Edgar Filing: Spark Energy, Inc.

Document

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549



		FORM 10-K

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

For the fiscal year ended December 31, 2018.

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

For the transition period from to

Commission File Number: 001-36559

Spark Energy, Inc.

(Exact name of registrant as specified in its charter)



Delaware				46-5453215
(State or other jurisdiction of incorporation or organization)				(I.R.S. Employer Identification No.)



		12140 Wickchester Ln, Suite 100		(713) 600-2600
		Houston, Texas 77079
		(Address and zip code of principal executive offices)		(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:



Title of each class				Name of exchange on which registered
Class A common stock, par value $0.01 per share				The NASDAQ Global Select Market
8.75% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Stock, par value $0.01 per share				The NASDAQ Global Select Market

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act

Yes o No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.

Yes o No x

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

Yes x No o

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

Yes x No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

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

Large accelerated filer o Accelerated filer x

Non-accelerated filer o Smaller reporting company o

Emerging Growth Company x

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

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

Yes o No x

The aggregate market value of common stock held by non-affiliates of the registrant on June 30, 2018, the last business day of the registrant's most recently completed second fiscal quarter, based on the closing price on that date of $9.75, was approximately $111 million. The registrant, solely for the purpose of this required presentation, had deemed its Board of Directors and Executive Officers to be affiliates, and deducted their stockholdings in determining the aggregate market value.

There were 14,141,872 shares of Class A common stock, 20,800,000 shares of Class B common stock and 3,707,256 shares of Series A Preferred Stock outstanding as of February 28, 2019.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant's definitive Proxy Statement in connection with the 2019 Annual Meeting of Stockholders are incorporated by reference into Part III of this Form 10-K.

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		Page
PART I
Items 1 & 2.	Business and Properties	5
Item 1A.	Risk Factors	19
Item 1B.	Unresolved Staff Comments	37
Item 3.	Legal Proceedings	37
Item 4.	Mine Safety Disclosures	37
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	38
	Stock Performance Graph	38
Item 6.	Selected Financial Data	40
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	41
	Overview	41
	Drivers of Our Business	42
	Non-GAAP Performance Measures	46
	Consolidated Results of Operations	49
	Operating Segment Results	52
	Liquidity and Capital Resources	54
	Cash Flows	57
	Summary of Contractual Obligations	58
	Off-Balance Sheet Arrangements	58
	Related Party Transactions	59
	Critical Accounting Policies and Estimates	59
	Contingencies	61
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	62
Item 8.	Financial Statements and Supplementary Data	64
	Index to Consolidated Financial Statements	64
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	123
Item 9A.	Controls and Procedures	123
Item 9B.	Other Information	123
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	124
Item 11.	Executive Compensation	124
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	124
Item 13.	Certain Relationships and Related Transactions, and Director Independence	125
Item 14.	Principal Accounting Fees and Services	125
PART IV
Item 15.	Exhibits, Financial Statement Schedules	125
Item 16.	Form 10-K Summary
SIGNATURES		131
EXHIBIT INDEX		126

Cautionary Note Regarding Forward Looking Statements

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

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


•	changes in commodity prices;


•	the sufficiency of risk management and hedging policies and practices;


•	the impact of extreme and unpredictable weather conditions, including hurricanes and other natural disasters;


•	federal, state and local regulations, including the industry's ability to address or adapt to potentially restrictive new regulations that may be enacted by public utility commissions;


•	our ability to borrow funds and access credit markets;


•	restrictions in our debt agreements and collateral requirements;


•	credit risk with respect to suppliers and customers;


•	changes in costs to acquire customers as well as actual attrition rates;


•	accuracy of billing systems;


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


•	significant changes in, or new changes by, the ISOs in the regions we operate;


•	competition; and


•	the “Risk Factors” in this Annual Report, and in our quarterly reports, other public filings and press releases.

You should review the Risk Factors in Item 1A of Part I and other factors noted throughout or incorporated by reference in this Annual Report that could cause our actual results to differ materially from those contained in any forward-looking statement. All forward-looking statements speak only as of the date of this Annual Report. Unless required by law, we disclaim any obligation to publicly update or revise these statements whether as a result of new information, future events or otherwise. It is not possible for us to predict all risks, nor can we assess the impact of all factors on the business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements.

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PART I.

Items 1 & 2. Business and Properties

General

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

Our business consists of two operating segments:

•

Retail Electricity Segment. In this segment, we purchase electricity supply through physical and financial transactions with market counterparties and independent system operators ("ISOs") and supply electricity to residential and commercial consumers pursuant to fixed-price and variable-price contracts. For the years ended December 31, 2018, 2017 and 2016, approximately 86%, 82% and 76%, respectively, of our revenue was derived from the sale of electricity.

