5 million reduction related to the winter storm Uri credit settlements received and includes a $64.4 million add back related to winter storm Uri.
(4) Retail Gross Margin for the year ended December 31, 2022 includes a deduction of $9.6 million non-recurring credit related to winter storm Uri add back in 2021.
(5) Adjusted EBITDA for the year ended December 31, 2023 includes a $0.8 million add back related to merger agreement expense.

Total Revenues. Total revenues for the year ended December 31, 2023 were approximately $435.2 million, a decrease of approximately $25.3 million, or 5%, from approximately $460.5 million for the year ended December 31, 2022. This decrease was primarily due to lower electricity volumes sold as a result of a smaller electricity customer book during 2023 as compared to 2022 offset by an increase in electricity unit revenue per MWh. Total revenues for the year ended December 31, 2022 increased approximately $67.0 million, or 17%, from approximately $393.5 million for the year ended December 31, 2021. This increase was primarily due to an increase in electricity unit revenue per MWh and higher natural gas volumes sold as a result of a larger natural gas customer book in 2022 as compared to 2021.
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Analysis of the impact of changes in prices and volumes between the years ended December 31, 2023, 2022 and 2021 are as follows:
2023 vs. 20222022 vs. 2021
Change in electricity volumes sold$(60.6)$(30.5)
Change in natural gas volumes sold(2.9)25.6 
Change in electricity unit revenue per MWh36.3 61.4 
Change in electricity unit revenue per MWh - winter storm Uri— (0.9)
Change in natural gas unit revenue per MMBtu3.7 9.5 
Change in net asset optimization (expense) revenue(5.0)1.9 
Change in other revenue3.2 — 
Change in total revenues$(25.3)$67.0 

Retail Cost of Revenues. Total retail cost of revenues for the year ended December 31, 2023 was approximately $310.7 million, a decrease of approximately $46.4 million, or 13%, from approximately $357.1 million for the year ended December 31, 2022. This decrease was primarily due to lower electricity volumes sold as a result of a smaller electricity customer book during 2023 as compared to 2022, offset by a increase in electricity supply costs due to higher electricity commodity price environment in 2023. Total retail cost of revenues for the year ended December 31, 2022 increased approximately $33.9 million, or 10%, from approximately $323.2 million for the year ended December 31, 2021. This increase was primarily due to an increase in electricity and natural gas supply costs due to higher commodity price environment in 2022, and a change in the value of our retail derivative portfolio, offset by electricity supply costs related to winter storm Uri in 2021 that did not re-occur in 2022 and a winter storm Uri credit received from ERCOT in 2022.

Analysis of the impact of changes in prices and volumes between the years ended December 31, 2023, 2022, and 2021 are as follows:
2023 vs. 20222022 vs. 2021
Change in electricity volumes sold$(46.4)$(21.4)
Change in natural gas volumes sold(2.1)13.2 
Change in electricity unit cost per MWh17.3 65.6 
Change in electricity unit cost per MWh - winter storm Uri9.6 (74.8)
Change in natural gas unit cost per MMBtu(12.5)26.2 
Change in value of retail derivative portfolio(13.8)25.1 
Change in other costs1.5— 
Change in retail cost of revenues$(46.4)$33.9 

General and Administrative Expense. General and administrative expense for the year ended December 31, 2023 was approximately $68.9 million, an increase of approximately $7.0 million, or 11%, as compared to $61.9 million for the year ended December 31, 2022. This increase was primarily attributable to higher employee costs and an increase in sales and marketing due to increased sales activity. General and administrative expense for the year ended December 31, 2022 increased approximately $17.6 million, or 40%, as compared to $44.3 million for the year ended December 31, 2021. This increase was primarily attributable to higher employee costs and higher bad debt expense in 2022 and lower employee costs in 2021 due to employee retention credits related to CARES Act that did not re-occur in 2022.

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Depreciation and Amortization Expense. Depreciation and amortization expense for the year ended December 31, 2023 was approximately $9.1 million, a decrease of approximately $7.6 million, or 46%, from approximately $16.7 million for the year ended December 31, 2022. This decrease was primarily due to the decreased amortization expense associated with customer relationship intangibles. Depreciation and amortization expense for the year ended December 31, 2022 decreased approximately $4.9 million, or 23%, from approximately $21.6 million for the year ended December 31, 2021. This decrease was primarily due to the decreased amortization expense associated with customer relationship intangibles.

