Please see Item 9B. “Other Information” and Note 4 "Acquisitions"“Item 1A — Risk Factors” in the notes to our consolidated financial statements for a more detailed description of these acquisitions, including the purchase price, the source of funds and financing arrangements with our Founder and/or NG&E. Please see “Risk Factors"this Annual Report for a discussion of risks related to our acquisition strategy and ability to finance such transactions.

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 is in the interest of the Company.customers.

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

In most markets, we hedge our electricity exposure with financial products and then purchase the physical power directly from the ISO for delivery. Alternatively, we may use physical products to hedge our electricity exposure rather than buying physical electricity in the day-ahead market from the ISO. During the year ended December 31, 2019,2022, we transacted physical and financial settlementsettlements of electricity with approximately 13nine 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. We attempt to estimate such amounts, but they are difficult to estimate because they are charged in arrears by the ISOs and are subject to fluctuations based on weather and other market

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 continual 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, 2019,2022, we transacted physical and financial settlements of natural gas with approximately 7081 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, within which we are ableallow 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.

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

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

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

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. A discussion of theThe various risks we face in our risk management activities is as follows:are discussed below.

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.

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

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.

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

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 continually 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, 2019,2022, approximately 67%59% 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 0.8%0.9% 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.service to the extent the ability to terminate service has not been limited as a result of regulatory orders. Under these service programs, we are exposed to credit risk related to payment for services rendered during the time between when the customer is transferred to us by the local regulated utility and the time we return the customer to the utility for termination of service, which is generally one to two billing periods. We may also realize a loss on fixed-price customers in this scenario due to the fact that we will have already fully hedged the customer’s expected commodity usage for the life of the contract.

In non-POR markets (and in select POR markets where we may choose to direct bill our customers), we manage commercial customer credit risk through a formal credit review and manage residential customer credit risk through a varietyin the case of procedures, which may includecommercial customers, and credit score screening, deposits and disconnection for non-payment.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. We

We assess the adequacy of the allowance for doubtful accounts 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, 20192022 was $13.5$6.9 million, or 1.7%1.5% 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, 2019.2022.

We do not have high concentrations of sales volumes to individual customers. For the year ended December 31, 2019,2022, our largest customer accounted for less than 1% of total retail energy sales volume.sales.

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, 2019,2022, approximately $0.1$1.9 million of our total exposure of $3.1$2.8 million was either with a non-investment grade counterparty or otherwise not secured with collateral or a guarantee.

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. As of December 31, 2019,During 2022, we havedid not experiencedexperience any material loss related to cyber-attacks or other information security breaches.

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

We may engage in additional transactions with NG&E in the future and expect that any such transactions would be funded by a combination of cash, subordinated debt, or the issuance of Class A or Class B common stock. 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 our Founder will be subject to negotiation and approval by a special committee of our Board of Directors consisting solely of independent directors. Please see “Risk“Item 1A — Risk Factors” in this Annual Report for risks related to acquisitions and transactions with our affiliates.

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,

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.

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 supplies.product deliveries. This timing difference affects our cash flows, especially during peak cycles in the winter and summer months.

Natural gas accounted for approximately 15%24% of our retail revenues for the year ended December 31, 2019,2022, which exposes us to a high degree of seasonality in our cash flows and income earned throughout the year as a result of the high concentration of heating load in the winter months. We utilize a considerable amount of cash from operations and borrowing capacity to fund working capital, which includes inventory purchases from April through October each year. We sell our natural gas inventory during the months of November through March of each year. We expect that the significant seasonality impacts to our cash flows and income will continue in future periods.

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

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“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.

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

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.

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

Our corporate headquarters is located in Houston, Texas, and we also maintain an office in Orangeburg, New York.Texas.

As of December 31, 2022, we operated in 102 utility service territories across 19 states and the prices at which we can acquireDistrict of Columbia and had approximately 331,000 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 fifteen states (Arizona, California, Colorado, Connecticut, Florida, Illinois, Indiana, Maryland, Massachusetts, Michigan, Nevada, New Jersey, New York, Ohio and Pennsylvania) and electricity customers in twelve states (Connecticut, Delaware, Illinois, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Ohio, Pennsylvania and Texas) and the commodities we resell. The prevailing market prices forDistrict of Columbia using seven brands (Electricity Maine, Electricity N.H., Major Energy, Provider Power Mass, Respond Power, Spark Energy, and Verde Energy).

