VIASP 10-K
Via Renewables, Inc. (VIASP)
10-K
2026-03-05
For: 2025-12-31
View Original
Added on
April 06, 2026
| UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 | ||
FORM | ||||||||||||||
For the fiscal year ended December 31 , 2025
OR
For the transition period from to
Commission File Number: 001-36559
(Exact name of registrant as specified in its charter)
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |||||||||||||
(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 | ||||||
8.75% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Stock, par value $0.01 per share | ||||||||
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.
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).
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 ☐
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 ☒
There were 3,792,493 shares of Class A common stock, 3,530,836 shares of Class B common stock and 2,094,372 shares of Series A Preferred Stock outstanding as of March 3, 2026.
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 no later than 120 days after December 31, 2025.
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,” “could,” “likely,” “will,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” “plan,” “intend,” “project,” or other similar words. Forward-looking statements appear in a number of places in this Report. All statements, other than statements of historical fact, included in this Report are forward- looking statements. The forward-looking statements include statements regarding the impacts of cash flow generation and liquidity, business strategy, prospects for growth and acquisitions, outcomes of legal proceedings, the timing, availability, ability to pay and amount of cash dividends on our Series A Preferred Stock, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans, objectives, beliefs of management, availability and terms of capital, competition, government regulation and general economic conditions. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we cannot give any assurance that such expectations will prove correct.
The forward-looking statements in this Report are subject to risks and uncertainties. Important factors that could cause actual results to materially differ from those projected in the forward-looking statements include, but are not limited to:
•changes in commodity prices, the 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, heat waves 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;
•risks related to our recently completed Merger (as defined below) including the outcome of any legal proceedings, regulatory proceedings or enforcement matters that may be instituted against us and others relating to the Merger or otherwise, the impact of the Merger on our operations and the amount of the costs, fees, expenses and charges related to Merger;
•competition; and
•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.
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Risk Factor Summary
Our business, financial condition, cash flows, results of operations and ability to pay dividends on our and Series A Preferred Stock could be materially and adversely affected by, and the price of our 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.
•Decarbonization policies and the evolving energy transition could reduce demand for certain products, increase costs and require changes to our business model.
•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.
•Our supply, trading and hedging activities expose us to complex wholesale market and derivatives requirements and disputes that could increase costs or limit our ability to manage commodity 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 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.
•Evolving cybersecurity disclosure requirements could increase our costs and expose us to liability if we are unable to timely assess and disclose cybersecurity incidents.
•Failure to comply with privacy, data protection and consumer information requirements could expose us to regulatory enforcement, litigation and increased operating costs.
•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.
•Our renewable and environmental product offerings and related marketing claims could be subject to increased scrutiny and, if we are unable to substantiate or procure attributes, could harm our business.
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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.
•Our use of automation, artificial intelligence and third-party tools could expose us to operational, legal, regulatory and reputational 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 Series A Preferred Stock.
•The Series A Preferred Stock is subordinated to our existing and future debt obligations.
•Numerous factors may affect the trading price of the Series A Preferred Stock.
•There may not be an active trading market for the Series A Preferred Stock, which may in turn reduce the market value and your ability to transfer or sell your shares of Series A Preferred Stock.
•W. Keith Maxwell III, our founder, sole common stock shareholder and Chief Executive Officer, holds all of the voting power of our common stock, and 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 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 Series A Preferred Stock in the public market could reduce the price of the Series A Preferred Stock, and may dilute your ownership in us.
•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.
•The Series A Preferred Stock is not rated.
•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.
•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.
•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.
On June 13, 2024, we consummated a merger between the Company, Retailco, and wholly owned subsidiary of Retailco (the "Merger"), with the Company continuing as the surviving corporation in the Merger. As a result of the Merger, Mr. Maxwell and his affiliates became the owners of all of the issued and outstanding shares of our Class A common stock and Class B common stock. Effective as of the end of trading on June 13, 2024, the Class A common stock ceased to trade on NASDAQ.
Our Operations
As of December 31, 2025, we operated in 106 utility service territories across 21 states and the District of Columbia and had approximately 421,000 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 thirteen states (Connecticut, Delaware, Illinois, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Ohio, Pennsylvania, Texas and Rhode Island) and the District of Columbia using seven brands (Electricity Maine, ENH Power, Major Energy, Provider Power Mass, Spark Energy, Verde Energy, and Texans Choice Power).
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
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variable-price service options 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.
The fixed/variable splits of our RCEs were as follows as of December 31, 2025:
Green products and renewable energy credits
In response to increased demand for renewable energy, 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 in addition to improved customer satisfaction.
Renewable electricity products allow customers to choose electricity generated from sources such as wind, solar, hydroelectric and biofuel, which is achieved 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 the 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 procure both RECs and carbon offsets in volumes that match customers’ usage who are enrolled in green energy plans.
In addition to the RECs we purchase to satisfy our voluntary requirements under the terms of our green contracts with our customers, 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 (“RPS”). 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
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based on a variety of factors, including cost to acquire customers, availability of opportunities and our view of commodity pricing in particular regions.
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.
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 2025, the largest channels were direct sales, door-to-door and web-based sales. We typically use brokers to obtain C&I customers, which are typically larger and have greater natural gas and electricity requirements. At December 31, 2025, our customer base was 59% residential and 41% 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 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, Sole Common Stockholder and Chief Executive Officer” for a discussion of affiliate relationships.
The following table provides a summary of our acquisitions over the past five years:
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| Company / Portfolio | Date Completed | RCEs | Segment | Acquisition Source | ||||||||||
| Customer Portfolio | May 2021 | 45,000 | Electricity | Third Party | ||||||||||
| Customer Portfolio | July 2021 | 33,000 | Natural Gas | Third Party | ||||||||||
Customer Portfolio (1) | January 2022 | 69,000 | Natural Gas Electricity | Third Party | ||||||||||
| Customer Portfolio | August 2022 | 18,700 | Natural Gas | Third Party | ||||||||||
| Customer Portfolio | April 2024 | 9,300 | Natural Gas | Third Party | ||||||||||
| Customer Portfolio | October 2024 | 61,600 | Natural Gas | Third Party | ||||||||||
| Customer Portfolio | October 2024 | 37,400 | Natural Gas Electricity | Third Party | ||||||||||
| Customer Portfolio | April 2025 | 3,400 | Natural Gas | Third Party | ||||||||||
| Customer Portfolio | May 2025 | 13,600 | Natural Gas | Third Party | ||||||||||
| Customer Portfolio | October 2025 | 3,300 | Electricity | Third 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
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rather than buying physical electricity in the day-ahead market from the ISO. During the year ended December 31, 2025, we transacted physical and financial settlements of electricity with approximately fourteen suppliers.
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, 2025, we transacted physical and financial settlements of natural gas with approximately 76 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
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risk committee. Hedges of our firm transportation obligations are limited to two years or less and hedging of interruptible capacity is prohibited.
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 commodity products we utilize transact at different settlement 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, especially during extreme cold weather conditions. Similarly, in our electricity markets, customer usage is settled at the load zone price for electricity thus if we hedge our supply at a trading 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 sometimes 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.
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, 2025, approximately 61% 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 0.2% 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
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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, 2025 was $1.3 million, or 0.3% 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, 2025.
We do not have high concentrations of sales volumes to individual customers. For the year ended December 31, 2025, 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, 2025, approximately $4.5 million of our total exposure of $5.8 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 2025, we did not experience any material loss related to cyber-attacks or other information security breaches.
Relationship with our Founder, Sole Common Stock Shareholder, and Chief Executive Officer
We have historically leveraged our relationship with affiliates of our founder, sole common stock 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.
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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.
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 33% of our retail revenues for the year ended December 31, 2025, 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
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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.
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."
Maryland
Maryland SB1, sponsored by Senator Augustine (D-Prince George’s County) and Delegate Crosby (D- St. Mary’s County), was signed into law in May 2024. In addition to numerous new green energy requirements, pricing restrictions and burdensome new consumer protections, Maryland SB1 prohibits residential purchase of receivables (POR) for contracts executed or renewed after December 31, 2024. Maryland SB1’s effect has been to largely make it extremely difficult for all retail energy providers to offer Maryland residential consumers energy choice.
The Company is working to minimize economic impacts of Maryland SB1 to the Company. Other deregulated states may follow Maryland’s regulatory path. For example, in Illinois, there is a recently proposed bill similar to Maryland’s SB1.
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.
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 (One-to-One Rule). 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 had the ability to impact our ability to obtain, and increase the cost of, sales leads for our telemarketing channel. had the ability to impact our ability to obtain, and increase the cost of, sales leads for
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our telemarketing channel. However, on January 24, 2025, a business day before the One-to-One Rule was to go into effect, the U.S. Court of Appeals for the Eleventh Circuit, in the case, Insurance Marketing Coalition Limited v. the FCC, issued a ruling which vacated the “one-to-one” consent and the “logically and topically related” requirements for marketing calls and texts adopted by the Federal Communications Commission (FCC) in its rules for the Telephone Consumer Protection Act (TCPA). This ruling is helpful, but uncertainty and challenge still remains regarding telemarketing.
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.
Employees
As of December 31, 2025, we employed 162 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.
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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, 2025, approximately 54% of our workforce was male and 46% 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 Series A Preferred Stock could be materially and adversely affected by, and the price of our 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.
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.
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, 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.
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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.
Decarbonization policies and the evolving energy transition could reduce demand for certain products, increase costs and require changes to our business model.
Federal, state and local policies and market developments relating to decarbonization, electrification, renewable integration and emissions reductions may affect customer demand for electricity and natural gas products, the cost and availability of supply and the rules governing retail competition. For example, changes to clean energy standards, carbon-related programs, building electrification initiatives, restrictions affecting gas infrastructure and evolving utility and ISO reliability requirements could increase our compliance costs, change pricing dynamics and alter customer behavior and attrition patterns.
We may be required to redesign products, modify marketing and disclosures, invest in new capabilities or exit certain markets if we are unable to operate economically under evolving policies and market structures. Any such developments could materially and adversely affect our business, financial condition, results of operations and cash flows.
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.
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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.
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.
Our supply, trading and hedging activities expose us to complex wholesale market and derivatives requirements and disputes that could increase costs or limit our ability to manage commodity risk.
We purchase and sell energy commodities and use physical and financial instruments to manage commodity price and volumetric risk. These activities are subject to evolving requirements and oversight, including rules applicable to derivatives, trading practices, recordkeeping, reporting, position limits and margin and collateral requirements, as well as wholesale market conduct standards and anti-manipulation rules.
Regulatory changes, heightened enforcement activity, changes in market rules or settlement methodologies, or increased collateral or margin requirements could increase the cost of hedging, restrict available products or counterparties, or limit our ability to execute our risk management strategy.
We may also be subject to disputes and settlement adjustments in ISO/RTO markets or with utilities and counterparties, including retroactive charges, uplift allocations, revised methodologies, billing disputes or other adjustments that could adversely affect our cash flows and results of operations. Any allegation that our trading, scheduling, bidding or hedging practices violated applicable requirements—even if ultimately unsubstantiated—could result in investigations, penalties, increased compliance costs, reputational harm and diversion of management time.
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. It is commonplace now for retailers to receive Notice of Violations and Assessment of Penalties proposing multi-million dollar civil penalties, restitution payments to certain customers and a multi-year suspension from the applicable market.
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
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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.”
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 12 "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.
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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.
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 distribute a signification portion of our cash through dividends to holders of Series A Preferred Stock.
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.
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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.
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
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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.
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, such as 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, 2025, customers in non-POR markets represented approximately 39% 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
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•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;
•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.
Evolving cybersecurity disclosure requirements could increase our costs and expose us to liability if we are unable to timely assess and disclose cybersecurity incidents.
We are subject to evolving cybersecurity disclosure obligations, including requirements to disclose material cybersecurity incidents and to provide enhanced disclosures regarding our cybersecurity risk management, strategy and governance. These requirements may increase our costs of compliance and may require us to make expedited judgments regarding the materiality, scope and likely impact of cybersecurity events, often based on incomplete, rapidly developing or potentially inaccurate information.
Any failure, or perceived failure, to maintain effective cybersecurity disclosure controls and procedures—including controls relating to escalation, investigation, documentation and communication with third parties—could result in delayed, incomplete or inaccurate public disclosures, increased scrutiny by regulators, enforcement actions, private litigation (including securities class actions), reputational harm and diversion of management time, any of which could materially and adversely affect our business, financial condition, results of operations and cash flows.
In addition, cybersecurity incidents affecting our vendors, utilities, ISO counterparties, lead generators or other third parties could impair our operations and could require public disclosure even if our systems are not directly compromised, which could further increase the difficulty of timely investigation and disclosure.
Failure to comply with privacy, data protection and consumer information requirements could expose us to regulatory enforcement, litigation and increased operating costs.
We collect, store, process and share certain customer and prospective customer information in connection with marketing, enrollment, verification, billing, collections, customer service and regulatory compliance. We may also process call recordings, chat transcripts or other communications data in connection with our sales and customer support activities. Privacy, data protection and related consumer-protection laws and regulations are rapidly evolving and may impose new obligations or restrict our ability to use data for marketing, analytics, customer service and risk management.
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Our failure, or alleged failure, to comply with applicable privacy requirements, contractual data-use restrictions, recording-consent requirements, data retention and deletion obligations, or evolving standards applicable to vendors and service providers could result in investigations, enforcement actions, fines, civil litigation (including class actions), contractual claims and reputational harm. Compliance may require significant investments in data mapping, vendor oversight, training and technical controls, and may limit the effectiveness of our customer acquisition efforts.
Even if we comply with applicable requirements, increased compliance costs or restrictions on data use could reduce the effectiveness of our marketing and customer engagement activities, impair customer experience and adversely affect our results of operations.
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, 2025, approximately 63% of our RCEs were located in five states. Specifically, 25%, 15%, 8%, 8% and 7% of our customers on an RCE basis were located in PA, CO, TX, NY, and OH, 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.
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. 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 also 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 retailers. Further, a price increase for voluntary 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 with respect to renewable energy may adversely impact the availability to us, and marketability by us, of renewable energy under our brands.
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Our renewable and environmental product offerings and related marketing claims could be subject to increased scrutiny and, if we are unable to substantiate or procure attributes, could harm our business.
We offer, or may offer, products that include renewable energy attributes, renewable energy credits (RECs), carbon offsets or other environmental components. Standards, registry practices and regulatory expectations governing renewable attributes and environmental marketing claims continue to evolve and are subject to heightened scrutiny by regulators, consumer advocates and private plaintiffs.
If we are unable to procure sufficient RECs or other attributes at commercially reasonable prices, if a registry or supplier experiences operational issues, or if applicable standards change, we may be unable to deliver products as marketed or as required under customer contracts. Any allegation that our marketing materials or customer disclosures regarding renewable content, offsets or emissions impacts are misleading or cannot be substantiated could result in regulatory investigations, customer claims, class action litigation, reputational harm and adverse impacts on customer acquisition and retention.
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.
Our use of automation, artificial intelligence and third-party tools could expose us to operational, legal, regulatory and reputational risks.
We may use, or may increasingly use, automated decision tools and artificial intelligence (AI) technologies, including tools provided by third parties, in areas such as customer acquisition and engagement, forecasting and risk
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management, fraud detection, customer service, quality assurance or internal operations. The use of these technologies presents risks that may be difficult to predict or fully mitigate, including the risk that outputs are inaccurate, incomplete, biased or not explainable, that tools are misused by employees or vendors, or that model performance degrades as market, customer or regulatory conditions change.
If AI-enabled tools generate inaccurate internal reports or disclosures, misleading customer communications, incorrect bills, flawed enrollment or verification decisions, or non-compliant marketing content, we could face customer complaints, regulatory scrutiny, enforcement actions and litigation. We may also face risks related to data privacy, intellectual property, confidentiality and cybersecurity arising from the use of third-party AI tools, including the risk that sensitive information is incorporated into or exposed through third-party systems.
In addition, investor and regulatory focus on AI-related claims has increased, and any public statements about our use of AI or automation that are alleged to be inaccurate or overstated could subject us to reputational harm, regulatory inquiries and securities litigation.
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 $156.7 million of indebtedness outstanding and $36.7 million in issued letters of credit under our Senior Credit Facility, and no indebtedness outstanding under our Subordinated Facility as of December 31, 2025. 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 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, 2027, 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;
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•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.
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.
The shares of Series A Preferred Stock require the payment of 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 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.
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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.
The Series A Preferred Stock is subordinated to our existing and future debt obligations.
The Series A Preferred Stock is 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. 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.
Additionally, none of our subsidiaries have guaranteed or otherwise become obligated with respect to the Series A Preferred Stock. As a result, the Series A Preferred Stock effectively ranks 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 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 Series A Preferred Stock.
The trading price of the Series A Preferred Stock may depend on many factors, some of which are beyond our control. Additionally, the market price of our 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 announcement of the elimination, suspension, reduction or reinstatement of dividends on 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 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 Series A Preferred Stock to fluctuate substantially, which may adversely affect the trading price of our Series A Preferred Stock. In the past, when the market price of a stock has been volatile, holders of common stock have at times instituted securities class action litigation. If any 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 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 trading price of the 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 Series A Preferred Stock to expect a higher distribution yield, and cause them to sell their Series A Preferred Stock. Accordingly, higher market interest rates could cause the market price of the 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 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 Series A Preferred Stock, which may in turn reduce the market value and your ability to transfer or sell your Series A Preferred Stock.
There are no assurances that there will be an active trading market for our Series A Preferred Stock. The liquidity of any market for the 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 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 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, our founder, sole common stock shareholder and Chief Executive Officer, holds all the voting power of our common stock, and holders of Series A Preferred Stock have extremely limited voting rights.
Mr. Maxwell beneficially indirectly owns all the combined voting power of the company's common stock.
Mr. Maxwell has the ability to elect all of the members of our board of directors, and thereby to control our management and affairs. In addition, Mr. Maxwell is able to determine the outcome of all matters requiring shareholder approval, including mergers and other material transactions, and is able to cause or prevent a change in the composition of our board of directors or a change in control of our company.
So long as Mr. Maxwell continues to hold all our common stock, he will continue to be able to control all matters requiring shareholder approval. This concentration of stock ownership may also adversely affect the trading price of our Series A Preferred Stock to the extent investors perceive a disadvantage in owning stock of a company with a controlling shareholder.
Holders of the Series A Preferred Stock generally have no 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.
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
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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 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.
Future sales of Series A Preferred Stock in the public market could reduce the price of the Series A Preferred Stock, and may dilute your ownership in us.
We may 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.
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.
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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.
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.
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.
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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%. 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.
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.
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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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. Our company does not have a nominating and corporate governance committee or a compensation committee of independent directors. As a result, 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
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.
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
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
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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 Senior Vice President of Enterprise Technology Solutions along with his team with over 20 years of combined experience in the field of cybersecurity, the Senior VP of Enterprise Technology Solutions brings a wealth of expertise to his role. His in-depth knowledge and experience are instrumental in developing and executing our cybersecurity strategies. Our Senior VP of Enterprise Technology Solutions oversees our governance programs, tests our compliance with standards, remediates known risks, and leads our employee training program.
Monitor Cybersecurity Incidents
The Senior VP of Enterprise Technology Solutions 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 Senior VP of Enterprise Technology Solutions 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 Senior VP of Enterprise Technology Solutions 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.
Reporting to the Board of Directors
The Senior VP of Enterprise Technology Solutions, 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.
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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 12 "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
All our common equity is indirectly owned by Mr. Maxwell.