Customer Acquisition Cost. Customer acquisition cost for the year ended December 31, 2023 was approximately $6.7 million, an increase of approximately $0.8 million, or 14%, from approximately $5.9 million for the year ended December 31, 2022. This increase was primarily due to increased sales activity in 2023 as compared to 2022. Customer acquisition cost for the year ended December 31, 2022 increased approximately $4.5 million, or 315% from approximately $1.4 million for the year ended December 31, 2021, and reflected a return to more historical levels. This decrease was primarily due to limitation on our door-to-door marketing as a result of COVID-19 during most of 2021. The low customer acquisition cost in 2021 was primarily due to a 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.
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Operating Segment Results
 Year Ended December 31,
  202320222021
 (in thousands, except volume and per unit operating data)
Retail Electricity Segment
Total Revenues$328,466 $352,750 $322,594 
Retail Cost of Revenues240,979 275,701 284,794 
Less: Net (Losses) Gains on non-trading derivatives, net of cash settlements(79)(15,265)6,194 
Non-recurring event - winter storm Uri— 9,565 (64,403)
Retail Gross Margin (1) —Electricity
$87,566 $82,749 $96,009 
Volumes—Electricity (MWhs) (3)
2,008,947 2,433,906 2,677,681 
Retail Gross Margin (2) (4) —Electricity per MWh
$43.59 $34.00 $35.86 
Retail Natural Gas Segment
Total Revenues$110,894 $110,065 $75,134 
Retail Cost of Revenues68,202 81,395 38,425 
Less: Net (Losses) Gains on non-trading derivatives, net of cash settlements(4,797)(3,396)184 
Retail Gross Margin (1) —Gas
$47,489 $32,066 $36,525 
Volumes—Gas (MMBtus)11,252,862 11,558,952 8,611,285 
Retail Gross Margin (2) —Gas per MMBtu
$4.22 $2.77 $4.24 

(1) Reflects the Retail Gross Margin attributable to our Retail Electricity Segment or Retail Natural Gas Segment, as applicable. Retail Gross Margin is a non-GAAP financial measure. See "Non-GAAP Performance Measures" for a reconciliation of Retail Gross Margin to most directly comparable financial measures presented in accordance with GAAP.
(2) Reflects the Retail Gross Margin for the Retail Electricity Segment or Retail Natural Gas Segment, as applicable, divided by the total volumes in MWh or MMBtu, respectively.
(3) Excludes volumes (8,402 MWhs) related to winter storm Uri impact for the year ended December 31, 2021.
(4) Retail Gross Margin - Electricity per MWh excludes winter storm Uri impact.
Retail Electricity Segment

Total revenues for the Retail Electricity Segment for the year ended December 31, 2023 were approximately $328.5 million, a decrease of approximately $24.3 million, or 7%, from approximately $352.8 million for the year ended December 31, 2022. This decrease was largely due to lower volumes sold, resulting in a decrease of $60.6 million. This decrease was partially offset by higher electricity prices, resulting in an increase of $36.3 million. Total revenues for the Retail Electricity Segment for the year ended December 31, 2022 increased approximately $30.2 million, or 9%, from approximately $322.6 million for the year ended December 31, 2021. This increase was largely due higher electricity prices, resulting in an increase of $61.4 million. This was partially offset by a decrease in volumes, which resulted in a decrease of $30.5 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.







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Retail cost of revenues for the Retail Electricity Segment for the year ended December 31, 2023 was approximately $241.0 million, a decrease of approximately $34.7 million, or 13%, from approximately $275.7 million for the year ended December 31, 2022. This decrease was primarily due to lower volumes sold, resulting in a decrease of $46.4 million and a decrease of $15.2 million due to a change in the value of our retail derivative portfolio used in hedging and a credit of $9.6 million related to Winter Storm Uri received in 2022 that did not reoccur in 2023. This was offset by an increase in electricity costs of $17.3 million due to higher commodity price environment in 2023. Retail cost of revenues for the Retail Electricity Segment for the year ended December 31, 2022 decreased approximately $9.1 million, or 3%, from approximately $284.8 million for the year ended December 31, 2021. This decrease was primarily due to a decrease in supply costs of $74.8 million related to winter storm Uri in 2021 that did not re-occur in 2022 (which includes a credit of $9.6 million related to winter storm Uri received in 2022 from ERCOT) and electricity volumes sold resulting in a decrease of $21.4 million. This was offset by an increase in electricity costs of $65.6 million due to higher commodity price environment in 2022 and by an increase of $21.5 million due to a change in the value of our retail derivative portfolio used in hedging.