•

Our Operations

As of December 31, 2018, we operated in 94 utility service territories across 19 states and the District of Columbia and had approximately 908,000 RCEs. An RCE, or residential customer equivalent, 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 District of Columbia using eleven brands (CenStar Energy, Electricity Maine, Electricity N.H., HIKO Energy, Major Energy, Oasis Energy, Perigee Energy, Provider Power Mass, Respond Power, Spark Energy, and Verde Energy). During 2018, we began reducing the number of brands through which we conduct operations with a goal of reducing the number of separate brands to six by the end of 2019.

Customer Contracts and Product Offerings

Fixed and variable-price contracts

We offer a variety of fixed-price and variable-price service options to our natural gas and electricity customers. Under our fixed-price service options, our customers purchase natural gas and electricity at a fixed price over the life of the customer contract, which provides our customers with protection against increases in natural gas and electricity prices. Our fixed-price contracts typically have a term of one to two years for residential customers and up to three 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 come with or without a monthly service fee and/or a termination fee. 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 factors,

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including the competitive landscape in the market and the regulatory environment, and may also include a monthly service fee. We also offer variable-price natural gas and electricity plans that offer an introductory fixed price that is generally applied for a certain number of billing cycles, typically two billing cycles in our current markets, then switches to a variable price based on market conditions. Our variable plans may or may not provide for a termination fee, depending on the market and customer type.

As of December 31, 2018, approximately 53% of our natural gas RCEs were fixed-price, and the remaining 47% were variable-price. As of December 31, 2018, approximately 81% of our electricity RCEs were fixed-price, and the remaining 19% were variable-price.

The fixed/variable splits of our RCEs were as follows as of December 31, 2018:

Green products and renewable energy credits

We offer renewable and carbon neutral (“green”) products in certain markets. Green energy products are a growing market opportunity and typically provide increased unit margins as a result of improved customer satisfaction and less competition. Renewable electricity products allow customers to choose electricity sourced from wind, solar, hydroelectric and biofuel sources, through the purchase of renewable energy credits (“RECs”). Carbon neutral natural gas products give customers the option to reduce or eliminate the carbon footprint associated with their energy usage through the purchase of carbon offset credits. These products typically provide for fixed or variable prices and generally follow the terms of our other products with the added benefit of carbon reduction and reduced environmental impact. We currently offer renewable electricity in all of our electricity markets and carbon neutral natural gas in several of our gas markets.

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

Customer Acquisition and Retention

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

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Organic Growth

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

Once a product has been created for a particular market, we then develop a marketing campaign using a combination of sales channels. We identify and acquire customers through a variety of sales channels, including our inbound customer care call center, outbound calling, online marketing, opt-in web-based leads, email, direct mail, door-to-door sales, affinity programs, direct sales, brokers and consultants. For residential customers, we primarily use indirect sales brokers, web based solicitation, door-to-door sales, outbound calling, and other methods. For 2018, the largest channels were door-to-door sales, web-based, and outbound telemarketing. For C&I customers, which are typically larger and have greater natural gas and electricity requirements, we typically use brokers or direct marketing to obtain these customers. At December 31, 2018, our customer base was 55% residential and 45% C&I customers. In our sales practices, we typically employ multiple vendors under short-term contracts and have not entered into any exclusive marketing arrangements with sales vendors. Our marketing team continuously evaluates the effectiveness of each customer acquisition channel and makes adjustments in order to achieve targeted growth and manage customer acquisition costs. We attempt to maintain a disciplined approach to recovery of our customer acquisition costs within defined periods.

Acquisitions

We actively monitor acquisition opportunities that may arise in the domestic acquisition market, and seek to

acquire both portfolios of customers as well as retail energy companies utilizing some combination of cash and borrowings under our Senior Credit Facility, the issuance of common or preferred stock, or other financing arrangements. Historically, our customer acquisition strategy has been executed using both third parties and through affiliated relationships. See “—Relationship with our Founder and Majority Shareholder” for a discussion of affiliate relationships.