Dividends
We have historically paid a cash dividend each quarter to holders of our Series A Preferred 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
The following table sets forth information regarding purchase of our Series A Preferred Stock by us during the three months ended December 31, 2025 pursuant to our redemption.
| Period | (a) Total Number of Shares Purchased | (b) Average Price Paid per Share | (c ) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | (d) Maximum Number (or Approximate Dollar Value) of Shares that May yet be Purchased Under the Plans or Programs | ||||||||||
October 1 - October 31, 2025(1) | 287,294 | $ | 25.00 | 287,294 | — | |||||||||
| November 1 - November 30, 2025 | — | — | — | — | ||||||||||
December 1 - December 31, 2025 (2) | 258,565 | 25.47 | 258,565 | — | ||||||||||
| Total | 545,859 | $ | 25.22 | 545,859 | — | |||||||||
(1) On September 15, 2025, we announced the redemption of 287,294 shares of our Series A Preferred Stock for a redemption price of $25.00 per share, plus an amount equal to all accumulated and unpaid dividends thereon to, but not including, the redemption date of October 15, 2025. We paid $7.2 million on the redemption date.
(2) On November 18, 2025, we announced the redemption of 258,565 shares of our Series A Preferred Stock for a redemption price of $25.00 per share, plus an amount equal to all accumulated and unpaid dividends thereon to, but not including, the redemption date of December 18, 2025. We paid $6.6 million on the redemption date.
Stock Performance Graph
The company does not have a class of common stock registered under section 12 of the Securities Exchange Act of 1934.
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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, 2025, we operated in 106 utility service territories across 21 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, 2025, 2024 and 2023, approximately 67%, 75% and 75%, 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, 2025, 2024 and 2023, approximately 33%, 25% and 25%, respectively, of our retail revenues were derived from the sale of natural gas.
Recent Developments
Acquisition of Customer Books
In October 2025, we entered into an asset purchase agreement to acquire up to 3,300 RCEs for a cash purchase price of up to a maximum $0.5 million paid in cash or funded in escrow accounts. These electricity customers were located in our existing market and transferred from the sellers to the Company in the fourth quarter of 2025.
Partial Redemption of Series A Preferred Stock
On November 18, 2025, we announced the redemption of 258,565 shares of our Series A Preferred Stock for a redemption price of $25.00 per share, plus an amount equal to all accumulated and unpaid dividends thereon to, but not including, the redemption date of December 18, 2025. We paid $6.6 million on the redemption date.
On January 16, 2026, we announced the redemption of 232,708 shares of our Series A Preferred Stock for a redemption price of $25.00 per share, plus an amount equal to all accumulated and unpaid dividends thereon to, but not including, the redemption date of February 17, 2026. We paid $5.9 million on the redemption date.
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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, 2025, 2024 and 2023:
| RCEs: | |||||||||||
| December 31, | |||||||||||
| (In thousands) | 2025 | 2024 | 2023 | ||||||||
| Retail Electricity | 225 | 232 | 217 | ||||||||
| Retail Natural Gas | 196 | 156 | 118 | ||||||||
| Total Retail | 421 | 388 | 335 | ||||||||
The following table details our count of RCEs by geographical location as of December 31, 2025:
| RCEs by Geographic Location: | ||||||||||||||||||||
| (In thousands) | Electricity | % of Total | Natural Gas | % of Total | Total | % of Total | ||||||||||||||
| New England | 46 | 20% | 22 | 11% | 68 | 16% | ||||||||||||||
| Mid-Atlantic | 120 | 54% | 50 | 26% | 170 | 40% | ||||||||||||||
| Midwest | 25 | 11% | 33 | 17% | 58 | 14% | ||||||||||||||
| Southwest | 34 | 15% | 91 | 46% | 125 | 30% | ||||||||||||||
| Total | 225 | 100% | 196 | 100% | 421 | 100% | ||||||||||||||
The geographical locations noted above include the following states:
•New England - Connecticut, Maine, Massachusetts, New Hampshire and Rhode Island;
•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.
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During the year ended December 31, 2025, we added approximately 188,400 RCEs through our various organic sales channels. 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.
We also acquire companies and portfolios of customers through both external and affiliated channels. During the year ended December 31, 2025, we added 46,600 RCEs through asset purchase agreements. Refer to Note 15 “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.
While we remain focused on organic sales and identifying customer portfolio and business acquisitions, we cannot ensure that our RCE count will remain at current levels or grow. Our RCE count, as well as the margins we earn on our customers, contribute to our overall profitability, cash flow and ability to pay dividends.
RCE Activity
The following table shows our RCE activity during the years ended December 31, 2025, 2024 and 2023.
| (In thousands) | Retail Electricity | Retail Natural Gas | Total | % Net Annual Increase (Decrease) | ||||||||||
| December 31, 2022 | 201 | 130 | 331 | |||||||||||
| Additions | 118 | 22 | 140 | |||||||||||
| Attrition | (102) | (34) | (136) | |||||||||||
| December 31, 2023 | 217 | 118 | 335 | 1% | ||||||||||
| Additions | 129 | 80 | 209 | |||||||||||
| Attrition | (114) | (42) | (156) | |||||||||||
| December 31, 2024 | 232 | 156 | 388 | 16% | ||||||||||
| Additions | 143 | 92 | 235 | |||||||||||
| Attrition | (150) | (52) | (202) | |||||||||||
| December 31, 2025 | 225 | 196 | 421 | 26% | ||||||||||
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 2025, 2024 and 2023 were as follows:
| Year Ended | Quarter Ended | ||||||||||||||||
| December 31 | December 31 | September 30 | June 30 | March 31 | |||||||||||||
| 2023 | 3.4% | 3.3% | 3.1% | 3.1% | 3.9% | ||||||||||||
| 2024 | 3.9% | 4.0% | 4.1% | 3.4% | 3.9% | ||||||||||||
| 2025 | 4.2% | 4.9% | 4.0% | 3.5% | 4.3% | ||||||||||||
Customer attrition during the year ended December 31, 2024 was higher than the year ended December 31, 2023 driven primarily by proactive non-renewals in New York due to regulatory changes, along with increased attrition attributed to the new customer book acquisitions in the fourth quarter.
Customer attrition for the year ended December 31, 2025 was higher than the year ended December 31, 2024 primarily due to proactive non-renewals in Maryland due to regulatory changes as well as higher attrition related to new customer book acquisitions.
Customer Acquisition Costs
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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, 2025, customer acquisition costs were as follows:
| Year Ended December 31, | |||||||||||
| (In thousands) | 2025 | 2024 | 2023 | ||||||||
| Customer Acquisition Costs | $ | 10,415 | $ | 9,508 | $ | 6,736 | |||||
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 deemed economically or strategically advantageous.
Customer Credit Risk
Approximately 61% 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 credit loss expense on non-POR revenues was as follows:
| Year Ended December 31, | |||||||||||
| 2025 | 2024 | 2023 | |||||||||
| Total Non-POR Credit Loss as Percent of Revenue | 0.5 | % | 1.3 | % | 1.7 | % | |||||
During the year ended December 31, 2025, we experienced lower credit loss expense versus 2024. In 2025, our continued focus on collection efforts and enhanced credit check requirements resulted in a decrease in credit loss expense.
During the year ended December 31, 2024, we experienced lower credit loss expense versus 2023. In 2024, our continued focus on collection efforts resulted in a decrease in credit loss expense.
For the years ended December 31, 2025, 2024 and 2023, approximately 61%, 60% and 55%, 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, 2025, 2024 and 2023, 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 0.2%, 1.2% and 1.0%, 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
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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.
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 $3.8 million, $2.3 million and $7.3 million for the years ended December 31, 2025, 2024 and 2023, 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, 2025 were as follows:
| Year Ended December 31, | |||||||||||||||||
| (in thousands) | 2025 | 2024 | 2023 | ||||||||||||||
Adjusted EBITDA (1) | $ | 72,308 | $ | 58,581 | $ | 56,855 | |||||||||||
Retail Gross Margin (1) | $ | 149,769 | $ | 141,996 | $ | 136,650 | |||||||||||
(1) Adjusted EBITDA for the year ended December 31, 2025, 2024 and 2023 includes an add back of $0.1 million, $2.4 million and 0.8 million, respectively, related to merger agreement expense.
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 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 and Maximum Total 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) | 2025 | 2024 | 2023 | ||||||||||||||
| Reconciliation of Adjusted EBITDA to Net Income: | |||||||||||||||||
| Net income | $ | 35,583 | $ | 61,075 | $ | 26,105 | |||||||||||
| Depreciation and amortization | 21,824 | 9,446 | 9,102 | ||||||||||||||
| Interest expense | 7,517 | 6,943 | 9,334 | ||||||||||||||
| Income tax expense | 10,523 | 16,259 | 11,142 | ||||||||||||||
| EBITDA | 75,447 | 93,723 | 55,683 | ||||||||||||||
| Less: | |||||||||||||||||
| Net, (loss) on derivative instruments | (5,964) | (3,720) | (71,493) | ||||||||||||||
| Net, cash settlements on derivative instruments | (1,213) | 34,148 | 66,632 | ||||||||||||||
| Customer acquisition costs | 10,415 | 9,508 | 6,736 | ||||||||||||||
| Plus: | |||||||||||||||||
| Non-cash compensation expense | — | 2,411 | 2,295 | ||||||||||||||
| Merger agreement expense | 99 | 2,383 | 752 | ||||||||||||||
Adjusted EBITDA | $ | 72,308 | $ | 58,581 | $ | 56,855 | |||||||||||
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) | 2025 | 2024 | 2023 | ||||||||||||||
| Reconciliation of Adjusted EBITDA to net cash provided by operating activities: | |||||||||||||||||
| Net cash provided by operating activities | $ | 42,097 | $ | 50,484 | $ | 49,315 | |||||||||||
| Amortization of deferred financing costs | (792) | (852) | (825) | ||||||||||||||
| Bad debt expense | (1,308) | (2,469) | (3,442) | ||||||||||||||
| Interest expense | 7,517 | 6,943 | 9,334 | ||||||||||||||
| Income tax expense | 10,523 | 16,259 | 11,142 | ||||||||||||||
| Merger agreement expense | 99 | 2,383 | 752 | ||||||||||||||
| Changes in operating working capital | |||||||||||||||||
| Accounts receivable, prepaids, current assets | 29,506 | (734) | (17,159) | ||||||||||||||
| Inventory | 790 | (987) | (1,281) | ||||||||||||||
| Accounts payable, accrued liabilities, current liabilities | (10,470) | (3,380) | 15,206 | ||||||||||||||
| Other | (5,654) | (9,066) | (6,187) | ||||||||||||||
| Adjusted EBITDA | $ | 72,308 | $ | 58,581 | $ | 56,855 | |||||||||||
| Cash Flow Data: | |||||||||||||||||
| Cash flows provided by operating activities | $ | 42,097 | $ | 50,484 | $ | 49,315 | |||||||||||
| Cash flows used in investing activities | $ | (17,581) | $ | (4,727) | $ | (1,435) | |||||||||||
| Cash flows used in financing activities | $ | (51,894) | $ | (18,093) | $ | (40,636) | |||||||||||
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
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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.
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.
| Year Ended December 31, | |||||||||||||||||
| (in thousands) | 2025 | 2024 | 2023 | ||||||||||||||
| Reconciliation of Retail Gross Margin to Gross Profit: | |||||||||||||||||
| Total Revenues | $ | 463,451 | $ | 398,868 | $ | 435,192 | |||||||||||
| Less: | |||||||||||||||||
| Retail cost of revenues | 321,807 | 230,791 | 310,744 | ||||||||||||||
| Gross Profit | $ | 141,644 | $ | 168,077 | $ | 124,448 | |||||||||||
| Less: | |||||||||||||||||
| Net asset optimization expense | (3,770) | (2,326) | (7,326) | ||||||||||||||
| Net, (loss) on non-trading derivative instruments | (3,142) | (4,464) | (70,304) | ||||||||||||||
| Net, cash settlements on non-trading derivative instruments | (1,213) | 32,871 | 65,428 | ||||||||||||||
| Retail Gross Margin | $ | 149,769 | $ | 141,996 | $ | 136,650 | |||||||||||
| Retail Gross Margin - Retail Electricity Segment | $ | 88,909 | $ | 93,669 | $ | 87,566 | |||||||||||
| Retail Gross Margin - Retail Natural Gas Segment | $ | 60,847 | $ | 47,865 | $ | 47,489 | |||||||||||
| Retail Gross Margin - Other | $ | 13 | $ | 462 | $ | 1,595 | |||||||||||
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, | ||||||||||||||||
| 2025 | 2024 | 2023 | |||||||||||||||
| Revenues: | |||||||||||||||||
| Retail revenues | $ | 467,175 | $ | 399,418 | $ | 439,360 | |||||||||||
| Net asset optimization expense | (3,770) | (2,326) | (7,326) | ||||||||||||||
| Other revenue | 46 | 1,776 | 3,158 | ||||||||||||||
| Total Revenues | 463,451 | 398,868 | 435,192 | ||||||||||||||
| Operating Expenses: | |||||||||||||||||
| Retail cost of revenues | 321,807 | 230,791 | 310,744 | ||||||||||||||
| General and administrative expense | 66,289 | 74,453 | 68,874 | ||||||||||||||
| Depreciation and amortization | 21,824 | 9,446 | 9,102 | ||||||||||||||
| Total Operating Expenses | 409,920 | 314,690 | 388,720 | ||||||||||||||
| Operating income | 53,531 | 84,178 | 46,472 | ||||||||||||||
| Other (expense)/income: | |||||||||||||||||
| Interest expense | (7,517) | (6,943) | (9,334) | ||||||||||||||
| Interest and other income | 92 | 99 | 109 | ||||||||||||||
| Total Other (Expenses)/Income | (7,425) | (6,844) | (9,225) | ||||||||||||||
| Income before income tax expense | 46,106 | 77,334 | 37,247 | ||||||||||||||
| Income tax expense | 10,523 | 16,259 | 11,142 | ||||||||||||||
| Net income | $ | 35,583 | $ | 61,075 | $ | 26,105 | |||||||||||
| Other Performance Metrics: | |||||||||||||||||
Adjusted EBITDA (1) (2) | $ | 72,308 | $ | 58,581 | $ | 56,855 | |||||||||||
Retail Gross Margin (1) | $ | 149,769 | $ | 141,996 | $ | 136,650 | |||||||||||
| Customer Acquisition Costs | $ | 10,415 | $ | 9,508 | $ | 6,736 | |||||||||||
| RCE Attrition | 4.2 | % | 3.9 | % | 3.4 | % | |||||||||||
| Distributions paid to Class B non-controlling unit holders and dividends paid to Class A common shareholders | $ | (30,338) | $ | (10,664) | $ | (7,182) | |||||||||||
(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, 2025, 2024 and 2023 includes an add back of $0.1 million, $2.4 million and 0.8 million, respectively, related to merger agreement expense.
Total Revenues. Total revenues for the year ended December 31, 2025 were approximately $463.5 million, an increase of approximately $64.6 million, or 16%, from approximately $398.9 million for the year ended December 31, 2024. This increase was primarily due to higher gas and electricity volumes sold due to a larger customer book as a result of book purchases and higher electricity unit revenue. This was partially offset by lower natural gas unit revenue and other revenue during 2025 as compared to 2024. Total revenues for the year ended December 31, 2024 decreased approximately $36.3 million, or 8%, from approximately $435.2 million for the year ended December 31, 2023. This decrease was primarily due to lower electricity and gas unit revenue as a result of decreased electricity and gas rates, partially offset by higher electricity and gas volumes sold as a result of a larger electricity and gas customer book during 2024 as compared to 2023.
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Analysis of the impact of changes in prices and volumes between the years ended December 31, 2025, 2024 and 2023 are as follows:
| 2025 vs. 2024 | 2024 vs. 2023 | ||||||||||
| Change in electricity volumes sold | $ | 9.0 | $ | 4.4 | |||||||
| Change in natural gas volumes sold | 58.4 | 3.5 | |||||||||
| Change in electricity unit revenue per MWh | 4.0 | (32.6) | |||||||||
| Change in natural gas unit revenue per MMBtu | (3.7) | (15.3) | |||||||||
| Change in net asset optimization expense | (1.4) | 5.0 | |||||||||
| Change in other revenue | (1.7) | (1.3) | |||||||||
| Change in total revenues | $ | 64.6 | $ | (36.3) | |||||||
Retail Cost of Revenues. Total retail cost of revenues for the year ended December 31, 2025 was approximately $321.8 million, an increase of approximately $91.0 million, or 39%, from approximately $230.8 million for the year ended December 31, 2024. This increase was primarily due to change in derivative portfolio, higher gas and electricity volumes sold due to larger customer book and higher gas and electricity unit cost during 2025 as compared to 2024. Total retail cost of revenues for the year ended December 31, 2024 decreased approximately $79.9 million, or 26%, from approximately $310.7 million for the year ended December 31, 2023. This decrease was primarily due to lower electricity and gas costs due to lower electricity commodity price environment in 2024 and a change in our retail derivative portfolio, partially offset by higher electricity and gas volumes sold as a result of a larger electricity and gas customer book during 2024 as compared to 2023.
Analysis of the impact of changes in prices and volumes between the years ended December 31, 2025, 2024, and 2023 are as follows:
| 2025 vs. 2024 | 2024 vs. 2023 | ||||||||||
| Change in electricity volumes sold | $ | 6.2 | $ | 3.2 | |||||||
| Change in natural gas volumes sold | 30.2 | 2.0 | |||||||||
| Change in electricity unit cost per MWh | 11.6 | (37.5) | |||||||||
| Change in natural gas unit cost per MMBtu | 11.6 | (14.2) | |||||||||
| Change in value of retail derivative portfolio | 32.8 | (33.3) | |||||||||
| Change in other costs | (1.4) | (0.1) | |||||||||
| Change in retail cost of revenues | $ | 91.0 | $ | (79.9) | |||||||
General and Administrative Expense. General and administrative expense for the year ended December 31, 2025 was approximately $66.3 million, a decrease of approximately $8.2 million, or 11%, as compared to $74.5 million for the year ended December 31, 2024. This decrease was primarily attributable to a decrease in bad debt and legal expenses in 2025 as compared to 2024, and stock compensation expense related to the Merger in 2024 that did not reoccur in 2025. General and administrative expense for the year ended December 31, 2024 increased do you approximately $5.6 million, or 8%, as compared to $68.9 million for the year ended December 31, 2023.This increase was primarily attributable to an increase in stock compensation expense and legal fees, both of which were related to the Merger in 2024, and an increase in legal and regulatory expense in 2024 compared to 2023.
Depreciation and Amortization Expense. Depreciation and amortization expense for the year ended December 31, 2025 was approximately $21.8 million, an increase of approximately $12.4 million, or 131%, from approximately $9.4 million for the year ended December 31, 2024. This increase was primarily due to higher amortization expense associated with customer relationship intangibles as result of customer book purchases in 2025. Depreciation and amortization expense for the year ended December 31, 2024 increased approximately $0.3 million, or 4%, from approximately $9.1 million for the year ended December 31, 2023. This increase was primarily due to the increased amortization expense associated with customer relationship intangibles that were acquired in 2024 .
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Customer Acquisition Cost. Customer acquisition cost for the year ended December 31, 2025 was approximately $10.4 million, an increase of approximately $0.9 million, or 10%, from approximately $9.5 million for the year ended December 31, 2024. This increase was primarily due to increased sales activity in 2025 as compared to 2024. Customer acquisition cost for the year ended December 31, 2024 increased approximately $2.8 million, or 41% from approximately $6.7 million for the year ended December 31, 2023. This increase was primarily due to increased sales activity in 2024 as compared to 2023.