We offer a variety of fixed-price and variable-price service options to our natural gas and electricity have historically, and may continue to fluctuate substantially over relatively short periods of time. Changes in market prices forcustomers. 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 result from manyor may not provide for a monthly service fee and/or a termination fee, depending on the market and customer type. Our variable-price service options carry a month-to-month term and are priced based on our forecasts of underlying commodity prices and other market and business factors, that are outsideincluding 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 control, including:RCEs were as follows as of December 31, 2022:

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.

In most markets, we hedge our electricity exposure with financial products and then purchase the physical power directly from the ISO for delivery. Alternatively, we may use physical products to hedge our electricity exposure rather than buying physical electricity in the day-ahead market from the ISO. During the year ended December 31, 2022, we transacted physical and financial settlements of electricity with approximately nine suppliers.

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 beeconomically feasible to do so.

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 pass along changescapture 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.

We operate under a set of corporate risk policies and procedures relating to the pricespurchase and sale of electricity and natural gas, general risk management and credit and collections functions. Our in-house energy supply team is

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 payhave followed these policies. The risk committee also seeks to acquire commoditiesensure 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.

Because our contracts require that we deliver full natural gas or electricity requirements to our customers and such pricing fluctuationsbecause our customers’ usage can attract consumer class actions as well as state and federal regulatory actions.

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.

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 basisthe risk that prices may differ between the Chicago basisdelivery point and the individual utility system delivery points. These differences can be significant from time to time, particularly during extreme, unforecasted cold weather conditions. Similarly, in certain of our electricity markets, customers pay the load zone price for electricity, so if we purchase supply to be delivered at a hub, we may have basis risk between the hub and the load zone electricity prices due to local congestion that is not reflected in the hub price. We attempt to hedge basis risk where possible, but hedging instruments are sometimesoccasionally not economically feasible or available in the smaller quantities that we require.

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 useidentify 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 establishingeach of the markets, we monitor our hedges may reducereceivable aging, bad debt forecasts and actual bad debt expenses and adjust as necessary.

In territories where POR programs have been established, the effectivenesslocal 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 hedging instruments. Considerationscredit risk being linked to the applicable utility and not to our end-use customers in these territories. For the year ended December 31, 2022, approximately 59% 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 0.9% of total revenues for customer credit risk. In certain of the POR markets in which we operate, the utilities limit their collections exposure by retaining the ability to transfer a delinquent account back to us for collection when collections are past due for a specified period. If our subsequent collection efforts are unsuccessful, we return the account to the local regulated utility for termination of service to the extent the ability to terminate service has not been limited as a result of regulatory orders. Under these service programs, we are exposed to credit risk related to payment for services rendered during the time between when the customer is transferred to us by the local regulated utility and the time we return the customer to the utility for termination of service, which is generally one to two billing periods. We may also realize a loss on fixed-price customers in this scenario due to the fact that we will have already fully hedged the customer’s expected commodity usage for the life of the contract.

In non-POR markets (and in POR markets where we may choose to direct bill our customers), we manage customer credit risk through formal credit review in the case of commercial customers, and credit score screening, deposits and disconnection for non-payment, in the case of residential customers. Economic conditions may affect our hedging policiescustomers’ ability to pay bills in a timely manner, which could increase customer delinquencies and may lead to an

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 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 ability to compete depends on our ability to convince customers to switch to our products and storage capacity to us as a partservices, renew services with customers upon expiration of their competitive market operations. We are requiredcontract terms, and our ability to fill our allocated storage capacityoffer 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 natural gas, which creates commodity supplytheir customers and price risk. Sometimes we cannot hedge the volumes associated with these assets because they are too small comparedaccess 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,financial and other resources, which could have the effect of us being requiredpose a competitive challenge to access the spot market to cover such a recall.