The following table provides a summary of our acquisitions over the past five years:

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Company / Portfolio	Date Completed	RCEs	Segment	Acquisition Source
Company / Portfolio	Date Completed	RCEs	Segment	Acquisition Source
Customer Portfolio	February 2015	12,500	Electricity	Third Party
CenStar Energy Corp.	July 2015	65,000	Natural Gas Electricity	Third Party
Oasis Power Holdings, LLC	July 2015	40,000	Natural Gas Electricity	Affiliate
Customer Portfolio	September 2015	9,500	Natural Gas	Third Party
Provider Companies ⁽¹⁾	August 2016	121,000	Electricity	Third Party
Major Energy Companies ⁽²⁾	August 2016	220,000	Natural Gas Electricity	Affiliate
Perigee Energy, LLC	April 2017	17,000	Natural Gas Electricity	Affiliate
Verde Companies ⁽³⁾	July 2017	145,000	Electricity	Third Party
Customer Portfolio ⁽⁴⁾	October 2017 ⁽⁴⁾	44,000	Electricity	Third Party
HIKO Energy, LLC	March 2018	29,000	Natural Gas Electricity	Third Party
Customer Portfolio ⁽⁵⁾	(5)	35,000	Natural Gas Electricity	Affiliate
Customer Portfolio ⁽⁶⁾	(6)	60,000	Natural Gas Electricity	Third Party


(1)	Included Electricity Maine, LLC, Electricity N.H., LLC, Provider Power Mass, LLC (collectively, the “Provider Companies”).


(2)	Included Major Energy Services, LLC, Major Energy Electric Services, LLC, and Respond Power, LLC (collectively, the “Major Energy Companies”).

(3)

Included Verde Energy USA, Inc.; Verde Energy USA Commodities, LLC; Verde Energy USA Connecticut, LLC; Verde Energy USA DC, LLC; Verde Energy USA Illinois, LLC; Verde Energy USA Maryland, LLC; Verde Energy USA Massachusetts, LLC; Verde Energy USA New Jersey, LLC; Verde Energy USA New York, LLC; Verde Energy USA Ohio, LLC; Verde Energy USA Pennsylvania, LLC; Verde Energy USA Texas Holdings, LLC; Verde Energy USA Trading, LLC; and Verde Energy Solutions, LLC (collectively, the “Verde Companies”).


(4)	Includes customers transferred from April 2017 through October 2017 from the original owner of Perigee.


(5)	Includes customers transferred from April 2018 through December 2018.


(6)	We began to transfer customers we acquired from Starion Energy in December 2018 and will continue to transfer during 2019.

Please see and Item 9B. “Other Information” and Note 4 "Acquisitions" 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" for a discussion of risks related to our acquisition strategy and ability to finance such transactions.

Retaining customers and maximizing customer lifetime value

Following the acquisition of a customer, we devote significant attention to customer retention. We have developed a disciplined renewal communication process, which is designed to effectively reach our customers prior to the end of the contract term, and employ a team dedicated to managing this renewal communications process. Customers are contacted in each utility prior to the expiration of the customer's contract. We may contact the customer through additional channels such as outbound calls or email.

We also apply a proprietary evaluation and segmentation process to optimize value to both us and the customer. We analyze historical usage, attrition rates and consumer behaviors to specifically tailor competitive products that aim to maximize the total expected return from energy sales to a specific customer, which we refer to as customer lifetime value.

Investment in ESM

In 2016, we and eREX Co., Ltd., a Japanese company, entered into a joint venture investment in eREX Spark Marketing Co., Ltd ("ESM"). Operations for ESM began on April 1, 2016 in connection with the deregulation of the Japanese power market. As of December 31, 2018, we have contributed 156.4 million Japanese Yen, or $1.4

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million, for a 20% ownership interest in ESM. As of December 31, 2018, ESM has approximately 119,000 customers, which are currently excluded from our count of RCEs.

Commodity Supply

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

In most markets, we hedge our electricity exposure with financial products and then purchase the physical power directly from the ISO for delivery. Alternatively, we may use physical products to hedge our electricity exposure rather than buying physical electricity in the day-ahead market from the ISO. During the year ended December 31, 2018, we transacted physical and financial settlement of electricity with approximately 16 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 conditions. Many of the utilities we serve also allocate natural gas transportation and storage assets to us as a part of their competitive choice program. We are required to fill our allocated storage capacity with natural gas, which creates commodity supply and price risk. Sometimes we cannot hedge the volumes associated with these assets because they are too small compared to the much larger bulk transaction volumes required for trades in the wholesale market or it is not economically feasible to do so.

We periodically adjust our portfolio of purchase/sale contracts in the wholesale natural gas market based upon continual analysis of our forecasted load requirements. Natural gas is then delivered to the local regulated utility city-gate or other specified delivery points 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, 2018, we transacted physical and financial settlement of natural gas with approximately 82 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 able to purchase energy supply from these counterparties. If we desire to purchase supply beyond these credit limits, we are required to post collateral in the form of either cash or letters of credit. As we begin to approach the limits of our credit line with one supplier, we may purchase energy supply from another supplier and sell that supply to the original counterparty in order to reduce our net position with that counterparty and open up additional credit to procure supply in the future. Our sales of gas pursuant to these activities also enable us to optimize our credit lines with third-party energy suppliers by decreasing our net buy position with those suppliers.