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Operating Segment Results
| Year Ended December 31, | |||||||||||||||||
| 2025 | 2024 | 2023 | |||||||||||||||
| (in thousands, except volume and per unit operating data) | |||||||||||||||||
| Retail Electricity Segment | |||||||||||||||||
| Total Revenues | $ | 313,341 | $ | 300,347 | $ | 328,466 | |||||||||||
| Retail Cost of Revenues | 228,291 | 186,246 | 240,979 | ||||||||||||||
| Less: Net (losses) gains on non-trading derivatives, net of cash settlements | (3,859) | 20,432 | (79) | ||||||||||||||
Retail Gross Margin (1) —Electricity | $ | 88,909 | $ | 93,669 | $ | 87,566 | |||||||||||
| Volumes—Electricity (MWhs) | 2,096,670 | 2,035,597 | 2,008,947 | ||||||||||||||
Retail Gross Margin (2) —Electricity per MWh | $ | 42.40 | $ | 46.02 | $ | 43.59 | |||||||||||
| Retail Natural Gas Segment | |||||||||||||||||
| Total Revenues | $ | 153,834 | $ | 99,071 | $ | 110,894 | |||||||||||
| Retail Cost of Revenues | 93,483 | 43,231 | 68,202 | ||||||||||||||
| Less: Net (losses) gains on non-trading derivatives, net of cash settlements | (496) | 7,975 | (4,797) | ||||||||||||||
Retail Gross Margin (1) —Gas | $ | 60,847 | $ | 47,865 | $ | 47,489 | |||||||||||
| Volumes—Gas (MMBtus) | 18,440,577 | 11,603,745 | 11,252,862 | ||||||||||||||
Retail Gross Margin (2) —Gas per MMBtu | $ | 3.30 | $ | 4.12 | $ | 4.22 | |||||||||||
(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.
Total revenues for the Retail Electricity Segment for the year ended December 31, 2025 were approximately $313.3 million, an increase of approximately $13.0 million, or 4%, from approximately $300.3 million for the year ended December 31, 2024. This increase was largely due to higher volumes sold, resulting in an increase of $9.0 million and higher electricity prices, resulting in an increase of revenue by $4.0 million. Total revenues for the Retail Electricity Segment for the year ended December 31, 2024 decreased approximately $28.2 million, or 9%, from approximately $328.5 million for the year ended December 31, 2023. This decrease was largely due to lower electricity prices, resulting in a decrease of $32.6 million, partially offset by higher volumes sold, which resulted in an increase of $4.4 million.
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Retail cost of revenues for the Retail Electricity Segment for the year ended December 31, 2025 was approximately $228.3 million, an increase of approximately $42.1 million, or 23%, from approximately $186.2 million for the year ended December 31, 2024. This increase was primarily due to a change in the value of our retail derivative portfolio used in hedging of $24.3 million, an increase in electricity costs of $11.6 million and higher electricity volumes sold, resulting in a increase of $6.2 million. Retail cost of revenues for the Retail Electricity Segment for the year ended December 31, 2024 decreased approximately $54.8 million, or 23%, from approximately $241.0 million for the year ended December 31, 2023. This decrease was primarily due to lower electricity costs of $37.5 million due to lower commodity price environment in 2024, a change in the value of our retail derivative portfolio used in hedging of $20.5 million, partially offset by higher volumes sold, resulting in a increase of $3.2 million.
Retail gross margin for the Retail Electricity Segment for the year ended December 31, 2025 was approximately $88.9 million, an decrease of approximately $4.8 million, or 5%, as compared to the year ended December 31, 2024, and 2024 increased approximately $6.1 million or 7% as compared to December 31, 2023 as indicated in the table below (in millions).
| 2025 vs. 2024 | 2024 vs. 2023 | ||||||||||
| Change in volumes sold | $ | 2.8 | $ | 1.2 | |||||||
| Change in unit margin per MWh | (7.6) | 4.9 | |||||||||
| Change in retail electricity segment retail gross margin | $ | (4.8) | $ | 6.1 | |||||||
Electricity unit margin decreased in 2025 compared to prior year as a result of higher electricity cost resulting in lower unit margin per MWh sold. Unit margins improved in 2024 compared to prior year as a result of lower electricity cost resulting in higher unit margin per MWh sold.
The volumes of electricity sold increased from 2,035,597 MWh for the year ended December 31, 2024 to 2,096,670 MWh for the year ended December 31, 2025. This increase was primarily due to a larger customer book during 2025. The volumes of electricity sold increased from 2,008,947 MWh for the year ended December 31, 2023 to 2,035,597 MWh for the year ended December 31, 2024. This increase was primarily due to a larger customer book during 2024.
Retail Natural Gas Segment
Total revenues for the Retail Natural Gas Segment for the year ended December 31, 2025 were approximately $153.8 million, an increase of approximately $54.7 million, or 55%, from approximately $99.1 million for the year ended December 31, 2024. This increase was primarily attributable to higher volumes sold due to a larger gas customer book as a result of book purchases, resulting in an increase of $58.4 million, offset by a lower natural gas rates which decreased total revenues by $3.7 million. Total revenues for the Retail Natural Gas Segment for the year ended December 31, 2024 decreased by approximately $11.8 million, or 11%, from approximately $110.9 million for the year ended December 31, 2023. This decrease was primarily attributable to lower rates, which resulted in an decrease in total revenues of $15.3 million, partially offset by a increase in volumes of $3.5 million related to customer book purchase in 2024.
Retail cost of revenues for the Retail Natural Gas Segment for the year ended December 31, 2025 were approximately $93.5 million, an increase of approximately $50.3 million, or 116%, from approximately $43.2 million for the year ended December 31, 2024. The increase was primarily due to higher volumes sold, resulting in an increase of $30.2 million due to a larger customer book, higher supply costs of $11.6 million, and a change in the fair value of our retail derivative portfolio used for hedging, which resulted in an increase by $8.5 million. Retail cost of revenues for the Retail Natural Gas Segment for the year ended December 31, 2024, a decreased approximately $25.0 million, or 37%, from approximately $68.2 million for the year ended December 31, 2023. The decrease was primarily due to lower supply costs of $14.2 million, decrease of $12.8 million due to change in the fair value of our retail derivative portfolio used for hedging, offset by higher volumes of $2.0 million.
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Retail gross margin for the Retail Natural Gas Segment for the year ended December 31, 2025 was approximately $60.8 million, an increase of approximately $12.9 million, or 27% from approximately $47.9 million for the year ended December 31, 2024, and 2024 increased approximately $0.4 million or 1% from approximately $47.5 million for the year ended December 31, 2023 as indicated in the table below (in millions).
| 2025 vs. 2024 | 2024 vs. 2023 | ||||||||||
| Change in volumes sold | $ | 28.1 | $ | 1.5 | |||||||
| Change in unit margin per MMBtu | (15.2) | (1.1) | |||||||||
| Change in retail natural gas segment retail gross margin | $ | 12.9 | $ | 0.4 | |||||||
Natural Gas unit margins decreased in 2025 compared to prior year primarily as a result of the higher natural gas cost in 2025. Natural Gas unit margins decreased in 2024 compared to prior year primarily as a result of the lower natural gas prices in 2024.
The volumes of natural gas sold increased from 11,603,745 MMBtu for the year ended December 31, 2024 to 18,440,577 MMBtu for the year ended December 31, 2025. This increase was primarily due to a larger customer book purchases in 2025 compared to 2024. The volumes of natural gas sold increased from 11,252,862 MMBtu for the year ended December 31, 2023 to 11,603,745 MMBtu for the year ended December 31, 2024. This increase was primarily due to a larger customer book in 2024 compared to 2023.
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 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.
Liquidity Position
The following table details our available liquidity as of December 31, 2025:
| December 31, | |||||
| ($ in thousands) | 2025 | ||||
| Cash and cash equivalents | $ | 41,760 | |||
Senior Credit Facility Availability (1) | 66,524 | ||||
Subordinated Debt Facility Availability (2) | 25,000 | ||||
| Total Liquidity | $ | 133,284 | |||
(1) Reflects amount of Letters of Credit that could be issued based on existing covenants as of December 31, 2025.
(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."
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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, | |||||||||||||||||
| 2025 | 2024 | 2023 | |||||||||||||||
| Net cash provided by operating activities | $ | 42,097 | $ | 50,484 | $ | 49,315 | |||||||||||
| Net cash used in by investing activities | $ | (17,581) | $ | (4,727) | $ | (1,435) | |||||||||||
| Net cash used in financing activities | $ | (51,894) | $ | (18,093) | $ | (40,636) | |||||||||||
Cash Flows Provided by Operating Activities. Cash flows provided by operating activities for the year ended December 31, 2025 decreased by $8.4 million compared to the year ended December 31, 2024. The decrease was primarily the results of changes in working capital. Cash flows provided by operating activities for the year ended December 31, 2024 increased by $1.2 million compared to the year ended December 31, 2023. The increase was primarily the result of higher net income in 2024 coupled with other changes in working capital.
Cash Flows Used in Investing Activities. Cash flows used in investing activities increased by $12.9 million for the year ended December 31, 2025. The increase was primarily the result of acquisition of customer books during the year ended December 31, 2025. Cash flows used in investing activities increased by $3.3 million for the year ended December 31, 2024. The increase was primarily the result of customer book acquisitions during the year ended December 31, 2024.
Cash Flows Used in Financing Activities. Cash flows used in financing activities increased by $33.8 million for the year ended December 31, 2025. The increase in cash flows used in financing activities was primarily due to an increase in Series A Preferred Stock redemption and buyback of $22.3 million, an increase in distributions to controlling interest of $9.9 million, an increase in distributions to our non-controlling interest of $8.8 million, partially offset by an increase in net borrowing of our Senior Credit Facility of $5.0 million and a decrease of $1.9 million in dividends to Series A Preferred Stock holders for the year ended December 31, 2025. Cash flows used in financing activities decreased by $22.5 million for the year ended December 31, 2024. This was primarily due to net paydown of of sub-debt of $20.0 million in 2023 that we did not have in 2024, and net borrowing of $12.0 million from our Senior Credit Facility for the year ended December 31, 2024, offset by $4.2 million used in buyback of Series A Preferred Stock, and $7.3 million in distributions to our non-controlling interest.
Sources of Liquidity and Capital Resources
Senior Credit
The Company and Spark Holdco (together with certain subsidiaries of the Company and Spark Holdco, the “Co-Borrowers”) maintain a senior secured borrowing base credit facility with Woodforest National Bank, as administrative agent (the “Agent”), swing bank, swap bank, issuing bank, joint-lead arranger, sole bookrunner and syndication agent, and the other financial institutions party thereto as lenders. On June 28, 2024, the Company entered into the First Amendment (the "First Amendment") to its senior credit facility (as amended by the First Amendment, the “Senior Credit Facility”). The Senior Credit Facility matures on June 30, 2027 and has a borrowing capacity of $250.0 million.
On June 25, 2025, the Co-Borrowers entered into new arrangements with the Agent and the financial institutions party thereto, and other additional financial institutions, to increase the borrowing capacity under the Senior Credit Facility to $250.0 million from $205.0 million.
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As of December 31, 2025, we had total commitments of $250.0 million under our Senior Credit Facility, of which $156.7 million was outstanding, including $36.7 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, 2025, we were in compliance with the covenants under our Senior Credit Facility. Based upon existing covenants as of December 31, 2025, we had availability to borrow up to $66.5 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, 2028.
See Note 9 "Debt" in the notes to our condensed consolidated financial statements for further information.
Uses of Liquidity and Capital Resources
Repayment of Current Portion of Senior Credit Facility
Our Senior Credit Facility matures in June 2027, 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, 2025 was $156.7 million, including $36.7 million of outstanding letters of credit. The current variable interest rate on the facility at December 31, 2025 was 6.95%.
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, 2025 and 2024, we spent a total of $10.4 million and $9.5 million, respectively, on organic customer acquisitions.
During the years ended December 31, 2025 and 2024, we spent a total of 14.6 million and 3.2 million, respectively, on customer book 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, 2025 included approximately $3.0 million related to information systems improvements.
Dividends and Distributions
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, 2025, Spark HoldCo distributed $15.2 million in cash to the non-controlling interest holder and 9.9 million to controlling interest holder.
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During the year ended December 31, 2025, we paid $9.0 million of dividends to holders of our Series A Preferred Stock, and as of December 31, 2025, we had accrued $1.6 million related to dividends to holders of our Series A Preferred Stock, which we paid on January 15, 2026. 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.
On January 15, 2026, our Board of Directors declared a quarterly cash dividend in the amount of $0.65699 per share for the Series A Preferred Stock. Dividends on the Series A Preferred Stock will be paid on April 15, 2026 to holders of record on April 1, 2026. 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. 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, 2025 (in millions):
| Total | 2026 | 2027 | 2028 | 2029 | 2030 | > 5 years | |||||||||||||||||
| Purchase obligations: | |||||||||||||||||||||||
| Pipeline transportation agreements | $ | 5.1 | $ | 4.3 | $ | 0.6 | $ | 0.2 | $ | — | $ | — | $ | — | |||||||||
Other purchase obligations (1) | 8.4 | 3.9 | 3.1 | 1.4 | — | — | — | ||||||||||||||||
| Total purchase obligations | $ | 13.5 | $ | 8.2 | $ | 3.7 | $ | 1.6 | $ | — | $ | — | $ | — | |||||||||
| Senior Credit Facility | $ | 120.0 | $ | — | $ | 120.0 | $ | — | $ | — | $ | — | $ | — | |||||||||
| Debt | $ | 120.0 | $ | — | $ | 120.0 | $ | — | $ | — | $ | — | $ | — | |||||||||
(1) The amounts presented here include contracts for billing services and other software agreements to support our operations.
As of December 31, 2025, we had no material "off-balance sheet arrangements."
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Related Party Transactions
For a discussion of related party transactions, see Note 13 "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
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, 2025 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, 2025, 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, 2025, 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 12 "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 $(4.4) million and $28.4 million for the years ended December 31, 2025 and December 31, 2024, 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, 2025, our Gas Non-Trading Fixed Price Open Position (hedges net of retail load) was a short position of 132,692 MMBtu. An increase of 10% in the market prices (NYMEX) from their December 31, 2025 levels would have increased the fair market value of our net non-trading energy portfolio by less than $0.1 million. Likewise, a decrease of 10% in the market prices (NYMEX) from their December 31, 2025 levels would have decreased the fair market value of our non-trading energy derivatives by less than $0.1 million. As of December 31, 2025, our Electricity Non-Trading Fixed Price Open Position (hedges net of retail load) was a short position of 166,378 MWhs. An increase of 10% in the forward market prices from their December 31, 2025 levels would have decreased the fair market value of our net non-trading energy portfolio by $1.0 million. Likewise, a decrease of 10% in the forward market prices from their December 31, 2025 levels would have increased the fair market value of our non-trading energy derivatives by $1.0 million.
Credit Risk
In many of the utility services territories where we conduct business, Purchase of Receivables ("POR") programs have been established, whereby the local regulated utility purchases our receivables, and becomes responsible for billing the customer and collecting payment from the customer. 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 61%, 60% and 55% 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, 2025, 2024 and 2023, 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 0.2%, 1.2% and 1.0%, 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, 2025, 2024 and 2023 was approximately 0.5%, 1.3% and 1.7% 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 2025.
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, 2025 and 2024, approximately $4.5 million and $4.4 million of our total exposure of $5.8 million and $6.1 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, 2025 and 2024.
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, 2025, we were co-borrowers under the Senior Credit Facility, under which $120.0 million of variable rate indebtedness was outstanding. Based on the average amount of our variable rate indebtedness outstanding during the year ended December 31, 2025, a 1% percent increase in interest rates would have resulted in additional annual interest expense of approximately $1.2 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, 2025, we paid $9.0 million of dividends to holders of our Series A Preferred Stock, and as of December 31, 2025, based on the Series A Preferred Stock outstanding on December 31, 2025, a 1.0% increase in interest rates would have resulted in additional dividends of $0.8 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: | ||||||||
| CONSOLIDATED BALANCE SHEETS AS OF DECEMBER 31, 2025 AND DECEMBER 31, 2024 | ||||||||
| CONSOLIDATED STATEMENTS OF OPERATIONS AND NET INCOME FOR THE YEARS ENDED DECEMBER 31, 2025, 2024 AND 2023 | ||||||||
| CONSOLIDATED STATEMENT OF CHANGES IN EQUITY FOR THE YEARS ENDED DECEMBER 31, 2025, 2024 AND 2023 | ||||||||
| CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 2025, 2024 AND 2023 | ||||||||
| 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, 2025, 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, 2025.
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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, 2025 and 2024, the related consolidated statements of operations and net income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2025, 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 financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.
Basis for opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated 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 consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated 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 consolidated 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 consolidated 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 consolidated 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 consolidated 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 consolidated 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
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As described further in Note 6 to the consolidated financial statements, the Company has recognized $9 million in gross derivative assets and $9.1 million in gross derivative liabilities as of December 31, 2025. 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.
Our audit procedures related to testing the completeness and accuracy of derivative instruments included the following, among others.
•We tested the design and implementation 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 brokers’ 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.
/s/ GRANT THORNTON LLP
We have served as the Company's auditor since 2022.
March 5, 2026
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VIA RENEWABLES, INC.
CONSOLIDATED BALANCE SHEETS
(in thousands, except share counts)
| December 31, 2025 | December 31, 2024 | |||||||||||||
| Assets | ||||||||||||||
| Current assets: | ||||||||||||||
| Cash and cash equivalents | $ | $ | ||||||||||||
| Restricted cash | ||||||||||||||
Accounts receivable, net of allowance for credit losses of $ | ||||||||||||||
| Accounts receivable—affiliates | ||||||||||||||
| Inventory | ||||||||||||||
Fair value of derivative assets (1) | ||||||||||||||
| Customer acquisition costs, net | ||||||||||||||
| Customer relationships, net | ||||||||||||||
| Deposits | ||||||||||||||
| Renewable energy credit asset | ||||||||||||||
| Other current assets | ||||||||||||||
| Total current assets | ||||||||||||||
| Property and equipment, net | ||||||||||||||
| Fair value of derivative assets | ||||||||||||||
| Customer acquisition costs, net | ||||||||||||||
| Customer relationships, net | ||||||||||||||
| Deferred tax assets | ||||||||||||||
| Goodwill | ||||||||||||||
| Other assets | ||||||||||||||
| Total Assets | $ | $ | ||||||||||||
| Liabilities, Series A Preferred Stock and Stockholders' Equity | ||||||||||||||
| Current liabilities: | ||||||||||||||
| Accounts payable | $ | $ | ||||||||||||
| Accounts payable—affiliates | ||||||||||||||
| Accrued liabilities | ||||||||||||||
| Renewable energy credit liability | ||||||||||||||
Fair value of derivative liabilities (1) | ||||||||||||||
| Other current liabilities | ||||||||||||||
| Total current liabilities | ||||||||||||||
| Long-term liabilities: | ||||||||||||||
| Fair value of derivative liabilities | ||||||||||||||
| Long-term portion of Senior Credit Facility | ||||||||||||||
| Total liabilities | ||||||||||||||
| Commitments and contingencies (Note 12) | ||||||||||||||
Series A Preferred Stock, par value $ | ||||||||||||||
| Stockholders' equity: | ||||||||||||||
| Common Stock : | ||||||||||||||
Class A common stock, par value $ | ||||||||||||||
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Class B common stock, par value $ | ||||||||||||||
| Additional paid-in capital | ||||||||||||||
| Accumulated other comprehensive loss | ( | ( | ||||||||||||
| Retained earnings | ||||||||||||||
| Total stockholders' equity | ||||||||||||||
| Non-controlling interest in Spark HoldCo, LLC | ||||||||||||||
| Total equity | ||||||||||||||
| Total Liabilities, Series A Preferred Stock and stockholders' equity | $ | $ | ||||||||||||
(1) The fair value of derivative asset/(liabilities) includes affiliates-related amounts of $0.1 million and $(0.3 ) million as of December 31, 2025 and 2024, respectively.
The accompanying notes are an integral part of the consolidated financial statements.