Our overall operating results fluctuate substantially on a seasonal quarterly and annual basis depending on: (1)(i) the geographic mix of our customer base; (2)(ii) the relative concentration of our commodity mix; (3)(iii) weather conditions, which directly influence the demand for natural gas and electricity and affect the prices of energy commodities; and (4)(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. In addition, our

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 supplies.product deliveries. This timing difference could affectaffects our cash flows, especially during peak cycles in the winter and summer months. Furthermore,

Natural gas accounted for approximately 24% of our retail revenues for the year ended December 31, 2022, which exposes us to a high degree of seasonality in our cash flows and income earned throughout the year as a result of the seasonalityhigh concentration of our business, we may reserve a portion of our excess cash available for distributionheating load in the firstwinter months. We utilize a considerable amount of cash from operations and fourth quarters in orderborrowing capacity to fund working capital, which includes inventory purchases from April through October each year. We sell our secondnatural gas inventory during the months of November through March of each year. We expect that the significant seasonality impacts to our cash flows and third quarter distributions.income will continue in future periods.

We operate 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 ofhighly regulated natural gas and electricity cause volatilityretail sales industry in all of our quarterlyrespective jurisdictions, and annual earnings,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 unablesubject to fully anticipate.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."

Certain state commissions have begun efforts to quarterrestrict the ability of retail suppliers to “pass through” costs to customers associated with gainscertain changes in law or regulatory requirements. For example, on January 22, 2019, the New Jersey Board of Public Utilities (“NJ BPU”) sent a cease and losses on settled hedges relatingdesist letter to natural gas heldthird party suppliers (“TPS”) in inventory if we chooseNew Jersey instructing that a TPS may not charge a customer rate that is higher than the fixed rate applicable during the period for which that rate was fixed. The letter notified TPS that such increases were prohibited and instructed TPS to 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 portionrefund customers amounts charged in excess of the inventoryapplicable fixed rate. Parties have challenged the NJ BPU’s letter and it is usednot clear at this time whether refunds will be required. Similarly, the Connecticut Public Utilities Regulatory Authority (“PURA”) opened a docket after receiving complaints regarding increases by suppliers to satisfy delivery obligations to ourcertain fixed-price customers over the winter months, we hedge the associated price risk using derivative contracts. Any gains or losses associated with settled derivativesupplier contracts are reflected in the statement of operations as a component of retail cost of sales and net asset optimization.

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 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. Many ofconduct customer credit checks, these competitors

As compliance with the federal TCPA regulations and state telemarketing regulations becomes increasingly costly and as they become due.

Our participation 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 wholesale markets to procure supply for our retail customers and hedge pricing risk is subject to regulation by the cost of our supply commodities. Furthermore,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 Texas market,wholesale electricity markets, we are responsible for billingrequired to have market-based rate authorization, also known as “MBR Authorization,” from the distribution charges for the local regulated utilityFederal Energy Regulatory Commission ("FERC"). We are required to make status update filings to FERC to disclose any affiliate relationships and are at risk for these charges,quarterly filings to FERC regarding volumes of wholesale electricity sales in additionorder 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.

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 disruptionsthose interstate pipelines' tariff requirements and FERC regulations and policies applicable to shippers.

Changes in our information management systems arising outlaw and to FERC policies and regulations may adversely affect the availability and reliability of events beyond our control, such as natural disasters, pandemics, epidemics, failures in hardware firm and/or software, power fluctuations, telecommunicationsinterruptible transportation service on interstate pipelines, and other similar disruptions. In addition, our information management systems may be vulnerable to computer viruses, incursions by intruders or hackers and cyber terrorists and other similar disruptions. A cyber-attack on our information management systems 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 remedialwe cannot predict what future 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.

None.

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 1413 "Commitments and Contingencies" to the audited consolidated financial statements, which are incorporated herein by reference.

Not applicable.

Our Class A common stock is traded on the NASDAQ Global Select Market under the symbol “SPKE.“VIA." There is no public market for our Class B common stock. On March 3, 2020,20, 2023, we had one holder of record of our Class A common stock and two holders of record of our Class B common stock, excluding stockholders for whom shares are held in “nominee” or “street name.”

We typically pay a cash dividend each quarter to holders of our Class A common stock to the extent we have cash available for distribution and are permitted to do so under the terms of our Senior Credit Facility. Further, our ability to pay dividends will depend on certain factors including 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.

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

The following graph compares the quarterly performance of our Class A common stock to the NASDAQ Composite Index ("NASDAQ Composite") and the Dow Jones U.S. Utilities Index ("IDU"). The chart assumes that the value of the investment in our Class A common stock and each index was $100 at December 31, 20142017 and that all dividends were reinvested. The stock performance shown on the graph below is not indicative of future price performance.

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