Asset Optimization

Part of our business includes asset optimization activities in which we identify opportunities in the wholesale natural gas markets in conjunction with our retail procurement and hedging activities. Many of the competitive pipeline choice programs in which we participate require us and other retail energy suppliers to take assignment of and manage natural gas transportation and storage assets upstream of their respective city-gate delivery points. In our allocated storage assets, we are obligated to buy and inject gas in the summer season (April through October) and sell and withdraw gas during the winter season (November through March). These injection and purchase obligations require us to take a seasonal long position in natural gas. Our asset optimization group determines

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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.

Risk Management

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

Our risk committee has control and authority over all of our risk management activities. The risk committee establishes and oversees the execution of our credit risk management policy and our commodity risk policy. The risk management policies are reviewed at least annually and the risk committee typically meets quarterly to assure that we have followed its 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 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 the various risks we face in our risk management activities is as follows:

Commodity Price and Volumetric Risk

Because our contracts require that we deliver full natural gas or electricity requirements to our customers and because our customers’ usage can be impacted by factors such as weather, we may periodically purchase more or less commodity than our aggregate customer volumetric needs. In buying or selling excess volumes, we may be exposed to commodity price volatility. In order to address the potential volumetric variability of our monthly deliveries for fixed-price customers, we implement various hedging strategies to attempt to mitigate our exposure.

Our commodity risk management strategy is designed to hedge substantially all of our forecasted volumes on our fixed-price customer contracts, as well as a portion of the near-term volumes on our variable-price customer

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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 in one area to other areas, thereby mitigating potential increased costs for natural gas that we otherwise may have had to acquire at higher prices to meet increased demand.

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

Basis Risk

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

Customer Credit Risk

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

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In territories where POR programs have been established, the local regulated utility purchases our receivables, and then becomes responsible for billing and collecting payment from the customer. In return for their assumption of risk, we receive slightly discounted proceeds on the receivables sold. POR programs result in substantially all of our credit risk being linked to the applicable utility and not to our end-use customer in these territories. For the year ended December 31, 2018, approximately 66% of our retail revenues were derived from territories in which substantially all of our credit risk was directly linked to local regulated utility companies, all of which had investment grade ratings. During the same period, we paid these local regulated utilities a weighted average discount of approximately 1.0% of total revenues for customer credit risk. In certain of the POR markets in which we operate, the utilities limit their collections exposure by retaining the ability to transfer a delinquent account back to us for collection when collections are past due for a specified period. If our subsequent collection efforts are unsuccessful, we return the account to the local regulated utility for termination of service. 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 variety of procedures, which may include credit score screening, deposits and disconnection for non-payment. We also maintain an allowance for doubtful accounts, which represents our estimate of potential credit losses associated with accounts receivable from customers within these markets.

We assess the adequacy of the allowance for 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, 2018 was $10.1 million, or 1.0% 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, 2018.

We do not have high concentrations of sales volumes to individual customers. For the year ended December 31, 2018, our largest customer accounted for less than 1% of total retail energy sales volume.

Counterparty Credit Risk in Wholesale Markets

We do not independently produce natural gas and electricity and depend upon third parties for our supply, which exposes us to wholesale counterparty credit risk in our retail and asset optimization activities. If the counterparties to our supply contracts are unable to perform their obligations, we may suffer losses, including those that occur as a result of being unable to secure replacement supplies of natural gas or electricity on a timely or cost-effective basis or at all. At December 31, 2018, approximately $4.1 million of our total exposure of $22.7 million was either with a non-investment grade counterparty or otherwise not secured with collateral or a guarantee.

Operational Risk

As with all companies, we are at risk from cyber-attacks (breaches, unauthorized access, misuse, computer viruses, or other malicious code or other events) that could materially adversely affect our business, or otherwise cause interruptions or malfunctions in our operations.

We mitigate these risks through multiple layers of security controls including policy, hardware, and software security solutions. We also have engaged third parties to assist with both external and internal vulnerability scans and continually enhance awareness through employee education and accountability. As of December 31, 2018, we have not experienced any material loss related to cyber-attacks or other information security breaches.

Relationship with our Founder and Majority Shareholder

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We have historically leveraged our relationship with affiliates of our founder, chairman and majority shareholder, W. Keith Maxwell III (our "Founder"), to execute our strategy, including sourcing acquisitions, financing, and operations support. Our Founder owns National Gas & Electric, LLC, an affiliate of the Company (“NG&E”), which was formed for the purpose of purchasing retail energy companies and retail customer books that may ultimately be resold to the Company. 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 Factors" related to acquisitions and transactions with our affiliates.