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VIA RENEWABLES, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS AND NET INCOME
(in thousands, except per share data)
| Year Ended December 31, | |||||||||||||||||
| 2025 | 2024 | 2023 | |||||||||||||||
| Revenues: | |||||||||||||||||
| Retail revenues | $ | $ | $ | ||||||||||||||
| Net asset optimization expense | ( | ( | ( | ||||||||||||||
| Other revenue | |||||||||||||||||
| Total revenues | |||||||||||||||||
| Operating expenses: | |||||||||||||||||
| Retail cost of revenues | |||||||||||||||||
| General and administrative | |||||||||||||||||
| Depreciation and amortization | |||||||||||||||||
| Total operating expenses | |||||||||||||||||
| Operating income | |||||||||||||||||
| Other (expense)/income: | |||||||||||||||||
| Interest expense | ( | ( | ( | ||||||||||||||
| Interest and other income | |||||||||||||||||
| Total other (expense)/income | ( | ( | ( | ||||||||||||||
| Income before income tax expense | |||||||||||||||||
| Income tax expense | |||||||||||||||||
| Net income | $ | $ | $ | ||||||||||||||
| Less: Net income attributable to non-controlling interest | |||||||||||||||||
| Net income attributable to Via Renewables, Inc. stockholders | $ | $ | $ | ||||||||||||||
| Less: Dividend on Series A preferred stock | |||||||||||||||||
| Net income attributable to stockholders of Class A common stock | $ | $ | $ | ||||||||||||||
| Net income attributable to Via Renewables, Inc. per share of Class A common stock | |||||||||||||||||
| Basic | $ | $ | $ | ||||||||||||||
| Diluted | $ | $ | $ | ||||||||||||||
| Weighted average shares of Class A common stock outstanding | |||||||||||||||||
| Basic | |||||||||||||||||
| Diluted | |||||||||||||||||
The accompanying notes are an integral part of the consolidated financial statements.
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VIA RENEWABLES, INC.
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
(in thousands)
| Issued Shares of Class A Common Stock | Issued Shares of Class B Common Stock | Treasury Stock | Class A Common Stock | Class B Common Stock | Treasury Stock | Accumulated Other Comprehensive Income (Loss) | Additional Paid-In Capital | Retained Earnings (Deficit) | Total Stockholders' Equity | Non-controlling Interest | Total Equity | |||||||||||||||||||||||||||
| Balance at 12/31/2022: | ( | $ | $ | $ | ( | $ | ( | $ | $ | $ | $ | ( | $ | |||||||||||||||||||||||||
| Stock based compensation | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
| Restricted stock unit vesting | — | — | — | — | — | — | ( | — | ( | — | ( | |||||||||||||||||||||||||||
| Consolidated net income | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
| Stock issued- reverse stock split | — | — | — | |||||||||||||||||||||||||||||||||||
| Distributions paid to non-controlling unit holders | — | — | — | — | — | — | — | — | — | — | ( | ( | ||||||||||||||||||||||||||
Dividends paid to Class A common stockholders ($ | — | — | — | — | — | — | — | ( | — | ( | — | ( | ||||||||||||||||||||||||||
| Dividends paid to Preferred Stockholders | — | — | — | — | — | — | — | ( | ( | ( | — | ( | ||||||||||||||||||||||||||
| Changes in ownership interest | — | — | — | — | — | — | — | — | ( | |||||||||||||||||||||||||||||
| Balance at December 31, 2023 | ( | $ | $ | $ | ( | $ | ( | $ | $ | $ | $ | ( | $ | |||||||||||||||||||||||||
| Stock based compensation | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
| Restricted stock unit vesting | — | — | — | — | — | ( | — | ( | — | ( | ||||||||||||||||||||||||||||
| Consolidated net income | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
| Contribution for cash settlement / merger | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||
| Distributions paid to non-controlling unit holders | — | — | — | — | — | — | — | — | — | — | ( | ( | ||||||||||||||||||||||||||
| Distribution to controlling interest | ( | — | ( | — | ( | — | ( | — | ( | |||||||||||||||||||||||||||||
| Dividends paid to Preferred Stockholders | — | — | — | — | — | — | — | — | ( | ( | — | ( | ||||||||||||||||||||||||||
| Treasury Shares | — | — | — | — | — | ( | — | — | — | |||||||||||||||||||||||||||||
| Changes in ownership interest | — | — | — | — | — | — | — | — | ( | |||||||||||||||||||||||||||||
| Balance at December 31, 2024 | $ | $ | $ | $ | ( | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||
| Consolidated net income | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
| Distributions paid to non-controlling unit holders | — | — | — | — | — | — | — | — | — | — | ( | ( | ||||||||||||||||||||||||||
| Distribution to controlling interest | ( | — | ( | — | — | ( | ( | ( | — | ( | ||||||||||||||||||||||||||||
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| Dividends paid to Preferred Stockholders | — | — | — | — | — | — | — | — | ( | ( | — | ( | ||||||||||||||||||||||||||
| Changes in ownership interest | — | — | — | — | — | — | — | — | ( | |||||||||||||||||||||||||||||
Balance at December 31, 2025 | $ | $ | $ | $ | ( | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||
The accompanying notes are an integral part of the consolidated financial statements.
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VIA RENEWABLES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
| Year Ended December 31, | |||||||||||||||||
| 2025 | 2024 | 2023 | |||||||||||||||
| Cash flows from operating activities: | |||||||||||||||||
| Net income | $ | $ | $ | ||||||||||||||
| Adjustments to reconcile net income to net cash flows provided by operating activities: | |||||||||||||||||
| Depreciation and amortization expense | |||||||||||||||||
| Deferred income taxes | |||||||||||||||||
| Stock based compensation | |||||||||||||||||
| Amortization of deferred financing costs | |||||||||||||||||
| Bad debt expense | |||||||||||||||||
| Loss on derivatives, net | |||||||||||||||||
| Current period cash settlements on derivatives, net | ( | ( | |||||||||||||||
| Other | |||||||||||||||||
| Changes in assets and liabilities: | |||||||||||||||||
| (Increase) decrease in accounts receivables | ( | ( | |||||||||||||||
| (Increase) decrease in accounts receivable - affiliates | ( | ||||||||||||||||
| (Increase) decrease in inventory | ( | ||||||||||||||||
| (Increase) in customer acquisition costs | ( | ( | ( | ||||||||||||||
| (Increase) decrease in prepaid and other current assets | ( | ||||||||||||||||
| Decrease (increase) in other assets | ( | ||||||||||||||||
| Increase (decrease) in accounts payable and accrued liabilities | ( | ||||||||||||||||
| Increase (decrease) in accounts payable—affiliates | ( | ||||||||||||||||
| Decrease in other current liabilities | ( | ||||||||||||||||
| Decrease in other non-current liabilities | ( | ||||||||||||||||
Net cash provided by operating activities | |||||||||||||||||
| Cash flows from investing activities: | |||||||||||||||||
| Purchases of property and equipment | ( | ( | ( | ||||||||||||||
| Acquisition of Customers | ( | ( | |||||||||||||||
| Net cash used in investing activities | ( | ( | ( | ||||||||||||||
| Cash flows from financing activities: | |||||||||||||||||
| Buyback/Redemption of Series A Preferred Stock | ( | ( | |||||||||||||||
| Borrowings on notes payable | |||||||||||||||||
| Payments on notes payable | ( | ( | ( | ||||||||||||||
| Net paydown on subordinated debt facility | ( | ||||||||||||||||
| Contribution for cash settlement of merger | |||||||||||||||||
| Restricted stock vesting | ( | ( | |||||||||||||||
| Payment of dividends to Class A common stockholders | ( | ( | |||||||||||||||
| Payment of distributions to non-controlling unitholders | ( | ( | ( | ||||||||||||||
| Payment of Preferred Stock dividends | ( | ( | ( | ||||||||||||||
| Net cash used in financing activities | ( | ( | ( | ||||||||||||||
| (Decrease) increase in Cash and cash equivalents and Restricted Cash | ( | ||||||||||||||||
| Cash and cash equivalents and Restricted cash—beginning of period | |||||||||||||||||
| Cash and cash equivalents and Restricted cash—end of period | $ | $ | $ | ||||||||||||||
| Supplemental Disclosure of Cash Flow Information: | |||||||||||||||||
| Non-cash items: | |||||||||||||||||
| Property and equipment purchase accrual | $ | ( | $ | $ | ( | ||||||||||||
| Cash paid during the period for: | |||||||||||||||||
| Interest | $ | $ | $ | ||||||||||||||
| Taxes | $ | $ | $ | ||||||||||||||
The accompanying notes are an integral part of the consolidated financial statements.
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VIA RENEWABLES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Formation and Organization
Company's Name Change
In August 2021, Spark Energy, Inc. changed its name from Spark Energy, Inc. to Via Renewables, Inc. (the "Company").
Organization
We are an independent retail energy services company that provides residential and commercial customers in competitive markets across the United States with an alternative choice for natural gas and electricity. The Company is a holding company whose sole material asset consists of units in Spark HoldCo, LLC (“Spark HoldCo”). The Company is the sole managing member of Spark HoldCo, is responsible for all operational, management and administrative decisions relating to Spark HoldCo’s business and consolidates the financial results of Spark HoldCo and its subsidiaries. Spark HoldCo is the direct and indirect owner of the subsidiaries through which we operate. We conduct our business through several brands across our service areas, including Electricity Maine, Electricity N.H., Major Energy, Provider Power Massachusetts, Spark Energy, Verde Energy, and Texans Choice Power. Via Energy Solutions (“VES”) is a wholly owned subsidiary of the Company that offers broker services for retail energy customers. Via Wireless was a wholly owned subsidiary of the Company that offered wireless services and equipment to wireless customers; however the subsidiary is no longer active and has ceased providing wireless services.
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2. Basis of Presentation and Summary of Significant Accounting Policies
Basis of Presentation
The accompanying consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) and pursuant to the rules and regulations of the SEC. Our financial statements are presented on a consolidated basis and include all wholly-owned and controlled subsidiaries. We account for investments over which we have significant influence but not a controlling financial interest using the equity method of accounting. All significant intercompany transactions and balances have been eliminated in the consolidated financial statements.
Prior Period Adjustment
During the quarter ended December 31, 2025, the Company recorded an out‑of‑period adjustment related to amounts that should have been recognized in interim periods earlier in the fiscal year. Management evaluated the impact of the adjustment on the Company’s previously issued quarterly financial statements and concluded that the adjustment was immaterial to each of the affected interim periods. The adjustment did not have a material impact on the Company’s financial position, results of operations, or cash flows for any period presented.
Subsequent Events
Use of Estimates and Assumptions
Relationship with our Founder, Sole Common Stock Shareholder, and Chief Executive Officer
W. Keith Maxwell, III is the Chief Executive Officer, a director, and the owner of all of the voting power of our common stock through his ownership of Retailco, LLC (“Retailco”). Retailco is a wholly owned subsidiary of TxEx Energy Investments, LLC (“TxEx”), which is wholly owned by Mr. Maxwell.
We enter into transactions with and pay certain costs on behalf of affiliates that are commonly controlled by Mr. Maxwell, and these affiliates enter into transactions with and pay certain costs on our behalf. We undertake these transactions in order to reduce risk, reduce administrative expense, create economies of scale, create strategic alliances and supply goods and services among these related parties.
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These transactions include, but are not limited to, employee benefits provided through the Company’s benefit plans, insurance plans, leased office space, certain administrative salaries, management due diligence, recurring management consulting, and accounting, tax, legal, or technology services. Amounts billed under these arrangements are based on services provided, departmental usage, or headcount, which are considered reasonable by management. As such, the accompanying consolidated financial statements include costs that have been incurred by the Company and then directly billed or allocated to affiliates, and costs that have been incurred by our affiliates and then directly billed or allocated to us, and are recorded net in general and administrative expense on the consolidated statements of operations with a corresponding accounts receivable—affiliates or accounts payable—affiliates, respectively, recorded in the consolidated balance sheets. Additionally, the Company enters into transactions with certain affiliates for sales or purchases of natural gas and electricity, which are recorded in retail revenues, retail cost of revenues, and net asset optimization revenues in the consolidated statements of operations with a corresponding accounts receivable—affiliate or accounts payable—affiliate in the consolidated balance sheets. The allocations and related estimates and assumptions are described more fully in Note 13 "Transactions with Affiliates."
On June 13, 2024, we consummated a merger the Company, Retailco, and wholly owned subsidiary of Retailco (the "Merger"), with the Company continuing as the surviving corporation in the Merger. As a result of the Merger, Mr. Maxwell and his affiliates became the owners of all of the issued and outstanding shares of our Class A common stock and Class B common stock. Effective as of the end of trading on June 13, 2024, the Class A common stock ceased to trade on NASDAQ.
Cash and Cash Equivalents
Cash and cash equivalents consist of all unrestricted demand deposits and funds invested in highly liquid instruments with original maturities of three months or less. The Company periodically assesses the financial condition of the institutions where these funds are held and believes that its credit risk is minimal with respect to these institutions.
Restricted Cash
As part of the customer acquisitions in 2024 and 2025, we funded an escrow account, the balance of which is reflected as restricted cash in our consolidated balance sheet. As we acquire customers and other conditions of the asset purchase agreement are met, we make payments to the sellers from the escrow account. As of December 31, 2025 and 2024, the balance in the escrow account was $1.1 million and 15.9 million. See Note 15 "Customer Acquisitions" for further discussion.
Inventory
Inventory primarily consists of natural gas used to fulfill and manage seasonality for fixed and variable-price retail customer load requirements and is valued at the lower of weighted average cost or net realizable value. Purchased natural gas costs are recognized in the consolidated statements of operations, within retail cost of revenues, when the natural gas is sold and delivered out of the storage facility using the weighted average cost of the gas sold.
The Company's valued its wireless device inventory at the lower of cost or net realizable value. As of December 31, 2025 and 2024, the Company's wireless device inventory balance was zero and $0.1 million, respectively.
Customer Acquisition Costs
The Company capitalizes direct response advertising costs that consist primarily of hourly and commission-based telemarketing costs, door-to-door agent commissions and other direct advertising costs associated with proven customer generation in its balance sheet. These costs are amortized over to two years .
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As of December 31, 2025 and 2024, the net customer acquisition costs were $10.9 million and $9.2 million, respectively, of which $7.8 million and $7.1 million were recorded in current assets, and $3.1 million and $2.1 million were recorded in non-current assets. Amortization of customer acquisition costs was $8.5 million, $7.1 million, and $4.8 million for the years ended December 31, 2025, 2024 and 2023, respectively, which is recorded in depreciation and amortization in the Consolidated Statements of Operations. Customer acquisition costs do not include customer acquisitions through merger and acquisition activities, which are recorded as customer relationships.
Customer Relationships
Customer contracts recorded as part of mergers or book acquisitions are reflected as customer relationships in our balance sheet. The Company has recorded capitalized customer relationship of $7.0 million and $8.0 million, net of amortization, as current assets as of December 31, 2025 and 2024, respectively, and $0.3 million and $3.5 million, net of amortization, as non-current assets as of December 31, 2025 and 2024, respectively, related to these intangible assets. These intangibles are amortized on a straight-line basis over the estimated average life of the related customer contracts acquired, which is eighteen months .
Customer relationship amortization expense was $11.3 million, $0.8 million, and $2.5 million for the years ended December 31, 2025, 2024 and 2023, respectively.
Trademarks
We record trademarks as part of our acquisitions which represent the value associated with the recognition and positive reputation of an acquired company to its target markets. This value would otherwise have to be internally developed through significant time and expense or by paying a third party for its use. These intangibles are amortized over the estimated ten-year life of the trademark on a straight-line basis.
The fair values of trademark assets were determined at the date of acquisition using a royalty savings method under the income approach. Under this approach, the Company estimates the present value of expected cash flows resulting from avoiding royalty payments to use a third party trademark. The Company analyzes market royalty rates charged for licensing trademarks and applied an expected royalty rate to a forecast of estimated revenue, which was then discounted using an appropriate risk adjusted rate of return. As of December 31, 2025 and 2024, we had recorded $1.6 million and $2.0 million related to these trademarks in other assets. Amortization expense was $0.4 million, $0.4 million, and $0.4 million for the years ended December 31, 2025, 2024 and 2023, respectively.
We review trademarks for impairment whenever events or changes in business circumstances indicate the carrying value of the intangible assets may not be recoverable. Impairment is indicated when the undiscounted cash flows estimated to be generated by the intangible assets are less than their respective carrying value. If an impairment
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Deferred Financing Costs
Property and Equipment
The Company records property and equipment at historical cost. Depreciation expense is recorded on a straight-line method based on estimated useful lives, which range from 2 to 7 years, along with estimates of the salvage values of the assets. When items of property and equipment are sold or otherwise disposed of, any gain or loss is recorded in the consolidated statements of operations.
Goodwill
Goodwill represents the excess of cost over fair value of the assets of businesses acquired in accordance with FASB ASC Topic 350 Intangibles-Goodwill and Other ("ASC 350"). The goodwill on our consolidated balance sheet as of December 31, 2025 is associated with both our Retail Natural Gas and Retail Electricity segments. We determine our segments, which are also considered our reporting units, by identifying each unit that engaged in business activities from which it may earn revenues and incur expenses, had operating results regularly reviewed by the segment manager for purposes of resource allocation and performance assessment, and had discrete financial information.
Goodwill is not amortized, but rather 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 as of October 31. We compare our estimate of the fair value of the reporting unit with its carrying value, 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.
In accordance with our accounting policy, we completed our annual assessment of goodwill impairment as of October 31, 2025 during the fourth quarter of 2025, using a quantitative assessment approach, and the test indicated no impairment.
Revenues and Cost of Revenues
Our revenues are derived primarily from the sale of natural gas and electricity to customers, including affiliates. Revenues are recognized by the Company based on consideration specified in contracts with customers when performance obligations are satisfied by transferring control over products to a customer. Utilizing these criteria, revenue is recognized when the natural gas or electricity is delivered to the customer. Similarly, cost of revenues is recognized when the commodity is delivered.
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Revenues for natural gas and electricity sales are recognized under the accrual method. Natural gas and electricity sales that have been delivered but not billed by period end are estimated. Accrued unbilled revenues are based on estimates of customer usage since the date of the last meter read provided by the utility. Volume estimates are based on forecasted volumes and estimated 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.
Costs for natural gas and electricity sales are similarly recognized under the accrual method. Natural gas and electricity costs that have not been billed to the Company by suppliers but have been incurred by period end are estimated. The Company estimates volumes for natural gas and electricity delivered based on the forecasted revenue volumes, estimated transportation cost volumes and estimation of other costs associated with retail load that varies by commodity utility territory. These costs include items like ISO fees, ancillary services and renewable energy credits. Estimated amounts are adjusted when actual usage is known and billed.
Our asset optimization activities, which primarily include natural gas physical arbitrage and other short term storage and transportation transactions, meet the definition of trading activities and are recorded on a net basis in the consolidated statements of operations in net asset optimization revenues. The Company recorded asset optimization revenues, primarily related to physical sales or purchases of commodities, of $37.5 million, $23.0 million and $24.6 million for the years ended December 31, 2025, 2024 and 2023, respectively, and recorded asset optimization costs of revenues of $41.3 million, $25.3 million and $31.9 million for the years ended December 31, 2025, 2024 and 2023, respectively, which are presented on a net basis in asset optimization revenues in the Consolidated Statements of Operations.
Other revenue is derived from contracts with customers through the provision of wireless and other services and the sale of wireless equipment. These revenues are recognized under the accrual method, over time as wireless and other services are provided and at the time of delivery of wireless equipment. Costs for wireless and other services and the sale of wireless equipment are similarly recognized on the accrual basis, including costs to procure wireless data and wireless devices. The Company ceased providing wireless services in 2024.
Natural Gas Imbalances
The Company recorded an imbalance payable of zero
Derivative Instruments
The Company uses derivative instruments such as futures, swaps, forwards and options to manage the commodity price risks of its business operations.