Retail gross margin for the Retail Electricity Segment for the year ended December 31, 2023 was approximately $87.6 million, an increase of approximately $4.8 million, or 6%, as compared to the year ended December 31, 2022, and 2022 decreased approximately $13.3 million or 14% as compared to December 31, 2021 as indicated in the table below (in millions).
2023 vs. 20222022 vs. 2021
Change in volumes sold $(14.2)$(3.0)
Change in gross margin - winter storm Uri— (64.4)
Change in unit margin per MWh19.0 54.1 
Change in retail electricity segment retail gross margin$4.8 $(13.3)
Electricity unit margin improved in 2023 compared to prior year as a result of higher electricity prices resulting in higher unit margin per MWh sold. Unit margins were negatively impacted in 2022 compared to prior year primarily as a result of the higher electricity cost due to higher commodity price environment in 2022.

The volumes of electricity sold decreased from 2,433,906 MWh for the year ended December 31, 2022 to 2,008,947 MWh for the year ended December 31, 2023. This decrease was primarily due to a smaller customer book during 2023. The volumes of electricity sold decreased from 2,677,681 MWh for the year ended December 31, 2021 to 2,433,906 MWh for the year ended December 31, 2022. This decrease was primarily due to a smaller customer book in 2022 as compared to 2021.
Retail Natural Gas Segment

Total revenues for the Retail Natural Gas Segment for the year ended December 31, 2023 were approximately $110.9 million, an increase of approximately $0.8 million, or 1%, from approximately $110.1 million for the year ended December 31, 2022. This increase was primarily attributable to higher rates, which resulted in an increase in total revenues of $3.7 million, partially offset by a decrease in volumes of $2.9 million. Total revenues for the Retail Natural Gas Segment for the year ended December 31, 2022 increased by approximately $35.0 million, or 47%, from approximately $75.1 million for the year ended December 31, 2021. This increase was primarily attributable to an increase in volumes of $25.6 million, and higher rates, which resulted in an increase in total revenues of $9.5 million.

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Retail cost of revenues for the Retail Natural Gas Segment for the year ended December 31, 2023 were approximately $68.2 million, a decrease of approximately $13.2 million, or 16%, from approximately $81.4 million for the year ended December 31, 2022. The decrease was primarily due to lower supply costs of $12.5 million, lower volumes of $2.1 million, offset by an increase of $1.4 million due to change in the fair value of our retail derivative portfolio used for hedging. Retail cost of revenues for the Retail Natural Gas Segment for the year ended December 31, 2022 increased approximately $43.0 million, or 112%, from approximately $38.4 million for the year ended December 31, 2021. The increase was primarily due to higher supply costs of $26.2 million, higher volumes of $13.2 million, and an increase of $3.6 million due to change in the fair value of our retail derivative portfolio used for hedging.

Retail gross margin for the Retail Natural Gas Segment for the year ended December 31, 2023 was approximately $47.5 million, an increase of approximately $15.4 million, or 48% from approximately $32.1 million for the year ended December 31, 2022, and 2022 decreased approximately $4.4 million or 12% from approximately $36.5 million for the year ended December 31, 2021 as indicated in the table below (in millions).
2023 vs. 20222022 vs. 2021
Change in volumes sold $(0.8)$12.4 
Change in unit margin per MMBtu16.2 (16.8)
Change in retail natural gas segment retail gross margin$15.4 $(4.4)
Natural Gas unit margins improved in 2023 compared to prior year primarily as a result of the lower natural cost supply costs in 2023. Unit margins were negatively impacted in 2022 compared to prior year primarily as a result of the higher natural cost supply costs due to higher commodity price environment in 2022.
The volumes of natural gas sold decreased from 11,558,952 MMBtu for the year ended December 31, 2022 to 11,252,862 MMBtu for the year ended December 31, 2023. This decrease was primarily due to a smaller customer book in 2023 compared to 2022. The volumes of natural gas sold increased from 8,611,285 MMBtu for the year ended December 31, 2021 to 11,558,952 MMBtu for the year ended December 31, 2022. This increase was primarily due to a larger customer book in 2022 compared to 2021.
Liquidity and Capital Resources

Overview

Our primary sources of liquidity are cash generated from operations and borrowings under our Senior Credit Facility. Our principal liquidity requirements are to meet our financial commitments, finance current operations, fund organic growth and/or acquisitions, service debt and pay dividends. Our liquidity requirements fluctuate with our level of customer acquisition costs, acquisitions, collateral posting requirements on our derivative instruments portfolio, distributions, the effects of the timing between the settlement of payables and receivables, including the effect of bad debts, weather conditions, and our general working capital needs for ongoing operations. 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.