Prior to April 2018, we maintained a Master Service Agreement (the “Master Service Agreement”) with an affiliated company wholly owned by our Founder. Under this agreement, we were provided operational support services such as: enrollment and renewal transaction services; customer billing and transaction services; electronic payment processing services; customer services and information technology infrastructure and application support services (collectively, the "Services"). We paid our affiliate a monthly fee consisting of a monthly fixed fee plus a variable fee per customer per month depending on market complexity. Effective April 1, 2018, we terminated the Master Services Agreement. For a further discussion of transactions with affiliates, see Part II, Financial Statements and Supplementary Data, Note 15 "Transactions with Affiliates."

Competition

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

Our ability to compete depends on our ability to convince customers to switch to our products and services, 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 these advantages, many customers of these local regulated utilities may decide to stay with their longtime energy provider if they have been satisfied with their service in the past. In addition, competitors may choose to offer more attractive short-term pricing to increase their market share.

Seasonality of Our Business

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

Natural gas accounted for approximately 14% of our retail revenues for the year ended December 31, 2018, 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.

Regulatory Environment

We operate in the highly regulated natural gas and electricity retail sales industry in all of our respective jurisdictions, and must comply with the legislation and regulations in these jurisdictions in order to maintain our licenses to operate. We must also comply 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. There is potential for changes to state legislation and regulatory measures addressing licensing requirements that may impact our business model in the applicable jurisdiction. In addition, as further discussed below, our marketing activities and customer enrollment procedures are subject to rules and regulations at the state and federal levels, and failure to comply with requirements imposed by federal and state regulatory authorities could impact our licensing in a particular market.

In February 2016, the New York State Public Service Commission ("NYPSC") issued an order (the "Reset Order") resetting retail energy markets that, among other things, would have limited the types of competitive products that energy service companies ("ESCOs"), such as us, could offer in New York. The Reset Order stated that all new customer enrollments or expiring agreements for mass market (residential and certain small commercial) customers must enroll or re-enroll in a contract that offers either: (i) a guarantee that the customer will pay no more than what the customer would pay as a full service utility customer, or (ii) an electricity product that is at least 30% derived from specific renewable sources either in the State of New York or in adjacent market areas. In July 2016, most of the Reset Order, including the provisions previously noted, was vacated by a New York state court.

In July 2017, the New York State Supreme Court, Appellate Division, Third Department ruled to uphold the lower court’s ruling overturning portions of the Reset Order because the NYPSC did not follow the proper process in issuing the Reset Order. However, the court also determined that the NYPSC has authority to set ESCO rates and take other action consistent with the Resetting Order as long as the proper administrative process is followed. The NYPSC conducted evidentiary proceedings to determine what the regulatory framework for ESCOs in New York would be going forward, which concluded in late 2017. There can be no assurance that this process will result in a commercially reasonable framework for ESCOs to operate in New York. See "Risk Factors—We face risks due to increasing regulation of the retail energy industry at the state level."

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In addition, in connection with the Low-Income Order promulgated by the NYPSC in December of 2016, the New York State Supreme Court, Appellate Division, Third Department ruled in September 2017 that ESCOs must proceed with returning existing low-income customers to utility service and stop enrolling new low-income customers. The ESCO’s have effectively exhausted their legal remedies to appeal this matter and must now comply with the Low-Income Order. ESCOs may continue serving low income customers if those customers are enrolled in fixed arrangements with guaranteed savings or with value add inclusions (that were entered into prior to the effective date of the Low-Income Order) or if the ESCO receives a waiver from the NYPSC to provide low-income customers with guaranteed savings. The Company and its subsidiaries have been returning low-income customers to the applicable utilities as they have rolled off of their contracts. As of December 31, 2018, remaining low-income customers represent approximately 3% of our total RCEs in New York and 0.5% of our RCEs overall.

We are evaluating the potential impact of the NYPSC's Reset Order and subsequent proceedings on our New York operations while preparing to operate in compliance with any new requirements that may come as a result of any new order promulgated by the NYPSC. Given the uncertainty of the outcome of these matters and the final requirements that may be implemented, we are unable to predict at this time whether it will have a significant long-term impact on our operations in New York.

More recently, on October 15, 2018, the Attorney General for the Commonwealth of Massachusetts filed suit against another ESCO and others alleging unfair or deceptive acts or practices in violation of a consumer protections act, breach of the covenant of good faith and fair dealing, and violation of the Massachusetts Telemarketing Solicitation Act. Contemporaneously with the filing of their complaint, the Commonwealth filed for injunctive relief seeking to attach purchase of receivables program revenues owed to the ESCO as possible damages. There can be no assurance that the Commonwealth will not pursue similar claims against other ESCOs.