All derivatives are recorded in the consolidated balance sheets 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.
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.
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To manage the retail business, the Company holds 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.
Income Taxes
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. Amounts owed or refundable on current year returns is included as a current payable or receivable in the consolidated balance sheet.
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.
The Company recognizes interest and penalties related to unrecognized tax benefits within the provision for income taxes on continuing operations in our consolidated statements of operations.
Earnings per Share
Basic earnings per share (“EPS”) is computed by dividing net income attributable to stockholders (the numerator) by the weighted-average number of Class A common shares outstanding for the period (the denominator). Class B common shares are not included in the calculation of basic earnings per share because they are not participating securities and have no economic interests. Diluted earnings per share is similarly calculated except that the denominator is increased by potentially dilutive securities. We use the if-converted method to determine the potential dilutive effect of our Class B common stock.
Non-controlling Interest
Net income attributable to non-controlling interest represents the Class B Common stockholders' interest in income and expenses of the Company. The weighted average ownership percentages for the applicable reporting period are used to allocate the income (loss) before income taxes to each economic interest owner.
Commitments and Contingencies
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. Legal costs incurred in connection with loss contingencies are expensed as incurred.
Recently adopted accounting pronouncements
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In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The ASU requires enhanced income tax disclosures, particularly related to a reporting entity's effective tax rate reconciliation and income taxes paid. For the rate reconciliation, the update requires additional categories of information about federal, state, and foreign taxes and details about significant reconciling items, subject to a quantitative threshold. Income taxes paid must be similarly disaggregated by federal, state, and foreign based on a quantitative threshold. The standard became effective starting in annual period beginning after December 15, 2024. We adopted ASU 2023-09 effective January 1, 2025, and the adoption of this standard impacted certain income tax disclosures. See Note 11. Income Taxes in the accompanying notes to the consolidated financial statements for further detail.
New Accounting Standards Being Evaluated/Standards Not yet adopted
In November 2024, the FASB issued ASU 2024-03, Income Statement-Reporting Comprehensive Income-Expense Disaggregation Disclosures (Subtopic 220-40) (“ASU 2024-03”). ASU 2024-03 seeks to improve information about cost of sales and selling, general, and administrative expenses to assist investors in better understanding an entity’s cost structure and forecasting future cash flows. The updated guidance is effective for the Company for annual periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. The Company is currently evaluating the effect of this update on its consolidated financial statements and related disclosures.
In July 2025, the FASB issued ASU 2025-05, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses for Accounts Receivables and Contract Assets. The amendments in the ASU provide practical expedient and an accounting policy election to simplify the measurement of credit losses for certain receivables and contract assets. Under this practical expedient, entities may elect to assume that current conditions as of the balance sheet date do not change for the remaining life of the asset. The amendments are effective for annual reporting periods beginning after December 15, 2025, and interim reporting periods within those annual reporting periods. Early adoption is permitted in any interim or annual period in which financial statements have not yet been issued or made available for issuance. The Company is currently evaluating the effect of this update on its condensed consolidated financial statements and related disclosures.
In December 2025, the FASB issued ASU 2025‑11, Interim Reporting (Topic 270): Narrow‑Scope Improvements. This ASU clarifies and enhances guidance under ASC 270 on interim financial reporting by (i) clarifying the scope of ASC 270 such that it now explicitly applies only to entities that issue complete interim financial statements and related notes under U.S. GAAP, (ii) establishing clear guidance on the form of interim statements and notes, incorporating a comprehensive list of required interim disclosures drawn from across the ASC, and (iii) introducing a requirement to disclose material events and changes occurring after the end of the last annual period that could impact interim results. The ASU will be effective for interim periods beginning in 2028, though early adoption is permitted. This ASU is not expected to have a significant impact on our financial statements.
In December 2025, the FASB issued ASU 2025-12: Codification Improvements. The amendments in this ASU represent changes that (1) clarify, (2) correct errors, or (3) make minor improvements to the Accounting Standards Codification that make it easier to understand and apply. This amendments are effective for the Company’s annual reporting periods beginning July 1, 2027, and interim periods within those annual reporting periods, with early adoption permitted. This ASU is not expected to have a material impact on the Company’s consolidated financial statements.
The Company considers the applicability and impact of all ASUs. New ASUs were assessed and determined to be either not applicable or are expected to have minimal impact on our consolidated financial statements.
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3. Revenues
Our revenues are derived primarily from the sale of natural gas and electricity to customers, including affiliates. Revenue is measured based upon the quantity of gas or power delivered at prices contained or referenced in the customer's contract, and excludes any sales incentives (e.g. rebates) and amounts collected on behalf of third parties (e.g. sales tax).
Our revenues also include asset optimization activities. Asset optimization activities consist primarily of purchases and sales of gas that meet the definition of trading activities per FASB ASC Topic 815, Derivatives and Hedging. They are therefore excluded from the scope of FASB ASC Topic 606, Revenue from Contracts with Customers.
Other revenue is derived from contracts with customers through the provision of wireless and other services and the sale of wireless equipment. The Company ceased providing wireless services in 2024.
Revenues for electricity and natural gas sales are recognized under the accrual method when our performance obligation to a customer is satisfied, which is the point in time when the product is delivered and control of the product passes to the customer. Electricity and natural gas products may be sold as fixed-price or variable-price products. The typical length of a contract to provide electricity and/or natural gas is 12 months. Customers are billed and typically pay at least monthly, based on usage. Electricity and natural gas sales that have been delivered but not billed by period end are estimated and recorded as accrued unbilled revenues based on estimates of customer usage since the date of the last meter read provided by the utility. Volume estimates are based on forecasted volumes and estimated residential and commercial customer usage. Unbilled revenues are calculated by multiplying these volume estimates by the applicable rate by customer class (residential or commercial). Estimated amounts are adjusted when actual usage is known and billed.
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The following table discloses revenue by primary geographical market, customer type, and customer credit risk profile (in thousands). The table also includes a reconciliation of the disaggregated revenue to revenue by reportable segment (in thousands).
| Reportable Segments | |||||||||||||||||||||||||||||||||||
| Years ended December 31, 2025 | Years ended December 31, 2024 | Years ended December 31, 2023 | |||||||||||||||||||||||||||||||||
| Retail Electricity (c) | Retail Natural Gas | Total Reportable Segments | Retail Electricity (c) | Retail Natural Gas | Total Reportable Segments | Retail Electricity (c) | Retail Natural Gas | Total Reportable Segments | |||||||||||||||||||||||||||
| Primary markets (a) | |||||||||||||||||||||||||||||||||||
| New England | $ | $ | $ | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||
| Mid-Atlantic | |||||||||||||||||||||||||||||||||||
| Midwest | |||||||||||||||||||||||||||||||||||
| Southwest | |||||||||||||||||||||||||||||||||||
| $ | $ | $ | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||
| Customer type | |||||||||||||||||||||||||||||||||||
| Commercial | $ | $ | $ | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||
| Residential | |||||||||||||||||||||||||||||||||||
| Unbilled revenue (b) | ( | ( | ( | ( | |||||||||||||||||||||||||||||||
| $ | $ | $ | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||
| Customer credit risk | |||||||||||||||||||||||||||||||||||
| POR | $ | $ | $ | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||
| Non-POR | |||||||||||||||||||||||||||||||||||
| $ | $ | $ | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||
(a) The primary markets include the following states:
•New England - Connecticut, Maine, Massachusetts, New Hampshire and Rhode Island;
•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.
(b) Unbilled revenue is recorded in total until it is actualized, at which time it is categorized between commercial and residential customers.
(c) Retail Electricity includes services.
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Reconciliation to Consolidated Financial Information
A reconciliation of the reportable segment operating revenues to consolidated revenues is as follows:
| Year Ended December 31, | |||||||||||
| 2025 | 2024 | 2023 | |||||||||
| Total Reportable Segments Revenue | $ | $ | $ | ||||||||
| Net asset optimization expense | ( | ( | ( | ||||||||
| Other Revenue | |||||||||||
| Total Revenues | $ | $ | $ | ||||||||
We record gross receipts taxes on a gross basis in retail revenues and retail cost of revenues. During the year ended December 31, 2025, 2024 and 2023 our retail revenues included gross receipts taxes of $1.0 million, $1.1 million and $1.0 million respectively. During the year ended December 31, 2025, 2024 and 2023, our retail cost of revenues included gross receipts taxes of $7.1 million, $5.6 million and $5.2 million, respectively.
Accounts Receivables and Allowance for Credit Losses
The Company conducts business in many utility service markets where the local regulated utility purchases our receivables, and then becomes responsible for billing the customer and collecting payment from the customer (“POR programs”). These POR programs result in substantially all of the Company’s credit risk being linked to the 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.
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 accounts when the accounts receivable is deemed to be uncollectible.
The following table reflects the Company's beginning and ending balances of our account receivables.
| Year Ended December 31, | ||||||||||||||
2025 | 2024 | |||||||||||||
| Beginning balance accounts receivables | $ | $ | ||||||||||||
| Ending balance of accounts receivables | $ | $ | ||||||||||||
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. Bad debt expense of $1.3 million, $2.5 million and $3.4 million was recorded in general and administrative expense in the consolidated statements of operations for the years ended December 31, 2025, 2024 and 2023, respectively.
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A rollforward of our allowance for credit losses for the year ended December 31, 2025 is presented in the table below (in thousands):
| Balance at December 31, 2024 | $ | ( | |||
| Bad debt provision | ( | ||||
| Write-offs | |||||
| Recovery of previous write offs | ( | ||||
| Balance at December 31, 2025 | $ | ( | |||
4. Equity
Non-controlling Interest
We hold an economic interest and are the sole managing member in Spark HoldCo, with affiliates of Mr. Maxwell and majority shareholder holding the remaining economic interests in Spark HoldCo. As a result, we consolidate the financial position and results of operations of Spark HoldCo, and reflect the economic interests owned by these affiliates as a non-controlling interest.
On December 31, 2024, Spark HoldCo distributed $5.0 million in cash to the non-controlling interest holder, and the non-controlling interest holder transferred 206,273 shares of Class B common stock to the Company. After the distribution and the share transfer, the Company’s equity ownership in Spark HoldCo increased by 2.82 %, whereas the equity ownership of the non-controlling interest holder decreased by 2.82 %.
On March 31, 2025, Spark HoldCo distributed $6.0 million in cash to the non-controlling interest holder, and the non-controlling interest holder transferred 262,891 shares of Class B common stock to the Company. After the distribution and the share transfer, the Company’s equity ownership in Spark HoldCo increased by 3.59 %, whereas the equity ownership of the non-controlling interest holder decreased by 3.59 %.
During the period from April 2025 to December 2025, Spark HoldCo distributed $9.2 million in cash to the non-controlling interest holder and distributed pro-rated $9.9 million in cash to the controlling interest holder. The pro rated distribution during the period did not result in share transfer and change in equity ownership.
The following table summarizes the effects of changes in the Company's ownership interest in Spark HoldCo's equity (in thousands):
| Year Ended December 31, | ||||||||
| 2025 | 2024 | |||||||
| Net income attributable to Via Renewables, Inc. stockholders | $ | $ | ||||||
| Transfers (to) from the non-controlling interest | ||||||||
| Decrease in Via Renewables additional paid in capital from the equity shift | ( | ( | ||||||
| Net transfers (to) from non-controlling interest | ( | ( | ||||||
| Changes from net income attributable to Via Renewables stockholders and transfers (to) from non-controlling interest | $ | $ | ||||||
The Company and affiliates owned the following economic interests in Spark HoldCo at December 31, 2025 and December 31, 2024, respectively.
| The Company | Affiliated Owners | |||||||
December 31, 2025 | % | % | ||||||
December 31, 2024 | % | % | ||||||
The following table summarizes the portion of net income (loss) and income tax expense (benefit) attributable to non-controlling interest (in thousands):
| Year Ended December 31, | |||||||||||
| 2025 | 2024 | 2023 | |||||||||
| Net income allocated to non-controlling interest | $ | $ | $ | ||||||||
| Less: Income tax expense allocated to non-controlling interest | |||||||||||
| Net income attributable to non-controlling interest | $ | $ | $ | ||||||||
Class A Common Stock and Class B Common Stock
As a result of the Merger, on June 13, 2024, Mr. Maxwell and his affiliates became the owners of all of the issued and outstanding shares of Class A common stock and Class B common stock. Effective as of the end of trading on June 13, 2024, the Class A common stock ceased to trade on NASDAQ.
Dividends on Class A Common Stock
In April 2023, we announced that our Board of Directors elected to temporarily suspend the quarterly cash dividend on the Class A common stock.
Dividends declared for the Company's Class A common stock are reported as a reduction of retained earnings, or a reduction of additional paid in capital to the extent retained earnings are exhausted. During the years ended December 31, 2025, 2024, and 2023, we paid dividends on our Class A common stock of zero , zero , and $2.9 million. Dividends paid per share on each share of Class A common stock totaled $0.90625 for the year ended December 31, 2023.
Preferred Stock
The Company has 20,000,000 2,327,080 3,380,440
Issuance of Class A Common Stock Upon Vesting of Restricted Stock Units
For the years ended December 31, 2025, 2024, and 2023, zero , 95,592 , and 68,439 , respectively of restricted stock units vested, with zero , 61,709 , and 46,466 , respectively of shares of common stock distributed to the holders of these units. Differences between shares vested and issued were a result of zero , 33,883 , and 21,973 shares of common stock withheld by the Company to cover taxes owed on the vesting of such units.
As a result of the Merger, all of the Company’s outstanding restricted stock units were converted into $11.00 per share (other than those owned by Mr. Maxwell, which were cancelled for no consideration). The total payout for the settlement of restricted stock units was $0.6 million, which was paid by Retailco. This was recorded as contribution from non-controlling interest.
Earnings Per Share
Basic earnings per share (“EPS”) is computed by dividing net income attributable to stockholders (the numerator) by the weighted-average number of Class A common shares outstanding for the period (the denominator). Class B common shares are not included in the calculation of basic earnings per share because they are not participating securities and have no economic interests. Diluted earnings per share is similarly calculated except that the denominator is increased by potentially dilutive securities.
The following table presents the computation of basic and diluted income (loss) per share for the years ended December 31, 2025, 2024, and 2023 (in thousands, except per share data):
| Year Ended December 31, | |||||||||||
| 2025 | 2024 | 2023 | |||||||||
| Net income attributable to Via Renewables, Inc. stockholders | $ | $ | $ | ||||||||
| Less: Dividend on Series A preferred stock | |||||||||||
| Net income attributable to stockholders of Class A common stock | $ | $ | $ | ||||||||
| Basic weighted average Class A common shares outstanding | |||||||||||
| Basic earnings per share attributable to stockholders | $ | $ | $ | ||||||||
| Net income attributable to stockholders of Class A common stock | $ | $ | $ | ||||||||
| Effect of conversion of Class B common stock to shares of Class A common stock | |||||||||||
| Diluted net income attributable to stockholders of Class A common stock | $ | $ | $ | ||||||||
| Basic weighted average Class A common shares outstanding | |||||||||||
| Effect of dilutive Class B common stock | |||||||||||
| Diluted weighted average shares outstanding | |||||||||||
| Diluted earnings per share attributable to stockholders | $ | $ | $ | ||||||||
The computation of diluted earnings per share for the year ended December 31, 2025 and December 31, 2024 excludes 3.5 million and 4.0 million shares of Class B common stock because the effect of their conversion was antidilutive. The Company's outstanding shares of Series A Preferred Stock were not included in the calculation of diluted earnings per share because they contain only contingent redemption provisions that have not occurred.
Variable Interest Entity
Spark HoldCo is a variable interest entity due to its lack of rights to participate in significant financial and operating decisions and its inability to dissolve or otherwise remove its management. Spark HoldCo owns all of the outstanding membership interests in each of our operating subsidiaries. We are the sole managing member of Spark HoldCo, manage Spark HoldCo's operating subsidiaries through this managing membership interest, and are considered the primary beneficiary of Spark HoldCo. The assets of Spark HoldCo cannot be used to settle our obligations except through distributions to us, and the liabilities of Spark HoldCo cannot be settled by us except through contributions to Spark HoldCo. The following table includes the carrying amounts and classification of the assets and liabilities of Spark HoldCo that are included in our consolidated balance sheet as of December 31, 2025 and 2024 (in thousands):
| December 31, 2025 | December 31, 2024 | |||||||
| Assets | ||||||||
| Current assets: | ||||||||
| Cash and cash equivalents | $ | $ | ||||||
| Accounts receivable | ||||||||
| Other current assets | ||||||||
| Total current assets | ||||||||
| Non-current assets: | ||||||||
| Goodwill | ||||||||
| Other assets | ||||||||
| Total non-current assets | ||||||||
| Total Assets | $ | $ | ||||||
| Liabilities | ||||||||
| Current liabilities: | ||||||||
| Accounts Payable and Accrued Liabilities | $ | $ | ||||||
| Other current liabilities | ||||||||
| Total current liabilities | ||||||||
| Long-term liabilities: | ||||||||
| Long-term portion of Senior Credit Facility | ||||||||
| Subordinated debt—affiliate | ||||||||
| Other long-term liabilities | ||||||||
| Total long-term liabilities | ||||||||
| Total Liabilities | $ | $ | ||||||
5. Preferred Stock
Holders of the Series A Preferred Stock have no voting rights, except in specific circumstances of delisting or in the case the dividends are in arrears as specified in the Series A Preferred Stock Certificate of Designations. The Series A Preferred Stock accrued dividends at an annual percentage rate of 8.75 % through April 14, 2022. The floating rate period for the Series A Preferred Stock began on April 15, 2022. The dividend on the Series A Preferred Stock will accrue at an annual rate equal to the sum of (a) Three-Month LIBOR (if it then exists), or an alternative reference rate as of the applicable determination date and (b) 6.578 %, based on the $25.00 liquidation preference per share of the Series A Preferred Stock. The liquidation preference provisions of the Series A Preferred Stock are considered contingent redemption provisions because there are rights granted to the holders of the Series A Preferred Stock that are not solely within our control upon a change in control of the Company. Accordingly, the Series A Preferred Stock is presented between liabilities and the equity sections in the accompanying condensed consolidated balance sheets. As of April 15, 2022, we have the option to redeem our 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.
As a result of the Merger, holders of the Company’s Series A Preferred Stock were provided an optional limited change of control conversion right (the “Conversion Right”), available at the option of the holder, for $8.07 per share in cash. On June 27, 2024, the Company provided notice to the holders of the Series A Preferred Stock of the Conversion Right. Holders of the Series A Preferred Stock were entitled to exercise the Conversion Right through July 26, 2024. No holders of the Series A Preferred Stock exercised the Conversion Right.
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During the year ended December 31, 2025, we paid $9.0 million in dividends to holders of the Series A Preferred Stock. As of December 31, 2025, we had accrued $1.6 million related to dividends to holders of the Series A Preferred Stock. This dividend was paid on January 15, 2026. During the year ended December 31, 2024, the Company paid $10.9 million in dividends to holders of the Series A Preferred Stock and had accrued $2.4 million as of December 31, 2024.
During the year ended December 31, 2024, we purchased 187,103 shares of our Series A Preferred Stock, at a purchase price of $22.50 per share, for a total cost of $4.2 million in cash, pursuant to a tender offer for the Series A Preferred Stock commenced in November 2024.
During the year ended December 31, 2025, we repurchased total of 20,277 shares of our Series A Preferred Stock at an average purchase price of $23.53 per share, for a total cost of $0.5 million in cash, pursuant to a tender offer for the Series A Preferred Stock.
During the year end December 31, 2025, we redeemed total of 1,033,083 shares of our Series A Preferred Stock, for an average redemption price of $25.26 per share. We paid total of $26.1 million for the redemption.