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Liquidity Position
The following table details our available liquidity as of December 31, 2023:
December 31,
($ in thousands)2023
Cash and cash equivalents$42,595 
Senior Credit Facility Availability (1)
48,395 
Subordinated Debt Facility Availability (2)
25,000 
Total Liquidity$115,990 
(1) Reflects amount of Letters of Credit that could be issued based on existing covenants as of December 31, 2023.
(2) The availability of Subordinated Facility is dependent on Mr. Maxwell's willingness and ability to lend. See "— Sources of Liquidity and Capital Resources — Amended and Restated 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):
  Year Ended December 31,
  202320222021
Net cash provided by operating activities$49,315 $16,207 $12,702 
Net cash used in by investing activities$(1,435)$(6,871)$(6,510)
Net cash used in financing activities$(40,636)$(49,305)$(2,556)

Cash Flows Provided by Operating Activities. Cash flows provided by operating activities for the year ended December 31, 2023 increased by $33.1 million compared to the year ended December 31, 2022. The increase was primarily the result of higher net income in 2023 coupled with other changes in working capital. Cash flows provided by operating activities for the year ended December 31, 2022 increased by $3.5 million compared to the year ended December 31, 2021. The increase was primarily the result of higher net income in 2022 coupled with other changes in working capital, non-recurring winter storm Uri related costs of $64.4 million for the year ended December 31, 2021, which did not re-occur in 2022, and a $9.6 million credit received in the year ended December 31, 2022 from ERCOT related to winter storm Uri

Cash Flows Used in Investing Activities. Cash flows used in investing activities decreased by $5.4 million for the year ended December 31, 2023. The decrease was primarily the result of customer acquisitions during the year ended December 31, 2022 that did not re-occur in 2023. Cash flows used in investing activities increased by $0.4 million for the year ended December 31, 2022. The increase was primarily the result of increases related to customer acquisitions for the year ended December 31, 2022.

Cash Flows Used in Financing Activities. Cash flows used in financing activities decreased by $8.7 million for the year ended December 31, 2023. The decrease in cash flows used in financing activities was primarily due to a decrease in net paydown of our Senior Credit Facility of $32.0 million, a decrease in dividends paid to Class A common stockholders of $8.6 million, a decrease in distribution to non-controlling unitholders of $10.2 million, offset by net paydown of sub-debt of $20.0 million for the year ended December 31, 2023 compared to net borrowing of sub-debt of $20.0 million for the year ended December 31, 2022. Cash flows used in financing activities increased by $46.7 million for the year ended December 31, 2022. The increase in cash flows used in financing activities was primarily due to an increased net paydown of our Senior Credit Facility of $70.0 million, offset by an increase in sub-debt borrowing of $20.0 million for the year ended December 31, 2022.
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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 December 31, 2023, we had total commitments of $195.0 million under our Senior Credit Facility, of which $121.3 million was outstanding, including $24.3 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 December 31, 2023, we were in compliance with the covenants under our Senior Credit Facility. Based upon existing covenants as of December 31, 2023, we had availability to borrow up to $48.4 million under the Senior Credit Facility.

Maintaining compliance with our covenants under our Senior Credit Facility may impact our ability to pay dividends on our 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 December 31, 2023, there was zero outstanding borrowings under the Subordinated Debt Facility, and availability to borrow up to $25.0 million under the Subordinated Debt Facility. See Note 9 "Debt" for further information regarding the extension of 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 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 December 31, 2023 was $97.0 million. The current variable interest rate on the facility at December 31, 2023 was 8.60%.





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Customer Acquisitions

Our customer acquisition strategy consists of customer growth obtained through organic customer additions as well as opportunistic acquisitions. During the years ended December 31, 2023 and 2022, we spent a total of $6.7 million and $5.9 million, respectively, on organic customer acquisitions.

Capital Expenditures

Our capital requirements each year are relatively low and generally consist of minor purchases of equipment or information system upgrades and improvements. Capital expenditures for the year ended December 31, 2023 included approximately $1.4 million related to information systems improvements.

Dividends and Distributions

For the year ended December 31, 2023, we paid $2.9 million in dividends to holders of our 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 Class B common stock (our non-controlling interest holders). As a result, during the year ended December 31, 2023, Spark HoldCo made distributions of $3.6 million to our non-controlling interest holders related to the dividend payments to our Class A shareholders. In April 2023, we announced that our Board of Directors elected to temporarily suspend the quarterly cash dividend on the Class A common stock.

During the year ended December 31, 2023, we paid $10.3 million of dividends to holders of our Series A Preferred Stock, and as of December 31, 2023, we had accrued $2.7 million related to dividends to holders of our Series A Preferred Stock, which we paid on January 16, 2024. 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. Following the cessation of the publication of U.S. LIBOR on June 30, 2023, we use Three Month CME Term SOFR plus a tenor spread of 0.26161 percent (or 26.161 bps) to calculate the dividend rate on the Series A Preferred Stock pursuant to the rules of the Adjustable Interest Rate (LIBOR) Act. For the year ended December 31, 2023, we declared dividends of $10.6 million in the aggregate on our Series A Preferred Stock.