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

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

Recent interpretations of the Telephone Consumer Protection Act of 1991 (the "TCPA") by the Federal Communications Commission ("FCC") have introduced confusion regarding what constitutes an “autodialer” for purposes of determining compliance under the TCPA. Also, additional restrictions have been placed on wireless

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telephone numbers making compliance with the TCPA more costly. See “Risk Factors—Risks Related to Our Business and Our Industry—Liability under the TCPA has increased significantly in recent years, and we face risks if we fail to comply."

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

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

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

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

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

Employees

We employed 176 people as of December 31, 2018, none of which were subject to any collective bargaining agreements. We have not experienced any strikes or work stoppages and consider our relations with our employees to be satisfactory. We also utilize the services of independent contractors and vendors to perform various services.

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Facilities

Our corporate headquarters is located in Houston, Texas, and we also maintain an office in Orangeburg, New York. We believe that our facilities are adequate for our current operations. We share our corporate headquarters with certain of our affiliates, one of which is the lessee under the lease agreement covering these facilities, paying the entire lease payment on behalf of all affiliates. We reimburse this affiliate for our share of the leased space.

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Available Information

Our principal executive offices are located at 12140 Wickchester Ln., Suite 100, Houston, Texas 77079, and our telephone number is (713) 600-2600. Our website is located at www.sparkenergy.com. We make available our periodic reports and other information filed with or furnished to the Securities and Exchange Commission (the “SEC”), including our annual reports on Form 10-K, our quarterly reports on Form 10-Q, our current reports on Form 8-K, and all amendments to those reports, free of charge through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Any materials filed with the SEC may be read and copied at the SEC’s website at www.sec.gov.

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Item 1A. Risk Factors

You should carefully consider the risks described below together with the other information contained in this Annual Report on Form 10-K. If any of the risks below were to occur, our business, financial condition, cash flows, results of operation and ability to pay dividends on our Class A common stock and Series A Preferred Stock could be adversely impacted, and the price of the Class A common stock and Series A Preferred Stock could decline and you could lose your investment.

Risks Related to Our Business and Our Industry

We are subject to commodity price risk.

Our financial results are largely dependent on the prices at which we can acquire the commodities we resell. The prevailing market prices for natural gas and electricity have historically, and may continue to fluctuate substantially over relatively short periods of time. Changes in market prices for natural gas and electricity may result from many factors that are outside of our control, including:


—	weather conditions;


—	seasonality;


—	demand for energy commodities and general economic conditions;


—	disruption of natural gas or electricity transmission or transportation infrastructure or other constraints or inefficiencies;


—	reduction or unavailability of generating capacity, including temporary outages, mothballing, or retirements;


—	the level of prices and availability of natural gas and competing energy sources, including the impact of changes in environmental regulations impacting suppliers;


—	the creditworthiness or bankruptcy or other financial distress of market participants;


—	changes in market liquidity;


—	natural disasters, wars, embargoes, acts of terrorism and other catastrophic events;


—	significant changes in the pricing methods in the wholesale markets in which we operate;


—	changes in regulatory policies concerning how markets are structured, how compensation is provided for service, and the kinds of different services that can or must be offered;


—	federal, state, foreign and other governmental regulation and legislation; and


—	demand side management, conservation, alternative or renewable energy sources.

We may not be able to pass along changes to the prices we pay to acquire commodities to our customers.

Our financial results may be adversely impacted by weather conditions.

Weather conditions directly influence the demand for and availability of natural gas and electricity and affect the prices of energy commodities. Generally, on most utility systems, demand for natural gas peaks in the winter and demand for electricity peaks in the summer. Typically, when winters are warmer or summers are cooler, demand for energy is lower than expected, resulting in less natural gas and electricity consumption than forecasted. When demand is below anticipated levels due to weather patterns, we may be forced to sell excess supply at prices below our acquisition cost, which could result in reduced margins or even losses.

Conversely, when winters are colder or summers are warmer, consumption may outpace the volumes of natural gas and electricity against which we have hedged, and we may be unable to meet increased demand with storage or swing supply. In these circumstances, we may experience reduced margins or even losses if we are required to purchase additional supply at higher prices. We may fail to accurately anticipate demand due to fluctuations in weather or to effectively manage our supply in response to a fluctuating commodity price environment.

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Our risk management policies and hedging procedures may not mitigate risk as planned, and we may fail to fully or effectively hedge our commodity supply and price risk.

To provide energy to our customers, we purchase commodities in the wholesale energy markets, which are often highly volatile. Our commodity risk management strategy is designed to hedge substantially all of our forecasted volumes on our fixed-price customer contracts, as well as a portion of the near-term volumes on our variable-price customer contracts. We use both physical and financial products to hedge our exposure. The efficacy of our risk management program may be adversely impacted by unanticipated events and costs that we are not able to effectively hedge, including abnormal customer attrition and consumption, certain variable costs associated with electricity grid reliability, pricing differences in the local markets for local delivery of commodities, unanticipated events that impact supply and demand, such as extreme weather, and abrupt changes in the markets for, or availability or cost of, financial instruments that help to hedge commodity price.