On January 15, 2026, the Company declared a quarterly cash dividend in the amount of $0.65699 per share of Series A Preferred Stock. The dividend will be paid on April 15, 2026 to holders of record on April 1, 2026 of the Series A Preferred Stock.
A summary of our preferred equity balance for the years ended December 31, 2025 and 2024 is as follows:
| (in thousands) | ||||||||
Balance at December 31, 2023 | $ | |||||||
| Repurchase of Series A Preferred Stock | ( | |||||||
| Accumulated dividends on Series A Preferred Stock | ( | |||||||
Balance at December 31, 2024 | $ | |||||||
| Repurchase of Series A Preferred Stock | ( | |||||||
| Redemption of Series A Preferred Stock | ( | |||||||
| Accumulated dividends on Series A Preferred Stock | ( | |||||||
Balance at December 31, 2025 | $ | |||||||
6. Derivative Instruments
We are exposed to the impact of market fluctuations in the price of electricity and natural gas, basis differences in the price of natural gas, storage charges, renewable energy credits ("RECs"), and capacity charges from independent system operators. We use derivative instruments in an effort to manage our cash flow exposure to these risks. These instruments are not designated as hedges for accounting purposes, and accordingly, changes in the market value of these derivative instruments are recorded in the cost of revenues. As part of our strategy to optimize pricing in our natural gas related activities, we also manage a portfolio of commodity derivative instruments held for trading purposes. Our commodity trading activities are subject to limits within our Risk Management Policy. For these derivative instruments, changes in the fair value are recognized currently in earnings in net asset optimization revenues.
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to net against the related derivative liability's fair value. The specific types of derivative instruments we may execute to manage the commodity price risk include the following:
•Forward contracts, which commit us to purchase or sell energy commodities in the future;
•Futures contracts, which are exchange-traded standardized commitments to purchase or sell a commodity or financial instrument;
•Swap agreements, which require payments to or from counterparties based upon the differential between two prices for a predetermined notional quantity; and
•Option contracts, which convey to the option holder the right but not the obligation to purchase or sell a commodity.
The Company has entered into other energy-related contracts that do not meet the definition of a derivative instrument or for which we made a normal purchase, normal sale election and are therefore not accounted for at fair value including the following:
•Forward electricity and natural gas purchase contracts for retail customer load;
•Renewable energy credits; and
•Natural gas transportation contracts and storage agreements.
Volumes Underlying Derivative Transactions
The following table summarizes the net notional volumes of our open derivative financial instruments accounted for at fair value by commodity. Positive amounts represent net buys while bracketed amounts are net sell transactions (in thousands):
Non-trading
| Commodity | Notional | December 31, 2025 | December 31, 2024 | ||||||||||||||
| Natural Gas | MMBtu | ||||||||||||||||
| Electricity | MWh | ||||||||||||||||
Trading
| Commodity | Notional | December 31, 2025 | December 31, 2024 | ||||||||||||||
| Natural Gas | MMBtu | ||||||||||||||||
Gains (Losses) on Derivative Instruments
Gains (losses) on derivative instruments, net and current period settlements on derivative instruments were as follows for the periods indicated (in thousands):
| Year Ended December 31, | |||||||||||||||||
| 2025 | 2024 | 2023 | |||||||||||||||
| (Loss) on non-trading derivatives, net | $ | ( | $ | ( | $ | ( | |||||||||||
| (Loss) Gain on trading derivatives, net | ( | ( | |||||||||||||||
| (Loss) on derivatives, net | $ | ( | $ | ( | $ | ( | |||||||||||
Current period settlements on non-trading derivatives | ( | ||||||||||||||||
| Current period settlements on trading derivatives | |||||||||||||||||
| Total current period settlements on derivatives | $ | ( | $ | $ | |||||||||||||
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Gains (losses) on trading derivative instruments are recorded in net asset optimization revenues and gains (losses) on non-trading derivative instruments are recorded in retail cost of revenues on the consolidated statements of operations.
Fair Value of Derivative Instruments
The following tables summarize the fair value and offsetting amounts of our derivative instruments by counterparty and collateral received or paid (in thousands):
| December 31, 2025 | |||||||||||||||||||||||||||||
| Description | Gross Assets | Gross Amounts Offset | Net Assets | Cash Collateral Offset | Net Amount Presented | ||||||||||||||||||||||||
| Non-trading commodity derivatives | $ | $ | ( | $ | $ | $ | |||||||||||||||||||||||
| Trading commodity derivatives | ( | ||||||||||||||||||||||||||||
| Total Current Derivative Assets | ( | ||||||||||||||||||||||||||||
| Non-trading commodity derivatives | ( | ( | |||||||||||||||||||||||||||
| Trading commodity derivatives | ( | ||||||||||||||||||||||||||||
| Total Non-current Derivative Assets | ( | ( | |||||||||||||||||||||||||||
| Total Derivative Assets | $ | $ | ( | $ | $ | ( | $ | ||||||||||||||||||||||
| Description | Gross Liabilities | Gross Amounts Offset | Net Liabilities | Cash Collateral Offset | Net Amount Presented | ||||||||||||||||||||||||
| Non-trading commodity derivatives | $ | ( | $ | $ | ( | $ | $ | ( | |||||||||||||||||||||
| Trading commodity derivatives | ( | ( | ( | ||||||||||||||||||||||||||
| Total Current Derivative Liabilities | ( | ( | ( | ||||||||||||||||||||||||||
| Non-trading commodity derivatives | ( | ( | ( | ||||||||||||||||||||||||||
| Trading commodity derivatives | ( | ( | ( | ||||||||||||||||||||||||||
| Total Non-current Derivative Liabilities | ( | ( | ( | ||||||||||||||||||||||||||
| Total Derivative Liabilities | $ | ( | $ | $ | ( | $ | $ | ( | |||||||||||||||||||||
| December 31, 2024 | |||||||||||||||||||||||||||||
| Description | Gross Assets | Gross Amounts Offset | Net Assets | Cash Collateral Offset | Net Amount Presented | ||||||||||||||||||||||||
| Non-trading commodity derivatives | $ | $ | ( | $ | $ | $ | |||||||||||||||||||||||
| Trading commodity derivatives | ( | ||||||||||||||||||||||||||||
| Total Current Derivative Assets | ( | ||||||||||||||||||||||||||||
| Non-trading commodity derivatives | ( | ||||||||||||||||||||||||||||
| Trading commodity derivatives | |||||||||||||||||||||||||||||
| Total Non-current Derivative Assets | ( | ||||||||||||||||||||||||||||
| Total Derivative Assets | $ | $ | ( | $ | $ | $ | |||||||||||||||||||||||
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| Description | Gross Liabilities | Gross Amounts Offset | Net Liabilities | Cash Collateral Offset | Net Amount Presented | ||||||||||||||||||||||||
| Non-trading commodity derivatives | $ | ( | $ | $ | ( | $ | $ | ( | |||||||||||||||||||||
| Trading commodity derivatives | ( | ( | ( | ||||||||||||||||||||||||||
| Total Current Derivative Liabilities | ( | ( | ( | ||||||||||||||||||||||||||
| Non-trading commodity derivatives | ( | ( | ( | ||||||||||||||||||||||||||
| Trading commodity derivatives | ( | ( | ( | ||||||||||||||||||||||||||
| Total Non-current Derivative Liabilities | ( | ( | ( | ||||||||||||||||||||||||||
| Total Derivative Liabilities | $ | ( | $ | $ | ( | $ | $ | ( | |||||||||||||||||||||
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7. Property and Equipment
Property and equipment consist of the following (in thousands):
| Estimated useful lives (years) | December 31, 2025 | December 31, 2024 | |||||||||||||||
| Information technology | $ | $ | |||||||||||||||
| Other | |||||||||||||||||
| Total | |||||||||||||||||
| Accumulated depreciation | ( | ( | |||||||||||||||
| Property and equipment—net | $ | $ | |||||||||||||||
Information technology assets include software and consultant time used in the application, development and implementation of various systems including customer billing and resource management systems. As of each of December 31, 2025 and 2024, information technology includes $0.9 million and $2.3 million, respectively, of costs associated with assets not yet placed into service.
Depreciation expense recorded in the consolidated statements of operations was $1.7 million, $1.1 million and $1.4 million for the years ended December 31, 2025, 2024 and 2023, respectively.
8. Intangible Assets
Goodwill, customer relationships and trademarks consist of the following amounts (in thousands):
| December 31, 2025 | December 31, 2024 | ||||||||||
| Goodwill | $ | $ | |||||||||
Customer Relationships—Other | |||||||||||
| Cost | $ | $ | |||||||||
| Accumulated amortization | ( | ( | |||||||||
Customer Relationships—Other, net | $ | $ | |||||||||
Trademarks | |||||||||||
| Cost | $ | $ | |||||||||
| Accumulated amortization | ( | ( | |||||||||
| Trademarks, net | $ | $ | |||||||||
Changes in goodwill, customer relationships (including non-compete agreements) and trademarks consisted of the following (in thousands):
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Goodwill | Customer Relationships— Acquired & Non-Compete Agreements | Customer Relationships— Other | Trademarks | ||||||||||||||||||||
| Balance at December 31, 2022 | $ | $ | $ | $ | |||||||||||||||||||
| Additions | |||||||||||||||||||||||
| Amortization | ( | ( | ( | ||||||||||||||||||||
| Balance at December 31, 2023 | $ | $ | $ | $ | |||||||||||||||||||
| Additions | |||||||||||||||||||||||
| Amortization | ( | ( | |||||||||||||||||||||
| Balance at December 31, 2024 | $ | $ | $ | $ | |||||||||||||||||||
| Additions | |||||||||||||||||||||||
| Amortization | ( | ( | |||||||||||||||||||||
| Balance at December 31, 2025 | $ | $ | $ | $ | |||||||||||||||||||
Estimated future amortization expense for customer relationships and trademarks at December 31, 2025 is as follows (in thousands):
| Year Ending December 31, | |||||
| 2026 | $ | ||||
| 2027 | |||||
| 2028 | |||||
| 2029 | |||||
| 2030 | |||||
| > 5 years | |||||
| Total | $ | ||||
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9. Debt
Debt consists of the following amounts as of December 31, 2025 and 2024 (in thousands):
| December 31, 2025 | December 31, 2024 | ||||||||||
| Long-term debt: | |||||||||||
Senior Credit Facility (1) (2) | $ | $ | |||||||||
| Subordinated Debt | |||||||||||
| Total long-term debt | |||||||||||
| Total debt | $ | $ | |||||||||
(1) As of December 31, 2025 and 2024, the weighted average interest rate on the Senior Credit Facility was 6.95 % and 7.59 %, respectively.
(2) As of December 31, 2025 and 2024, we had $36.7 million and $25.6 million in letters of credit issued, respectively.
Capitalized financing costs associated with our Senior Credit Facility were $1.4 million and $1.7 million as of December 31, 2025 and 2024, respectively. Of these amounts, $0.9 million and $0.7 million are recorded in other current assets, and $0.5 million and $1.0 million are recorded in other non-current assets in the consolidated balance sheets as of December 31, 2025 and 2024, respectively.
Interest expense consists of the following components for the periods indicated (in thousands):
| Years Ended December 31, | |||||||||||||||||
| 2025 | 2024 | 2023 | |||||||||||||||
Senior Credit Facility | $ | $ | $ | ||||||||||||||
| Letters of credit fees and commitment fees | |||||||||||||||||
Amortization of deferred financing costs | |||||||||||||||||
Other | |||||||||||||||||
| Interest expense | $ | $ | $ | ||||||||||||||
Senior Credit Facility
The Company and Spark Holdco (together with certain subsidiaries of the Company and Spark Holdco, the “Co-Borrowers”) maintain a senior secured borrowing base credit facility with Woodforest National Bank, as administrative agent (the “Agent”), swing bank, swap bank, issuing bank, joint-lead arranger, sole bookrunner and syndication agent, and the other financial institutions party thereto as lenders. As further described below, on June 28, 2024, the Company entered into the First Amendment (the "First Amendment") to its senior credit facility (as amended by the First Amendment, the “Senior Credit Facility”). The Senior Credit Facility matures on June 30, 2027. As a result of the First Amendment to the Credit Agreement, we wrote off $0.1 million in deferred financing costs.
On June 25, 2025, the Co-Borrowers entered into new arrangements with the Agent and the financial institutions party thereto, and other additional financial institutions, to increase the borrowing capacity under the Senior Credit Facility to $250.0 million from $205.0 million.
Borrowings under the Senior Credit Facility are available for working capital loans, loans to fund acquisitions, swingline loans, letters of credit and, following the First Amendment, for repurchases of Series A Preferred Stock (subject to the terms and conditions therein).
Borrowings under the Senior Credit Facility bear interest at the following rates depending on the classification of the borrowing and provided further that at no time shall the interest rate be less than four percent (4.0 %) per annum:
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•The Base Rate (a rate per annum equal to the greatest of (a) the prime rate, (b) the Federal Funds Rate plus ½ of 1% and (c) Term Secured Overnight Financing Rate (“SOFR”) for a one month tenor plus 1.0 %, provided, that the Base Rate shall not at any time be less than 0%), plus an applicable margin of 2.25 % to 3.50 % depending on the type of borrowing and the average outstanding amount of loans and letters of credit under the Senior Credit Facility at the end of the prior fiscal quarter;
•The Term SOFR (a rate equal to the forward looking secured overnight financing rate published by the SOFR administrator on the website of the Federal Reserve Bank of New York or any successor source with either a comparable tenor (for any calculation with respect to a SOFR loan) or a one month tenor (for any calculation with respect to a Base Rate loan)), plus an applicable margin of 3.25 % to 4.50 % depending on the type of borrowing and the average outstanding amount of loans and letters of credit under the Senior Credit Facility at the end of the prior fiscal quarter; or
• The Daily Simple SOFR (a rate equal to the forward looking secured overnight financing rate published by the SOFR administrator on the website of the Federal Reserve Bank of New York or any successor source and applied on a daily basis by the Agent in accordance with rate recommendations for daily loans), plus an applicable margin of 3.25 % to 4.50 % depending on the type of borrowing and the average outstanding amount of loans and letters of credit under the Senior Credit Facility at the end of the prior fiscal quarter, plus a liquidity premium added by the Agent to each borrowing.
The Co-Borrowers are required to pay a non-utilization fee of 0.50 % quarterly in arrears on the unused portion of the Senior Credit Facility. In addition, the Co-Borrowers are subject to additional fees including an upfront fee, an annual administrative agency fee, an arrangement fee and letter of credit fees.
The Senior Credit Facility contains covenants that, among other things, require the maintenance of specified ratios or conditions including:
•Minimum Fixed Charge Coverage Ratio. The Company must maintain a minimum fixed charge coverage ratio of not less than 1.10 to 1.00. The Minimum Fixed Charge Coverage Ratio is defined as the ratio of (a) Adjusted EBITDA to (b) the sum of, among other things, consolidated interest expense, letter of credit fees, non-utilization fees, earn-out payments, certain restricted payments, taxes, and payments made on or after July 31, 2020 related to the settlement of civil and regulatory matters if not included in the calculation of Adjusted EBITDA. Our Minimum Fixed Charge Coverage Ratio as of December 31, 2025 was 1.42 to 1.00.
•Maximum Total Leverage Ratio. The Company must maintain a ratio of (x) the sum of all consolidated
indebtedness (excluding eligible subordinated debt and letter of credit obligations), plus (y) gross amounts reserved for civil and regulatory liabilities identified filings with the SEC, to Adjusted EBITDA of no more than 3.00 to 1.00. Our Maximum Total Leverage Ratio as of December 31, 2025 was 1.81 to 1.00.
As of December 31, 2025, the Company was in compliance with financial covenants under the Senior Credit Facility. The Company continues to manage the impact of commodity costs on financial covenant compliance. Maintaining compliance with our covenants under our Senior Credit Facility may impact our ability to pay dividends on our Series A Preferred Stock.
The Senior Credit Facility contains various customary affirmative covenants that require, among other things, the Company to maintain insurance, pay its obligations and comply with law. The Credit Agreement also contains customary negative covenants that limit the Company's ability to, among other things, incur certain additional indebtedness, grant certain liens, engage in certain asset dispositions, merge or consolidate, make certain payments, distributions and dividends, investments, acquisitions or loans, materially modify certain agreements, and enter into transactions with affiliates.
The Senior Credit Facility is secured by pledges of the equity of the portion of Spark HoldCo owned by the Company, the equity of Spark HoldCo’s subsidiaries, the Co-Borrowers’ present and future subsidiaries, and
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substantially all of the Co-Borrowers’ and their subsidiaries’ present and future property and assets, including intellectual property assets, accounts receivable, inventory and liquid investments, and control agreements relating to bank accounts.
The Company is entitled to pay cash dividends to the holders of its Series A Preferred Stock so long as: (a) no default exists or would result therefrom; (b) the Co-Borrowers are in pro forma compliance with all financial covenants before and after giving effect thereto; and (c) the outstanding amount of all loans and letters of credit do not exceed the borrowing base limits.
The Senior Credit Facility contains certain customary representations and warranties and events of default. Events of default include, among other things, payment defaults, breaches of representations and warranties, covenant defaults, cross-defaults and cross-acceleration to certain indebtedness, certain events of bankruptcy, certain events under ERISA, material judgments in excess of $5.0 million, certain events with respect to material contracts, and actual or asserted failure of any guaranty or security document supporting the Senior Credit Facility to be in full force and effect. A default will also occur if at any time W. Keith Maxwell III ceases to, directly or indirectly, beneficially own at least fifty-one percent (51 %) of the Company’s outstanding Class A common stock and Class B common stock on a combined basis, and a controlling percentage of the voting equity interest of the Company, and certain other changes in control. If such an event of default occurs, the lenders under the Senior Credit Facility would be entitled to take various actions, including the acceleration of amounts due under the facility and all actions permitted to be taken by a secured creditor.
Subordinated Debt Facility
The Company maintains an Amended and Restated Subordinated Promissory Note in the principal amount of up to $25.0 million (the “Subordinated Debt Facility”), by and among the Company, Spark HoldCo and Retailco. The Subordinated Debt Facility allows the Company to draw advances in increments of no less than $1.0 million per advance up to $25.0 million. In connection with entering into the First Amendment to the Senior Credit Facility, the Company entered into an amended and restated subordinated promissory note with Spark HoldCo and Retailco, which extends the maturity date of the note to January 31, 2028.
Borrowings are at the discretion of Retailco. Advances thereunder accrue interest at an annual rate equal to the prime rate as published by the Wall Street Journal plus two percent (2.0 %) from the date of the advance.
The Company has the right to capitalize interest payments under the Subordinated Debt Facility. The Subordinated Debt Facility is subordinated in certain respects to our Senior Credit Facility pursuant to a subordination agreement. The Company may pay interest and prepay principal on the Subordinated Debt Facility so long it is in compliance with the covenants under the Senior Credit Facility, is not in default under the Senior Credit Facility and has minimum availability of $5.0 million under the borrowing base under the Senior Credit Facility. Payment of principal and interest under the Subordinated Debt Facility is accelerated upon the occurrence of certain change of control or sale transactions.
As of December 31, 2025 and 2024, there were zero
10. Fair Value Measurements
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. Fair values are based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. This includes the credit standing of counterparties involved and the impact of credit enhancements.
We apply fair value measurements to our commodity derivative instruments based on the following fair value hierarchy, which prioritizes the inputs to the valuation techniques used to measure fair value into three broad levels:
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•Level 1—Quoted prices in active markets for identical assets and liabilities. Instruments categorized in Level 1 primarily consist of financial instruments such as exchange-traded derivative instruments.
•Level 2—Inputs other than quoted prices recorded in Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 primarily include non-exchange traded derivatives such as over-the-counter commodity forwards and swaps and options.