On January 17, 2024, our Board of Directors declared a quarterly cash dividend in the amount of $0.75960 per share for the Series A Preferred Stock. Dividends on the Series A Preferred Stock will be paid on April 15, 2024 to holders of record on April 1, 2024. The Board of Directors may be required to reduce, eliminate or suspend quarterly cash dividends to the holders of the Series A Preferred Stock.

Future dividends are 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.

Even if we are permitted to pay dividends on the Series A Preferred Stock, our Board of Directors may elect to reduce, eliminate or suspend the dividends on the Series A Preferred Stock, in order to maintain cash balances for operations or for other reasons. A dividend penalty event would occur if dividends on the Series A Preferred Stock are in arrears for six or more quarterly dividend periods, in which case the dividend rate on the Series A Preferred Stock would increase by 2.00% per annum, and the holders of the Series A Preferred Stock would be entitled to elect two members to our Board of Directors, until the dividend penalty event is cured.
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Summary of Contractual Obligations
The following table discloses aggregate information about our contractual obligations and commercial commitments as of December 31, 2023 (in millions): 
Total20242025202620272028> 5 years
Purchase obligations:
Pipeline transportation agreements $9.2 $5.9 $1.6 $0.9 $0.6 $0.2 $— 
Other purchase obligations (1)
16.4 6.0 5.1 5.3 — — — 
Total purchase obligations$25.6 $11.9 $6.7 $6.2 $0.6 $0.2 $— 
Senior Credit Facility$97.0 $— $97.0 $— $— $— $— 
Debt$97.0 $— $97.0 $— $— $— $— 

(1)     The amounts presented here include contracts for billing services and other software agreements to support our operations.

As of December 31, 2023, we had no material "off-balance sheet arrangements."

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Related Party Transactions

For a discussion of related party transactions, see Note 14 "Transactions with Affiliates" in the Company’s audited consolidated financial statements.
Critical Accounting Policies and Estimates

Our significant accounting policies are described in Note 2 "Basis of Presentation and Summary of Significant Accounting Policies" to our audited consolidated financial statements. We prepare our financial statements in conformity with accounting principles generally accepted in the United States of America and pursuant to the rules and regulations of the SEC, which require us to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying footnotes. Actual results could differ from those estimates. We consider the following policies to be the most critical in understanding the judgments that are involved in preparing our financial statements and the uncertainties that could impact our financial condition and results of operations.

Revenue Recognition and Retail Cost of Revenues

Our revenues are derived primarily from the sale of natural gas and electricity to retail customers. We also record revenues from sales of natural gas and electricity to wholesale counterparties, including affiliates. Revenues are recognized when the natural gas or electricity is delivered. Similarly, cost of revenues is recognized when the commodity is delivered.

In each period, natural gas and electricity that has been delivered but not billed by period is estimated. Accrued unbilled revenues are based on estimates of customer usage since the date of the last meter read and are provided by the utility. Volume estimates are based on forecasted volumes and estimated customer usage by class. Unbilled revenues are calculated by multiplying these volume estimates by the applicable rate by customer class. Estimated amounts are adjusted when actual usage is known and billed.

The cost of natural gas and electricity for sale to retail customers is similarly based on estimated supply volumes for the applicable reporting period. In estimating supply volumes, we consider the effects of historical customer volumes, weather factors and usage by customer class. Transmission and distribution delivery fees, where applicable, are estimated using the same method used for sales to retail customers. In addition, other load related costs, such as ISO fees, ancillary services and renewable energy credits are estimated based on historical trends, estimated supply volumes and initial utility data. Volume estimates are then multiplied by the supply rate and recorded as retail cost of revenues in the applicable reporting period. Estimated amounts are adjusted when actual usage is known and billed.

Accounts Receivables and Allowance for Credit Losses

The Company conducts business in many utility service markets where the local regulated utility purchases our receivables, and then becomes responsible for billing the customer and collecting payment from the customer (“POR programs”). These POR programs result in substantially all of the Company’s credit risk being linked to the applicable utility, which generally has an investment-grade rating, and not to the end-use customer. The Company monitors the financial condition of each utility and currently believes its receivables are collectible.

In markets that do not offer POR programs or when the Company chooses to directly bill its customers, certain receivables are billed and collected by the Company. The Company bears the credit risk on these accounts and records an appropriate allowance for credit losses 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.