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

Additionally, assumptions that we use in establishing our hedges may reduce the effectiveness of our hedging instruments. Considerations that may affect our hedging policies include, but are not limited to, human error, assumptions about customer attrition, the relationship of prices at different trading or delivery points, assumptions about future weather, and our load forecasting models.

In addition, we incur costs monthly for ancillary charges such as reserves and capacity in the electricity sector by ISOs. For example, the ISOs will charge all retail electricity providers for monthly reserves that the ISO determines are necessary to protect the integrity of the grid. We 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 conditions. We may be unable to fully pass the higher cost of ancillary reserves and reliability services through to our customers, and increases in the cost of these ancillary reserves and reliability services could negatively impact our results of operations.

Many of the natural gas utilities we serve allocate a share of transportation and storage capacity to us as a part of their competitive market operations. We are required to fill our allocated storage capacity with natural gas, which creates commodity supply and price risk. Sometimes we cannot hedge the volumes associated with these assets because they are too small compared to the much larger bulk transaction volumes required for trades in the wholesale market or it is not economically feasible to do so. In some regulatory programs or under some contracts, this capacity may be subject to recall by the utilities, which could have the effect of us being required to access the spot market to cover such a recall.

We face risks due to increasing regulation of the retail energy industry at the state level.

The retail energy industry is highly regulated. Regulations may be changed or reinterpreted and new laws and regulations applicable to our business could be implemented in the future. To the extent that the competitive restructuring of retail electricity and natural gas markets is reversed, altered or discontinued, such changes could have a detrimental impact on our business and overall financial condition.

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Some states are beginning to increase their regulation of their retail electricity and natural gas markets in an effort to eliminate deceptive marketing practices. For example, in 2015 the Connecticut Legislature passed legislation providing that licensed electric suppliers in Connecticut could no longer offer variable rate products.

Additionally, the NYPSC launched efforts in 2016 to limit the types of competitive products that ESCOs, such as us, can offer in New York. The NYPSC issued an order (the "Reset Order") requiring that all new customer enrollments or expiring agreements for mass market (residential and certain small commercial) customers must enroll or re-enroll in a contract that offers either: (i) a guarantee that the customer will pay no more than what the customer would pay as a full service utility customer, or (ii) an electricity product that is at least 30% derived from specific renewable sources either in the State of New York or in adjacent market areas. Most of the original Reset Order was vacated by a New York state court in July 2016. However, the ESCOs lost an appeal on the matter of whether the NYPSC has jurisdiction over ESCO pricing of products. Currently, ESCOs and the NYPSC are involved in evidentiary proceedings that are addressing, among other things, whether the NYPSC has sufficient cause to implement regulatory changes similar to those proposed in the Reset Order. In the event that all or significant components of the Reset Order are implemented, ESCOs, including us, could be obligated to, among other things, drop customers to the utility or seek affirmative consent from fixed and variable rate customers upon renewal, which may be very difficult to obtain. As of December 31, 2018, approximately 16% of our customers on an RCE basis were located in New York.

The NYPSC has also implemented a low-income order that requires ESCOs to return existing low-income customers to utility service and stop enrolling new low-income customers unless customers are enrolled in fixed arrangements with guaranteed savings or with value add inclusions (that were entered into prior to the effective date of the low-income order) or if the ESCO receives a waiver from the NYPSC to provide low-income customers with guaranteed savings. As a result of the low-income order, we have been dropping low-income customers back to the applicable utilities as they have rolled off of their contracts. As of December 31, 2018, remaining low-income customers represent approximately 3% of our total RCEs in New York and 0.5% of our RCEs overall. There can be no assurance that the NYPSC or state regulatory agencies to which we are subject will not continue trying to implement restrictive anti-competitive regulations on us.

On October 15, 2018, the Attorney General for the Commonwealth of Massachusetts filed suit against certain other ESCOs alleging unfair or deceptive acts or practices in violation of a consumer protections act, breach of the covenant of good faith and fair dealing, and violation of the Massachusetts Telemarketing Solicitation Act. Contemporaneously with the filing of their complaint, the Commonwealth filed for injunctive relief seeking to attach purchase of receivables program revenues owed to the ESCO as possible damages. There can be no assurance that the Commonwealth will not pursue similar claims against other ESCOs or that other state regulatory agencies to which we are subject will not continue trying to implement restrictive anti-competitive regulations on us and other ESCOs.