•Level 3—Unobservable inputs for the asset or liability, including situations where there is little, if any, observable market activity for the asset or liability. The Level 3 category includes estimated earnout obligations related to our acquisitions.
As the fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3), the Company maximizes the use of observable inputs and minimizes the use of unobservable inputs when measuring fair value. These levels can change over time. In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. In these cases, the lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
The following tables present assets and liabilities measured and recorded at fair value in our consolidated balance sheets on a recurring basis by and their level within the fair value hierarchy (in thousands):
| Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||
| December 31, 2025 | |||||||||||||||||||||||
| Non-trading commodity derivative assets | $ | $ | $ | $ | |||||||||||||||||||
| Trading commodity derivative assets | |||||||||||||||||||||||
| Total commodity derivative assets | $ | $ | $ | $ | |||||||||||||||||||
| Non-trading commodity derivative liabilities | $ | $ | ( | $ | $ | ( | |||||||||||||||||
| Trading commodity derivative liabilities | ( | ( | |||||||||||||||||||||
| $ | $ | ( | $ | $ | ( | ||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||
| December 31, 2024 | |||||||||||||||||||||||
| Non-trading commodity derivative assets | $ | $ | $ | $ | |||||||||||||||||||
| Trading commodity derivative assets | |||||||||||||||||||||||
| Total commodity derivative assets | $ | $ | $ | $ | |||||||||||||||||||
| Non-trading commodity derivative liabilities | $ | ( | $ | ( | $ | $ | ( | ||||||||||||||||
| Trading commodity derivative liabilities | ( | ( | |||||||||||||||||||||
| $ | ( | $ | ( | $ | $ | ( | |||||||||||||||||
We had no transfers of assets or liabilities between any of the above levels during the years ended December 31, 2025, 2024 and 2023.
Our derivative contracts include exchange-traded contracts valued utilizing readily available quoted market prices and non-exchange-traded contracts valued using market price quotations available through brokers or over-the-counter and on-line exchanges.
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In addition, in determining the fair value of our derivative contracts, we apply a credit risk valuation adjustment to reflect credit risk, which is calculated based on our or the counterparty’s historical credit risks. As of December 31, 2025 and 2024, the credit risk valuation adjustment was a reduction of derivative (liabilities)/assets, net of less than $(0.1 ) million and $0.1 million, respectively.
11. Income Taxes
We and our subsidiaries, CenStar and Verde Energy USA, Inc. ("Verde Corp") are each subject to U.S. federal income tax as corporations. CenStar and Verde Corp file consolidated tax returns in jurisdictions that allow combined reporting. Spark HoldCo and its subsidiaries, with the exception of CenStar and Verde Corp, are treated as flow-through entities for U.S. federal income tax purposes, and, as such, are generally not subject to U.S. federal income tax at the entity level. Rather, the tax liability with respect to their taxable income is passed through to their members or partners. Accordingly, we are subject to U.S. federal income taxation on our allocable share of Spark HoldCo's net U.S. taxable income.
In our financial statements, we report federal and state income taxes for our share of the partnership income attributable to our ownership in Spark HoldCo and for the income taxes attributable to CenStar and Verde Corp. Net income attributable to non-controlling interest includes the provision for income taxes related to CenStar and Verde Corp.
We account for income taxes using the asset and liability method. Deferred tax assets and liabilities are recognized for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and the tax bases of the assets and liabilities. We apply existing tax law and the tax rate that we expect to apply to taxable income in the years in which those differences are expected to be recovered or settled in calculating the deferred tax assets and liabilities. Effects of changes in tax rates on deferred tax assets and liabilities are recognized in income in the period of the tax rate enactment. A valuation allowance is recorded when it is not more likely than not that some or all of the benefit from the deferred tax asset will be realized.
On July 4th, 2025, the One Big Beautiful Bill Act (“OBBB”) was signed into law. The OBBB makes changes to U.S. tax law and includes provisions that beginning in January 2025, make permanent full expensing of tangible personal property, restores EBITDA-based calculations for purposes of the business interest deduction and allows for current expensing of R&D expenditures. We recorded the impact of OBBB which resulted in additional deductions related primarily to current expensing of R&D expenditures. OBBB had no material impact on total tax expense for the year.
ASU 2023-09 is effective for fiscal years beginning after December 15, 2024, including interim periods within those fiscal years, with early adoption permitted. The Company has elected to retrospectively adopt the guidance in ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures effective for the year ended December 31, 2025. As a result, amounts disclosed throughout this footnote have been revised for the years ended December 31, 2024 and December 31, 2023.
The provision for income taxes for the years ended December 31, 2025, 2024, and 2023 included the following components:
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| (in thousands) | 2025 | 2024 | 2023 | |||||||||||||||||
| Current: | ||||||||||||||||||||
| Federal | $ | $ | $ | |||||||||||||||||
| State | ||||||||||||||||||||
| Total Current | ||||||||||||||||||||
| Deferred: | ||||||||||||||||||||
| Federal | ||||||||||||||||||||
| State | ||||||||||||||||||||
| Total Deferred | ||||||||||||||||||||
| Provision for income taxes | $ | $ | $ | |||||||||||||||||
The effective income tax rate was 22.8 %, 21.0 %, and 29.9 % for the years ended December 31, 2025, 2024, and 2023, respectively. The following table reconciles the income tax benefit that would result from application of the statutory federal tax rate, 21
| (in thousands) | 2025 | 2024 | 2023 | |||||||||||||||||||||||
| Income before income tax expense | ||||||||||||||||||||||||||
| U.S. | $ | $ | $ | |||||||||||||||||||||||
| Non - U.S. | ||||||||||||||||||||||||||
| Total | $ | $ | $ | |||||||||||||||||||||||
| Tax Effect | Rate Effect | Tax Effect | Rate Effect | Tax Effect | Rate Effect | |||||||||||||||||||||
| Income tax at U.S. statutory rate | $ | $ | $ | |||||||||||||||||||||||
State and local income tax, net of federal income tax effect (*) | ||||||||||||||||||||||||||
| Nontaxable or nondeductible items | ||||||||||||||||||||||||||
| Guaranteed payments | ||||||||||||||||||||||||||
| Preferred dividend distribution | ||||||||||||||||||||||||||
| Stewardship costs | ( | ( | ( | ( | ( | ( | ||||||||||||||||||||
| Non-controlling interest (Income) | ( | ( | ( | ( | ( | ( | ||||||||||||||||||||
| Outside basis difference | ||||||||||||||||||||||||||
| Other Non-deductible/Non Taxable | ( | ( | ||||||||||||||||||||||||
| Other Adjustments | ( | ( | ||||||||||||||||||||||||
| Provision for income taxes | $ | $ | $ | |||||||||||||||||||||||
(*) State taxes in Pennsylvania and New Jersey made up the majority (greater than 50%) of the tax effect in this category for 2025 and 2023. State taxes in Pennsylvania, New Jersey, and Illinois made up the majority (greater than 50%) of the tax effect in this category for 2024.
Total income tax expense for the years ended December 31, 2025, 2024 and 2023 differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income primarily due to state income taxes and the impact of permanent differences between book and taxable income, most notably the income attributable to non-controlling interest, which gets taxed at the non-controlling interest partner level.
Taxes paid, net of refunds, were as follows:
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| Years Ended December 31, | |||||||||||||||||
| (in thousands) | 2025 | 2024 | 2023 | ||||||||||||||
| U.S Federal | $ | $ | $ | ||||||||||||||
| U.S States | |||||||||||||||||
| Pennsylvania | |||||||||||||||||
| Texas | ** | ** | |||||||||||||||
| New Jersey | ** | ||||||||||||||||
| Other States | |||||||||||||||||
| Total | $ | $ | $ | ||||||||||||||
| Total taxes paid | $ | $ | $ | ||||||||||||||
The components of our deferred tax assets as of December 31, 2025 and 2024 are as follows:
| (in thousands) | 2025 | 2024 | ||||||
| Deferred Tax Assets: | ||||||||
| Investment in Spark HoldCo | $ | $ | ||||||
| Derivative | ||||||||
| Fixed Assets and Intangibles | ||||||||
| Other | ||||||||
| Total deferred tax assets | $ | $ | ||||||
| Deferred Tax Liabilities: | ||||||||
| Derivative | ( | |||||||
| Other | ( | ( | ||||||
| Total deferred tax liabilities | $ | ( | $ | ( | ||||
| Total deferred tax assets/liabilities | $ | $ | ||||||
We periodically assess whether it is more likely than not that we will generate sufficient taxable income to realize our deferred income tax assets. In making this determination, we consider all available positive and negative evidence and makes certain assumptions. We consider, among other things, our deferred tax liabilities, the overall business environment, our historical earnings and losses, current industry trends, and our outlook for future years. We believe it is more likely than not that our deferred tax assets will be utilized, and accordingly have not recorded a valuation allowance on these assets.
The tax years 2020 through 2024 remain open to examination by the major taxing jurisdictions to which the Company is subject to income tax.
Accounting for uncertainty in income taxes prescribes a recognition threshold and measurement methodology for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. As of December 31, 2025 and 2024 there was no no no
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12. Commitments and Contingencies
From time to time, we may be involved in legal, tax, regulatory and other proceedings in the ordinary course of business. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.
Legal Proceedings
Below is a summary of our currently pending material legal proceedings. We are subject to lawsuits and claims arising in the ordinary course of our business. The following legal proceedings are in various stages and are subject to substantial uncertainties concerning the outcome of material factual and legal issues. Accordingly, unless otherwise specifically noted, we cannot currently predict the manner and timing of the resolutions of these legal proceedings or estimate a range of possible losses or a minimum loss that could result from an adverse verdict in a potential lawsuit. While the lawsuits and claims are asserted for amounts that may be material should an unfavorable outcome occur, management does not currently expect that any currently pending matters will have a material adverse effect on our financial position or results of operations.
Consumer Lawsuits
Similar to other energy service companies (“ESCOs”) operating in the industry, from time-to-time, the Company is subject to class action lawsuits in various jurisdictions where the Company sells natural gas and electricity.
On January 14, 2021, Glikin, et al. v. Major Energy Electric Services, LLC, a purported variable rate class action was filed by a Maryland customer in the United States District Court, Southern District of New York, attempting to represent a class of all Major Energy customers (including customers of companies Major Energy acts as a successor to) in the United States charged a variable rate for electricity or gas by Major Energy during the applicable statute of limitations period up to and including the date of judgment. The Company moved this case to the United States District Court for the District of Maryland (Case No. 1:21-cv-03251-MJM) and in December 2023 filed a motion to dismiss the lawsuit. In September 2024, the Court granted the Company’s motion that argued that Glikin had failed to exhaust her administrative remedies and that, if she wishes to proceed, she must first go to the Maryland Public Service Commission (“Maryland PSC”). On November 6, 2024, Glikin filed a complaint with the Maryland PSC. The Company responded to her complaint on February 28, 2025. On May 2025, the PSC ruled in favor of the Company, finding no fraudulent conduct. Plaintiff filed a motion to lift the federal court stay on June 16, 2025. The Company filed a motion to dismiss in federal court; the federal court heard oral arguments on October 7, 2025. The parties are waiting for the court’s decision on the motion to dismiss.
On March 24, 2024, SUS Cast Products, Inc., a large commercial customer, filed a case against Spark Energy Gas, LLC (09C01-2403-PL-000007) in Indiana Cass County Circuit Court alleging that Spark improperly billed Indiana Transportation Service (“ITS”) fixed capacity charges under their gas supply agreement regulated under the NIPSCO Choice Program. The Company followed the 2010 Indiana Utility Regulatory Commission order in charging the ITS costs to customer and does not believe this case will have a material impact on the Company.
From time-to-time the Company and its operating subsidiaries receive TCPA-based lawsuits, which are without merit as the Company has a robust telemarketing compliance program in place. Two cases are pending, at early stages of litigation: (1) Clark v. Via Renewables, Inc. (filed January 30, 2024), and (2) Grant v. Via Renewables, Inc. (November 15, 2024). The Company is vigorously defending these claims.
Corporate Matter Lawsuits
The Company may from time to time be subject to legal proceedings that arise in the ordinary course of business. Although there can be no assurance in this regard, the Company does not expect any of those legal proceedings to have a material adverse effect on the Company’s results of operations, cash flows or financial condition.
On July 19, 2024, Joshua Amburgey, a purported stockholder of the Company at the time of the Merger, filed a verified class action complaint in the Delaware Court of Chancery (C.A. No. 2024-0762-KSJM) alleging that the
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Company’s directors and controlling stockholder breached their fiduciary duties in connection with the Merger. On July 25, 2024, Bruce Taylor, another purported stockholder, filed a related class action (C.A. No. 2024-0794) asserting fiduciary-duty and disclosure claims concerning the proxy statement for the Merger. A prior Section 220 books-and-records action filed by Michael Stutzman (C.A. No. 2024-0545-LM) was subsequently expanded to assert similar claims.
The Delaware Court of Chancery has consolidated these actions under the caption In re Via Renewables, Inc. Merger Litigation (C.A. No. 2024-0762-KSJM), and appointed lead counsel and a lead plaintiff. The consolidated action remains pending before Vice Chancellor McCormick. Defendants have filed a motion to dismiss this matter which is pending before the Delaware Chancery Court. Oral arguments on such motion are scheduled for April/May 2026. Related to this action, on January 15, 2026, Jones Walker, LLP filed an action in Louisiana to recover certain legal fees that have been disputed by the Company.
Regulatory Matters
Many state regulators have increased scrutiny on retail energy providers, across all industry providers. We are subject to regular regulatory inquiries, license renewal reviews, and preliminary investigations in the ordinary course of our business. Below is a summary of our currently pending material state regulatory matters. The following state regulatory matters are in various stages and are subject to substantial uncertainties concerning the outcome of material factual and legal issues. Accordingly, we cannot currently predict the manner and timing of the resolution of these state regulatory matters or estimate a range of possible losses or a minimum loss that could result from an adverse action. Management does not currently expect that any currently pending state regulatory matters will have a material adverse effect on our financial position or results of operations.
Illinois. On July 26, 2023, Spark Energy, LLC received a demand letter from a law firm representing the Office of the Illinois Attorney General alleging that Spark Energy, LLC’s marketing and sales practices may have not been in compliance with Illinois law. The letter offered, in the interest of efficiency and minimizing litigation costs, a settlement demand to resolve the matter. The Company has agreed to engage in mediation with the law firm to try to resolve this matter. The Company met for an all-day mediation in August 2024 and several other virtual settlement discussions. The settlement discussions were unsuccessful, and the Attorney General commenced a lawsuit in Illinois against Spark Energy, LLC and Spark Energy Gas, LCC on January 16, 2025 (“IL AG State Action”). Spark filed a motion to dismiss (“MTD”) the IL AG State Action and simultaneously, proactively filed a federal action raising constitutional issues (“Federal Action”). The IL AG and the Company have exchanged responses regarding the MTD in both cases. All actions are in the early stages, and the parties have resumed settlement negotiations.
New York. Verde Energy USA New York, LLC (“Verde New York”) is the subject of a proceeding before the New York State Public Service Commission (the “NYPSC”) captioned “Proceeding on Motion of the Commission to Seek Consequences Against Verde Energy USA New York, LLC for Violations of the Uniform Business Practices,” Case No. 25-E-0763 (the “Proceeding”). On January 26, 2026, the NYPSC issued an Order Instituting Proceeding and to Show Cause. The Order references allegations by the NYPSC staff that Verde New York violated the NYPSC’s Uniform Business Practices (“UBP”), including with respect to customer enrollment practices and the maintenance and/or production of verifiable proof of customer authorization and related enrollment records, and related compliance with staff information requests. The Order directs Verde New York to show cause within 30 days why the NYPSC should not impose consequences, which may include revocation of Verde New York’s eligibility to operate as an energy services company in New York and/or other remedies available under the UBP. Verde New York is responding in the Proceeding. The matter is at an early stage, and the Company cannot predict the outcome or reasonably estimate the amount or range of potential loss, if any. An adverse outcome could result in operational restrictions in New York, monetary consequences, customer remediation.
Ohio. On August 14, 2024, the Public Utility Commission of Ohio (“PUCO”) sent Major Energy a notice of probable non-compliance regarding approximately fifty-five consumer complaints during the time period January 3, 2023 through April 12, 2024. The Company has worked cooperatively with PUCO and the Ohio Office of Consumer Counsel to resolve this matter, and believes this matter will not have a material impact on the Company. A proposed settlement has been submitted to the PUCO for approval. On December 4, 2025, a settlement was approved by PUCO which directed certain refunds to customers and a donation to an Ohio charity which provides
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payment assistance for energy costs for certain low-income Ohio residents. These payments have all been processed.
State Legislative and Regulatory Developments
From time to time, state legislatures and regulatory commissions propose or adopt new measures that affect the retail energy industry, including changes to licensing, consumer protection, renewable energy content, and market access. The Company actively monitors these developments and participates, either directly or through industry trade associations, in stakeholder discussions to ensure that its perspective and the broader industry position are represented. The Company also attends public meetings and technical sessions to stay informed of emerging policy directions and to provide constructive input on behalf of retail suppliers. For example, in Maryland, Senate Bill 1 imposed new restrictions that effectively limited residential energy choice, while in Massachusetts, the Department of Public Utilities reopened Docket 19-07 to consider changes to green product standards and sales channels. The Company believes that ongoing engagement and transparency with state policymakers and regulators are essential to maintaining a stable and predictable regulatory environment and mitigating potential risks to its operations.
Indirect Tax Audits
As of the date of filing these consolidated financial statements, we are not subject to any indirect tax audits and have not identified any matters that would give rise to additional indirect tax liabilities.
As of December 31, 2025 and December 31, 2024 we had accrued $10.5 million and $11.9 million, respectively, related to litigation and regulatory matters and zero and $0.8 million, respectively, related to indirect tax audits. The accrual for litigation and regulatory matters, and indirect tax audit is recorded in accrued liabilities on the balance sheet. The outcome of each of these may result in additional expense.
13. Transactions with Affiliates
Transactions with Affiliates
We enter into transactions with and pay certain costs on behalf of affiliates that are commonly controlled in order to reduce risk, reduce administrative expense, create economies of scale, create strategic alliances and supply goods and services to these related parties. We also sell and purchase natural gas and electricity with affiliates. We present receivables and payables with the same affiliate on a net basis in the consolidated balance sheets as all affiliate activity is with parties under common control. Affiliated transactions include certain services to the affiliated companies associated with employee benefits provided through our benefit plans, insurance plans, leased office space, administrative salaries, due diligence work, recurring management consulting, and accounting, tax, legal, or technology services. Amounts billed are based on the services provided, departmental usage, or headcount, which are considered reasonable by management. As such, the accompanying consolidated financial statements include costs that have been incurred by us and then directly billed or allocated to affiliates, as well as costs that have been incurred by our affiliates and then directly billed or allocated to us, and are recorded net in general and administrative expense on the consolidated statements of operations with a corresponding accounts receivable—affiliates or accounts payable—affiliates, respectively, recorded in the consolidated balance sheets. Transactions with affiliates for sales or purchases of natural gas and electricity, are recorded in retail cost of revenues, and net asset optimization revenues in the consolidated statements of operations with a corresponding accounts receivable—affiliate or accounts payable—affiliate recorded in the consolidated balance sheets.