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For trade accounts receivables, the Company accrues an allowance for credit losses by business segment by pooling customer accounts receivables based on similar risk characteristics, such as customer type, geography, aging analysis, payment terms, and related macroeconomic 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 credit losses when the accounts receivable is deemed to be uncollectible.

We assess the adequacy of the allowance for credit losses through review of an aging of customer accounts receivable and general economic conditions in the markets that we serve.

Derivative Instruments

We enter into both physical and financial contracts for the purchase and sale of electricity and natural gas and apply the fair value requirements of ASC Topic 815, Derivatives and Hedging.

Our derivative instruments are subject to mark-to-market accounting requirements and are recorded on the consolidated balance sheet at fair value. Derivative instruments representing unrealized gains are reported as derivative assets while derivative instruments representing unrealized losses are reported as derivative liabilities. We offset amounts in the consolidated balance sheets for derivative instruments executed with the same counterparty where we have a master netting arrangement.

To manage our retail business, we hold derivative instruments that are not for trading purposes and are not designated as hedges for accounting purposes. Changes in the fair value of and amounts realized upon settlement of derivative instruments not held for trading purposes are recognized in retail costs of revenues.

As part of our asset optimization activities, we manage a portfolio of commodity derivative instruments held for trading purposes. Changes in fair value of and amounts realized upon settlements of derivatives instruments held for trading purposes are recognized in earnings in net asset optimization revenues.

We have 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.

Goodwill

As noted above, Goodwill represents the excess of cost over fair value of the assets of businesses. The goodwill on our consolidated balance sheet as of December 31, 2023 is associated with both our Retail Natural Gas and Retail Electricity reporting units. We determine our reporting units by identifying each unit that is engaged in business activities from which it may earn revenues and incur expenses, has operating results regularly reviewed by the segment manager for purposes of resource allocation and performance assessment, and has discrete financial information.

Goodwill is assessed for impairment whenever events or circumstances indicate that impairment of the carrying value of goodwill is likely, but no less often than annually. Our annual assessment, absent a triggering event is as of October 31 of each year. On October 31, 2023, we performed a quantitative assessment of goodwill in accordance with guidance from ASC 350, in which we compared our estimate of the fair value of our reporting units with their carrying values, including goodwill. If the carrying value of the reporting unit exceeds its fair value, we would recognize a goodwill impairment loss for the amount by which the reporting unit’s carrying value exceeds its fair value. All of these assessments and calculations, including the determination of whether a triggering event has occurred to undertake an assessment of goodwill involve a high degree of judgment.

We completed our annual assessment of goodwill impairment at October 31, 2023, and the test indicated no impairment.
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Deferred tax assets and liabilities

The Company recognizes the amount of taxes payable or refundable for each tax year. In addition, the Company follows the asset and liability method of accounting for income taxes where deferred tax assets and liabilities are recognized for the expected future tax consequences of events that have been recognized in the financial statements or tax returns and operating loss carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in those years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in the tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is provided for deferred tax assets if it is more likely than not that these items will not be realized.

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the projected future taxable income and tax planning strategies in making this assessment. All of these determinations involve estimates and assumptions.

Recent Accounting Pronouncements

Refer to Note 2 "Basis of Presentation and Summary of Significant Accounting Policies" for a discussion of 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. Liabilities for loss contingencies arising from claims, assessments, litigation, fines, penalties and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. For a discussion of the status of current legal and regulatory matters, see Note 13 "Commitments and Contingencies" in the Company’s audited consolidated financial statements.
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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

We hedge and procure our energy requirements from various wholesale energy markets, including both physical and financial markets and through short and long-term contracts. Our financial results are largely dependent on the margin we are able to realize between the wholesale purchase price of natural gas and electricity plus related costs and the retail sales price we charge our customers for these commodities. We actively manage our commodity price risk by entering into various derivative or non-derivative instruments to hedge the variability in future cash flows from fixed-price forecasted sales and purchases of natural gas and electricity in connection with our retail energy operations. These instruments include forwards, futures, swaps, and option contracts traded on various exchanges, such as NYMEX and Intercontinental Exchange, or ICE, as well as over-the-counter markets. These contracts have varying terms and durations, which range from a few days to several years, depending on the instrument. We also utilize similar derivative contracts in connection with our asset optimization activities to attempt to generate incremental gross margin by effecting transactions in markets where we have a retail presence. Generally, any such instruments that are entered into to support our retail electricity and natural gas business are categorized as having been entered into for non-trading purposes, and instruments entered into for any other purpose are categorized as having been entered into for trading purposes.
Our net (loss)/gain on our non-trading derivative instruments, net of cash settlements, was $(4.9) million and $(18.7) million for the years ended December 31, 2023 and December 31, 2022, 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” of this Annual Report.

