Via Renewables Inc.

03/05/2026 | Press release | Distributed by Public on 03/05/2026 16:23

Annual Report for Fiscal Year Ending December 31, 2025 (Form 10-K)

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.
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.
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
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
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.
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.
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
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.
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.
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 .
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.
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.
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.
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."
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.
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.
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.
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."
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.
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.
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.
Via Renewables Inc. published this content on March 05, 2026, and is solely responsible for the information contained herein. Distributed via EDGAR on March 05, 2026 at 22:23 UTC. If you believe the information included in the content is inaccurate or outdated and requires editing or removal, please contact us at [email protected]