The following tables presents asset and liability balances with affiliates (in thousands):
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December 31, 2025 | December 31, 2024 | ||||||||||
| Assets | |||||||||||
| Accounts Receivable - affiliates | $ | $ | |||||||||
Total Assets - affiliates | $ | $ | |||||||||
| December 31, 2025 | December 31, 2024 | ||||||||||
| Liabilities | |||||||||||
| Accounts Payable - affiliates | $ | $ | |||||||||
Subordinated Debt - affiliates (1) | |||||||||||
Total Liabilities - affiliates | $ | $ | |||||||||
The following table presents revenues and cost of revenues recorded in net asset optimization revenue associated with affiliates for the periods indicated (in thousands):
| December 31, 2025 | December 31, 2024 | December 31, 2023 | |||||||||||||||
| Revenue NAO - affiliates | $ | $ | $ | ||||||||||||||
| Less: Cost of Revenue NAO - affiliates | |||||||||||||||||
Net NAO - affiliates | $ | $ | $ | ||||||||||||||
The Company's retail cost of revenue include gains/(losses) related to derivative instruments transactions with affiliates. For the years ended December 31, 2025, 2024 and 2023, respectively, we recognized gain/(loss) of $(0.2 ) million, $1.1 million and $0.5 million and in retail cost of revenue related to derivative instruments settlements.
Cost Allocations
Where costs incurred on behalf of the affiliate or us cannot be determined by specific identification for direct billing, the costs are allocated to the affiliated entities or us based on estimates of percentage of departmental usage, wages or headcount. The total net amount direct billed and allocated to/(from) affiliates was $(5.9 ) million, $(4.3 ) million and $1.5 million for the years ended December 31, 2025, 2024 and 2023, respectively. The Company would have incurred incremental costs of $1.8 million, $1.5 million and $1.5 million for the years ended December 31, 2025, 2024 and 2023, respectively, operating on a stand-alone basis.
Distributions to and Contributions from Affiliates
During the years ended December 31, 2025, 2024 and 2023, we made distributions to affiliates of Mr. Maxwell of zero , zero and $3.6 million, respectively, for payments of quarterly distributions on their respective Spark HoldCo units. During the years ended December 31, 2025, 2024 and 2023, we also made distributions related to these affiliates for gross-up distributions of $5.5 million, $6.6 million, and $0.7 million, respectively, in connection with distributions made between Spark HoldCo and Via Renewables, Inc. for payment of income taxes incurred by us. Of the $5.5 million gross-up tax distribution for the year ended December 31, 2025, $5.2 million was distributed to affiliates and $0.3 million was distributed to the states on behalf of the affiliates.
On June 13, 2024, we consummated the Merger, following which Mr. Maxwell and his affiliates became the owners of all of the issued and outstanding shares of the Company's Class A common stock and Class B common stock.
Spark HoldCo Distribution
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During the year ended December 31, 2025 and 2024, respectively, Spark HoldCo distributed $15.2 million and $5.0 million in cash to the non-controlling interest holders. Refer to Note 4 – Equity for details of these transactions, including the amounts and ownership changes.
Membership Interest Purchase Agreement with NGE Holdco, LLC and Spark Holdco, LLC
On May 23, 2025, we entered into an agreement to acquire 100 % of the membership interests in NGE Texas, LLC (“NGE Texas”) for a nominal purchase price of $1 and a working capital payment of approximately $1.0 million, consisting entirely of restricted cash in the form of a Letter of Credit and ERCOT collateral. The primary purpose of the transaction was to obtain NGE Texas’s existing Texas retail electricity license, which is required to operate as a retail electricity provider in the state of Texas.
Subordinated Debt Facility
The Company maintains an Amended and Restated Subordinated Promissory Note in the principal amount of up to $25.0 million (the “Subordinated Debt Facility”), by and among the Company, Spark HoldCo and Retailco. The Subordinated Debt Facility allows the Company to draw advances in increments of no less than $1.0 million per advance up to $25.0 million through January 31, 2028. In connection with entering into the First Amendment to the Credit Agreement, the Company entered into an amended and restated subordinated promissory note with Spark HoldCo and Retailco, which extends the maturity date of the note to January 31, 2028. 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.
As of December 31, 2025 and 2024, there were zero
14. Segment Reporting
Our reportable business segments are retail electricity and retail natural gas. The retail electricity segment consists of electricity sales and transmission to residential and commercial customers. The retail natural gas segment consists of natural gas sales to, and natural gas transportation and distribution for, residential and commercial customers. The Chief Executive Officer, who is also the Chief Operating Decision Maker (“CODM”), determines the reportable business segments by considering the strategic operating units used to make financial decisions, allocate resources and assess performance of our business.
For the years ended December 31, 2025, 2024 and 2023, we recorded asset optimization revenues of $37.5 million, $23.0 million and $24.6 million and asset optimization cost of revenues of $41.3 million, $25.3 million and $31.9 million, respectively, which are presented on a net basis in asset optimization revenues.
The primary metric used by the CODM in managing the Company, assessing segment performance, and allocating resources is retail gross margin. We use retail gross margin to assess the performance of our operating segments. We define retail gross margin as gross profit less (i) net asset optimization (expenses) revenues, (ii) net (losses) gains on non-trading derivative instruments, (iii) net current period cash settlements on non-trading derivative instruments, and (iv) gains (losses) from non-recurring events (including non-recurring market volatility).
We deduct net gains (losses) on non-trading derivative instruments, excluding current period cash settlements, from the retail gross margin calculation in order to remove the non-cash impact of net gains and losses on these derivative instruments. We deduct net gains (losses) from non-recurring events (including non-recurring market volatility) to ensure retail gross margin reflects operating performance that is not distorted by non-recurring events or extreme market volatility. Retail gross margin should not be considered an alternative to, or more meaningful than, operating income (loss), as determined in accordance with GAAP.
The Company’s CODM reviews significant expenses on a consolidated level.
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Financial data for business segments are as follows (in thousands):
| Year Ended December 31, 2025 | |||||||||||||||||||||||||||||
Retail Electricity (1) | Retail Natural Gas | Corporate and Other | Eliminations | Consolidated | |||||||||||||||||||||||||
| Total Revenues | $ | $ | $ | ( | $ | $ | |||||||||||||||||||||||
| Retail cost of revenues | |||||||||||||||||||||||||||||
| Less: | |||||||||||||||||||||||||||||
Net asset optimization expense (2) | ( | ( | |||||||||||||||||||||||||||
| ( | ( | ( | |||||||||||||||||||||||||||
| Current period settlements on non-trading derivatives | ( | ( | |||||||||||||||||||||||||||
| Retail gross margin | $ | $ | $ | $ | $ | ||||||||||||||||||||||||
Add: Reconciling items (3) | ( | ||||||||||||||||||||||||||||
| Gross Profit | $ | ||||||||||||||||||||||||||||
Total Assets | $ | $ | $ | $ | ( | $ | |||||||||||||||||||||||
| Goodwill | $ | $ | $ | $ | $ | ||||||||||||||||||||||||
(1) Retail Electricity includes related services.
(2) For the year ended December 31, 2025, we recorded asset optimization revenues of $37.5 million and asset optimization cost of revenues of $41.3 million, which are presented on a net basis in asset optimization revenues.
(3) Reconciling item includes net asset optimization expenses, net (loss) and gain on non-trading derivative instruments and current period settlements on non- trading activities.
| Year Ended December 31, 2024 | |||||||||||||||||||||||||||||
Retail Electricity (1) | Retail Natural Gas | Corporate and Other | Eliminations | Consolidated | |||||||||||||||||||||||||
| Total Revenues | $ | $ | $ | ( | $ | $ | |||||||||||||||||||||||
| Retail cost of revenues | |||||||||||||||||||||||||||||
| Less: | |||||||||||||||||||||||||||||
Net asset optimization expense (2) | ( | ( | |||||||||||||||||||||||||||
| ( | ( | ||||||||||||||||||||||||||||
| Current period settlements on non-trading derivatives | |||||||||||||||||||||||||||||
| Retail gross margin | $ | $ | $ | $ | $ | ||||||||||||||||||||||||
Add: Reconciling items (3) | |||||||||||||||||||||||||||||
| Gross Profit | $ | ||||||||||||||||||||||||||||
| Total Assets | $ | $ | $ | $ | ( | $ | |||||||||||||||||||||||
| Goodwill | $ | $ | $ | $ | $ | ||||||||||||||||||||||||
(1) Retail Electricity includes related services.
(2) For the year ended December 31, 2024, we recorded asset optimization revenues of $23.0 million and asset optimization cost of revenues of $$25.3 million, which are presented on a net basis in asset optimization revenues.
(3) Reconciling item includes net asset optimization expenses, net (loss) and gain on non-trading derivative instruments and current period settlements on non- trading activities.
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| Year Ended December 31, 2023 | |||||||||||||||||||||||||||||
Retail Electricity (1) | Retail Natural Gas | Corporate and Other | Eliminations | Consolidated | |||||||||||||||||||||||||
| Total Revenues | $ | $ | $ | ( | $ | $ | |||||||||||||||||||||||
| Retail cost of revenues | |||||||||||||||||||||||||||||
| Less: | |||||||||||||||||||||||||||||
Net asset optimization expense (2) | ( | ( | |||||||||||||||||||||||||||
| ( | ( | ( | |||||||||||||||||||||||||||
| Current period settlements on non-trading derivatives | |||||||||||||||||||||||||||||
| Retail gross margin | $ | $ | $ | $ | $ | ||||||||||||||||||||||||
Add: Reconciling items (3) | ( | ||||||||||||||||||||||||||||
| Gross Profit | $ | ||||||||||||||||||||||||||||
| Total Assets | $ | $ | $ | $ | ( | $ | |||||||||||||||||||||||
| Goodwill | $ | $ | $ | $ | $ | ||||||||||||||||||||||||
(1) Retail Electricity includes related services.
(2) For the year ended December 31, 2023 we recorded asset optimization revenues of $24.6 million and asset optimization cost of revenues of $31.9 million, which are presented on a net basis in asset optimization revenues.
(3) Reconciling item includes net asset optimization expenses, net (loss) and gain on non-trading derivative instruments and current period settlements on non- trading activities.
Significant Customers
For each of the years ended December 31, 2025, 2024 and 2023, we did not have any significant customers that individually accounted for more than 10% of our consolidated retail revenue.
Significant Suppliers
15. Customer Acquisitions
Acquisition of Customer Books
In April 2024, we entered into an asset purchase agreement to acquire up to approximately 12,556 RCEs for a cash purchase price of up to a maximum of $2.3 million. These customers began transferring in June of 2024, and were in our existing markets. During the twelve months ended December 31, 2024, approximately 9,300 RCEs were transferred. As part of the acquisition, we funded an escrow account, the balance of which is reflected as restricted cash in our consolidated balance sheet. As we acquired customers, we made payments to the sellers from the escrow account. As of December 31, 2024, we completed this acquisition. The balance in the escrow account was $0.4 million as of December 31, 2024, which will be returned to the Company in the first quarter of 2025. As of December 31, 2025, the balance in the escrow account was zero .
In October 2024, we entered into two asset purchase agreements to acquire up to 100,600 RCEs for a cash purchase price of up to a maximum $16.9 million paid in cash or funded into escrow accounts. These customers are located in our existing markets and began transferring in December of 2024 and January of 2025. As we acquired customers, we made payments to the sellers from the escrow accounts. Funds from the escrow account were released to the
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sellers as acquired customers transferred from the sellers to the Company in accordance with the asset purchase agreement, and any unallocated balance were returned to the Company once the acquisitions were complete. As of December 31, 2025, we've completed this acquisition and approximately 99,000 RCEs were transferred. As of December 31, 2025, and 2024, the balance in the escrow accounts was $1.0 million and $15.5 million.
In April and May 2025, we entered into two asset purchase agreements to acquire up to 16,800 RCEs for a cash purchase price of up to a maximum $1.8 million paid in cash or funded into escrow accounts. These gas customers are located in our existing markets and began transferring in May 2025 and June 2025. As we acquired customers under these acquisition agreements, we made payments to the sellers from the escrow accounts. Funds from the escrow account were released to the sellers as acquired customers transferred from the sellers to the Company in accordance with the asset purchase agreement, and any unallocated balance was returned to the Company once the acquisitions were complete. As of December 31, 2025, we've completed this acquisition and approximately 17,000 RCEs were transferred. As of December 31, 2025, the balance is the escrow accounts was $0.1 million.
In October 2025, we entered into an asset purchase agreement to acquire up to 3,300 RCEs for a cash purchase price of up to a maximum $0.5 million paid in cash. These electricity customers were located in our existing market and transferred from the sellers to the Company in the fourth quarter of 2025.
16. Subsequent Events
Declaration of Dividends
On January 15, 2026, we declared a quarterly cash dividend in the amount of $0.65699 per share to holders of record of the Series A Preferred Stock on April 1, 2026. The dividend will be paid on April 15, 2026.
Partial Redemption of Series A Preferred Stock
On January 16, 2026, we announced the redemption of 232,708 shares of our Series A Preferred Stock for a redemption price of $25.00 per share, plus an amount equal to all accumulated and unpaid dividends thereon to, but not including, the redemption date of February 17, 2026. We paid $5.9 million on the redemption date.
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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
Our management, with the participation of our Chief Executive Officer and our Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Annual Report. The term “disclosure controls and procedures,” as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the company’s management, including its principal executive and principal financial officers or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving their objectives, and management necessarily applies its judgment in evaluating the cost benefit relationship of possible controls and procedures. Based on this evaluation, management concluded that our disclosure controls and procedures were effective as of December 31, 2025.
Management's Annual Report on Internal Control Over Financial Reporting
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
Changes in Internal Control over Financial Reporting
There was no change in our internal control over financial reporting identified in connection with the evaluation required by Rule 13a-15(d) and 15d-15(d) of the Exchange Act that occurred during the three months ended December 31, 2025 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Please see "Management's Report on Internal Control over Financial Reporting" under Item 8 of this Annual Report for a description of remediation measures we intend to take to address the material weakness identified in our internal control over financial reporting.
Item 9B. Other Information
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
Not Applicable.
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PART III.
Information as to Item 10 will be disclosed in a Form 10-K/A, which will be filed no later than 120 days after December 31, 2025.
Item 11. Executive Compensation
Information as to Item 11 will be disclosed in a Form 10-K/A, which will be filed no later than 120 days after December 31, 2025.
Item 12. Security Ownership of Certain Beneficial Owners and Management, and Related Stockholder Matters
Except as provided below, information as to Item 12 will be disclosed in a Form 10-K/A, which will be filed no later than 120 days after December 31, 2025.
Equity Compensation Plan Information
Not applicable.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Information as to Item 13 will be disclosed in a Form 10-K/A, which will be filed no later than 120 days after December 31, 2025.
Item 14. Principal Accounting Fees and Services
Information as to Item 14 will be disclosed in a Form 10-K/A, which will be filed no later than 120 days after December 31, 2025.
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PART IV.
Item 15. Exhibits, Financial Statement Schedules
(1) The consolidated financial statements of Via Renewables, Inc. and its subsidiaries and the report of the independent registered public accounting firm are included in Part II, Item 8 of this Annual Report.
(2) All schedules have been omitted because they are not required under the related instructions, are not applicable or the information is presented in the consolidated financial statements or related notes.
(3) The exhibits listed on the accompanying Exhibit Index are filed as part of, or incorporated by reference into, this Annual Report.
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| INDEX TO EXHIBITS | ||||||||||||||||||||
| Incorporated by Reference | ||||||||||||||||||||
| Exhibit | Exhibit Description | Form | Exhibit Number | Filing Date | SEC File No. | |||||||||||||||
| 2.1 | 8-K | 2.1 | 1/2/2024 | 001-36559 | ||||||||||||||||
| 2.2 | 8-K | 2.1 | 10/25/2024 | 001-36559 | ||||||||||||||||
| 3.1 | 10-K | 3.1 | 2/29/2024 | 001-36559 | ||||||||||||||||
| 3.2 | 8-K | 3.2 | 8/9/2021 | 001-36559 | ||||||||||||||||
| 3.3 | 8-A | 5 | 3/14/2017 | 001-36559 | ||||||||||||||||
| 4.1 | 10-Q | 4.1 | 8/1/2024 | 001-36559 | ||||||||||||||||
| 10.1 | 8-K | 10.1 | 7/7/2022 | 001-36559 | ||||||||||||||||
| 10.2 | 8-K | 10.1 | 6/28/2024 | 001-36559 | ||||||||||||||||
| 10.3 | 8-K | 10.2 | 8/4/2014 | 001-36559 | ||||||||||||||||
| 10.4 | 8-K | 10.1 | 7/17/2019 | 001-36559 | ||||||||||||||||
| 10.5 | 10-Q | 10.1 | 5/8/2017 | 001-36559 | ||||||||||||||||
| 10.6 | 8-K | 10.1 | 1/26/2018 | 001-36559 | ||||||||||||||||
| 10.7 | 8-K | 10.1 | 4/3/2020 | 001-36559 | ||||||||||||||||
| 10.8 | 8-K | 10.2 | 6/28/2024 | 001-36559 | ||||||||||||||||
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| 10.9† | 8-K | 10.5 | 8/4/2014 | 001-36559 | ||||||||||||||||
| 10.10† | 8-K | 10.1 | 8/30/2019 | 001-36559 | ||||||||||||||||
| 10.11† | 8-K | 10.1 | 3/19/2020 | 001-36559 | ||||||||||||||||
| 10.12† | 10-Q | 10.5 | 11/4/2021 | 001-36559 | ||||||||||||||||
| 10.13† | 8-K | 10.1 | 11/8/2021 | 001-36559 | ||||||||||||||||
| 10.14† | 10-K | 10.47 | 3/4/2021 | 001-36559 | ||||||||||||||||
| 10.15† | 10-Q | 10.3 | 11/4/2021 | 001-36559 | ||||||||||||||||
| 10.16 | 10-Q | 10.1 | 5/4/2023 | 001-36559 | ||||||||||||||||
| 10.17 | 8-K | 10.1 | 7/6/2023 | 001-36559 | ||||||||||||||||
| 10.18 | 8-K | 6/6/2025 | 001-36559 | |||||||||||||||||
| 10.19† | 8-K | 10.1 | 12/5/2025 | 001-36559 | ||||||||||||||||
| 21.1* | ||||||||||||||||||||
| 31.1* | ||||||||||||||||||||
| 31.2* | ||||||||||||||||||||
| 32** | ||||||||||||||||||||
| 101.INS* | XBRL Instance Document. | |||||||||||||||||||
| 101.SCH* | XBRL Schema Document. | |||||||||||||||||||
| 101.CAL* | XBRL Calculation Document. | |||||||||||||||||||
| 101.LAB* | XBRL Labels Linkbase Document. | |||||||||||||||||||
| 101.PRE* | XBRL Presentation Linkbase Document. | |||||||||||||||||||
| 101.DEF* | XBRL Definition Linkbase Document. | |||||||||||||||||||
| 104* | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101.INS) | |||||||||||||||||||
* Filed herewith
** Furnished herewith
† Compensatory plan or arrangement
+ Portions of this exhibit have been omitted and filed separately with the SEC pursuant to an order granting confidential treatment.
# The registrant agrees to furnish supplementally a copy of any omitted schedule to the Commission upon request.
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Item 16. Form 10-K Summary
None.
SIGNATURES
Pursuant to the requirements of section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| March 5, 2026 | Via Renewables, Inc. | ||||||||||||||||
| By: | /s/ Mike Barajas | ||||||||||||||||
| Mike Barajas | |||||||||||||||||
| Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer) | |||||||||||||||||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant in the capacities indicated on March 5, 2026: | |||||||||||||||||
| By: | /s/ W. Keith Maxwell III | ||||||||||||||||
| W. Keith Maxwell III | |||||||||||||||||
Chairman of the Board of Directors and Chief Executive Officer (Principal Executive Officer) | |||||||||||||||||
| /s/ Mike Barajas | |||||||||||||||||
| Mike Barajas | |||||||||||||||||
| Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer) | |||||||||||||||||
| /s/ Stephen Kennedy | |||||||||||||||||
| Stephen Kennedy | |||||||||||||||||
| Director | |||||||||||||||||
| /s/ Amanda Bush | |||||||||||||||||
| Amanda Bush | |||||||||||||||||
| Director | |||||||||||||||||
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