We measure the commodity risk of our non-trading energy derivatives using a sensitivity analysis on our net open position. As of December 31, 2023, our Gas Non-Trading Fixed Price Open Position (hedges net of retail load) was a short position of 295,068 MMBtu. An increase of 10% in the market prices (NYMEX) from their December 31, 2023 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 December 31, 2023 levels would have increased the fair market value of our non-trading energy derivatives by less than $0.1 million. As of December 31, 2023, our Electricity Non-Trading Fixed Price Open Position (hedges net of retail load) was a short position of 280,418 MWhs. An increase of 10% in the forward market prices from their December 31, 2023 levels would have decreased the fair market value of our net non-trading energy portfolio by $1.3 million. Likewise, a decrease of 10% in the forward market prices from their December 31, 2023 levels would have increased the fair market value of our non-trading energy derivatives by $1.3 million.
Credit Risk

In many of the utility services territories where we conduct business, Purchase of Receivables ("POR") programs have been established, whereby the local regulated utility purchases our receivables, and becomes responsible for billing the customer and collecting payment from the customer. This service results in substantially all of our credit risk being with the utility and not to our end-use customer in these territories. Approximately 55%, 59% and 59% of our retail revenues were derived from territories in which substantially all of our credit risk was with local regulated utility companies as of December 31, 2023, 2022 and 2021, respectively, all of which had investment grade ratings as of such date. During the same period, we paid these local regulated utilities a weighted average discount of approximately 1.0%, 0.9% and 0.9%, respectively, of total revenues for customer credit risk protection. In certain of the POR markets in which we operate, the utilities limit their collections exposure by retaining the ability to transfer a delinquent account back to us for collection when collections are past due for a specified period.
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If our collection efforts are unsuccessful, we return the account to the local regulated utility for termination of service. Under these service programs, we are exposed to credit risk related to payment for services rendered during the time between when the customer is transferred to us by the local regulated utility and the time we return the customer to the utility for termination of service, which is generally one to two billing periods. We may also realize a loss on fixed-price customers in this scenario due to the fact that we will have already fully hedged the customer's expected commodity usage for the life of the contract.

In non-POR markets (and in POR markets where we may choose to direct bill our customers), we manage customer credit risk through formal credit review in the case of commercial customers, and credit score screening, deposits and disconnection for non-payment, in the case of residential customers. Economic conditions may affect our customers' ability to pay bills in a timely manner, which could increase customer delinquencies and may lead to an increase in bad debt expense. Our bad debt expense for the year ended December 31, 2023, 2022 and 2021 was approximately 1.7%, 3.0% and 0.2% of non-POR market retail revenues, respectively. See “Management's Discussion and Analysis of Financial Condition and Results of Operations—Drivers of Our Business—Customer Credit Risk” for an analysis of our bad debt expense related to non-POR markets during 2023.

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 December 31, 2023 and 2022, approximately $2.1 million and $1.9 million of our total exposure of $2.8 million and $2.8 million, respectively, 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 December 31, 2023 and 2022.
Interest Rate Risk
We are exposed to fluctuations in interest rates under our Senior Credit Facility and our Series A Preferred Stock.

At December 31, 2023, we were co-borrowers under the Senior Credit Facility, under which $97.0 million of variable rate indebtedness was outstanding. Based on the average amount of our variable rate indebtedness outstanding during the year ended December 31, 2023, a 1% percent 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. Following the cessation of the publication of U.S. LIBOR on June 30, 2023, we use Three Month CME Term SOFR plus a tenor spread of 0.26161 percent (or 26.161 bps) to calculate the dividend rate on the Series A Preferred Stock pursuant to the rules of the Adjustable Interest Rate (LIBOR) Act. During the year ended December 31, 2023, we paid $10.3 million of dividends to holders of our Series A Preferred Stock, and as of December 31, 2023, based on the Series A Preferred Stock outstanding on December 31, 2023, a 1.0% increase in interest rates would have resulted in additional dividends of $0.9 million for the year.
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Item 8. Financial Statements and Supplementary Data
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
REPORTS OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM (PCAOB ID: 248)
CONSOLIDATED BALANCE SHEETS AS OF DECEMBER 31, 2023 AND DECEMBER 31, 2022 
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) FOR THE YEARS ENDED DECEMBER 31, 2023, 2022 AND 2021 
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY FOR THE YEARS ENDED DECEMBER 31, 2023, 2022 AND 2021 
CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 2023, 2022 AND 2021 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 

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MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

It is the responsibility of the management of Via Renewables, Inc. to establish and maintain adequate internal control over financial reporting. Internal control over financial reporting is defined in Rule 13a-15(f) or 15d-15(f) promulgated under the Exchange Act, as a process designed by, or under the supervision of, our principal executive and principal financial officers and effected by our board of directors, management, and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that:

Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect our transactions and dispositions of the assets;
Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and the receipts and expenditures are being made only in accordance with authorizations of our management and directors; and
Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on our financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management has assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2023, utilizing the criteria in the Committee of Sponsoring Organizations of the Treadway Commission’s Internal Control-Integrated Framework (2013). Based upon this assessment, management concluded that our internal control over financial reporting was effective as of December 31, 2023

Remediation of Previously Disclosed Material Weakness

As described in Part II, Item 9A “Controls and Procedures” of our 2022 Annual Report, we identified a material weakness in the design and operation of the controls over our calculation of deferred tax assets and liabilities and income tax expense as of December 31, 2022. A material weakness is defined as a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis.

The Company implemented remediation steps to address the material weakness and improve our internal control over financial reporting. Specifically, we have designed and implemented enhanced tax accounting processes and controls to (a) ensure changes in the Company’s interest in Spark HoldCo, LLC ("Spark HoldCo") are appropriately identified and recorded, and (b) ensure the precision of review of attributes of the Company’s deferred tax assets and liabilities and income tax expense. Additionally, the Company engaged experienced tax advisors to assist with the Company’s calculation of deferred tax assets and liabilities and income tax expense as of December 31, 2023. Testing of both the design and operating effectiveness of the Company’s enhanced controls was completed, and management concluded that the material weakness described above had been fully remediated as of December 31, 2023.

This Annual Report does not contain an attestation report of our independent registered public accounting firm related to internal control over financial reporting because the rules for non-accelerated companies provide an exemption from the attestation requirement.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


Board of Directors and Shareholders
Via Renewables, Inc.

Opinion on the financial statements

We have audited the accompanying consolidated balance sheets of Via Renewables, Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2023 and 2022, the related consolidated statements of operations and comprehensive income (loss), changes in equity, and cash flows for each of the two years in the period ended December 31, 2023, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.

Basis for opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Derivative Instruments

As described in Note 6 of the consolidated financial statements, the Company has recognized $2.2 million in gross derivative assets and $30.6 million in gross derivative liabilities as of December 31, 2023. We identified the completeness and accuracy of derivatives as a critical audit matter.

The principal consideration for our determination that the completeness and accuracy of derivatives is a critical audit matter is due to the significant volume of activity associated with the Company’s risk management activities and derivative portfolio.

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Our audit procedures related to testing the completeness and accuracy of derivative instruments included the following, among others.

We tested the design and operating effectiveness of controls over the Company’s process for capturing and accounting for derivative instruments.
We independently confirmed a sample of derivative contracts directly with counterparties.
We performed reconciliations between the broker’s statements and the Company’s derivative portfolio records.
We tested a sample of derivative contracts to verify underlying data agreed to the Company’s records.
We tested information subsequent to the balance sheet date to evaluate completeness of derivatives recorded. For example, we evaluated cash disbursement and receipt activity to evaluate completeness of the Company’s derivative portfolio records.


/s/ GRANT THORNTON LLP
We have served as the Company's auditor since 2022.
Houston, Texas

February 29, 2024

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Report of Independent Registered Public Accounting Firm
To the Shareholders and the Board of Directors of Via Renewables, Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated statements of operations and comprehensive income (loss), changes in equity and cash flows of Via Renewables, Inc. (the Company) for the year ended December 31, 2021, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the results of the Company’s operations and its cash flows for the year ended December 31, 2021, in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.






/s/ Ernst & Young LLP
We served as Via Renewables, Inc.’s auditor from 2018 to 2022.
Houston, Texas

March 3, 2022, except for the effects of the correction of prior year financial information and the reverse stock split as discussed in Notes 2 and 4, respectively, of the 2022 consolidated financial statements, as to which the date is March 29, 2023.
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AUDITED CONSOLIDATED FINANCIAL STATEMENTS

VIA RENEWABLES, INC.
CONSOLIDATED BALANCE SHEETS
(in thousands, except share counts)


December 31, 2023December 31, 2022
Assets
Current assets:
Cash and cash equivalents$42,595 $33,658 
Restricted cash 1,693 
Accounts receivable, net of allowance for credit losses of $4,496 and $4,335 as of December 31, 2023 and 2022, respectively
63,246 81,466