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

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

Our costs of doing business may fluctuate based on changing state, federal and local rules and regulations. For example, many electricity markets have rate caps, and changes to these rate caps by regulators can impact future price exposure. Similarly, regulatory changes can result in new fees or charges that may not have been anticipated when existing retail contracts were drafted, which can create financial exposure. Our ability to manage cost increases that result from regulatory changes will depend, in part, on how the “change in law provisions” of our contracts are interpreted and enforced, among other factors.

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

Our outbound telemarketing efforts and use of mobile messaging to communicate with our customers subjects us to regulation under the TCPA. Over the last several years, companies have been subject to significant liabilities as a result of violations of the TCPA, including penalties, fines and damages under class action lawsuits. In addition, the increased use by us and other consumer retailers of mobile messaging to communicate with our customers has created new issues of application of the TCPA to these communications. In 2015, the Federal Communications Commission issued several rulings that made compliance with the TCPA more difficult and costly. Our failure to effectively monitor and comply with our activities that are subject to the TCPA could result in significant penalties and the adverse effects of having to defend and ultimately suffer liability in a class action lawsuit related to such non-compliance.

We are also subject to liability under the TCPA for actions of our third party vendors who are engaging in outbound telemarketing efforts on our behalf. The issue of vicarious liability for the actions of third parties in violation of the TCPA remains unclear and has been the subject of conflicting precedent in the federal appellate courts. There can be no assurance that we may be subject to significant damages as a result of a class action lawsuit for actions of our vendors that we may not be able to control.

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

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

A negative outcome for any of these matters could result in significant damages. Litigation may also negatively impact us by requiring us to pay substantial settlements, increasing our legal costs, diverting management attention from other business issues or harming our reputation with customers.

For additional information regarding the nature and status of certain proceedings, see Note 14 "Commitment and Contingencies" to the audited consolidated financial statements.

Our business is dependent on retaining licenses in the markets in which we operate.

Our business model is dependent on continuing to be licensed in existing markets. We may have a license revoked or not be granted a renewal of a license, or our license could be adversely conditioned or modified (e.g., by increased bond posting obligations).

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

We have grown our business in part through strategic acquisition opportunities from third parties and from affiliates of our majority shareholder and may continue to do so in the future. Achieving the anticipated benefits of these transactions depends in part upon our ability to identify accretive acquisition targets, accurately assess the benefits

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and risks of the acquisition prior to undertaking it, and the ability to integrate the acquired businesses in an efficient and effective manner. When we identify an acquisition candidate, there is a risk that we may be unable to negotiate terms that are beneficial to us. Additionally, even if we identify an accretive acquisition target, the successful acquisition of that business requires estimating anticipated cash flow and accretive value, evaluating potential regulatory challenges, retaining customers and assuming liabilities. The accuracy of these estimates is inherently uncertain and our assumptions may turn out to be incorrect.

Furthermore, when we make an acquisition, we may not be able to accomplish the integration process smoothly or successfully. The difficulties of integrating acquisitions can include, among other things:


–	coordinating geographically separate organizations and addressing possible differences in corporate cultures and management philosophies;


–	dedicating significant management resources to the integration of the acquisition, which may temporarily distract management's attention from the day-to-day business of the combined company;


–	increased liquidity needs to support working capital for the purchase of natural gas and electricity supply to meet our customers’ needs, for the credit requirements of forward physical supply and for generally higher operating expenses;


–	operating in states and markets where we have not previously conducted business;


–	managing different and competing brands and retail strategies in the same markets;


–	coordinating customer information and billing systems and determining how to optimize those systems on a consolidated level;


–	ensuring our hedging strategy adequately covers a customer base that is managed through multiple systems; and


–	successfully recognizing expected cost savings and other synergies in overlapping functions.

In many of our acquisition agreements, we are entitled to indemnification from the counterparty for various matters, including breaches of representations, warranties and covenants, tax matters, and litigation proceedings. We generally obtain security to provide assurances that the counterparty could perform its indemnification obligations, which may be in the form of escrow accounts, payment withholding or other methods. However, to the extent that we do not obtain security, or the security turns out to be inadequate, there is a risk that the counterparty may fail to perform on its indemnification obligations, which could result in the losses being incurred by us.

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

Pursuant to our cash dividend policy, we distribute a significant portion of our cash through regular quarterly dividends, and our ability to grow and make acquisitions with cash on hand could be limited.

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

We may not be able to manage our growth successfully.

The growth of our operations will depend upon our ability to expand our customer base in our existing markets and to enter new markets in a timely manner at reasonable costs, organically or through acquisitions. In order for us to recover expenses incurred in entering new markets and obtaining new customers, we must attract and retain customers on economic terms and for extended periods. We may experience difficulty managing our growth and

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implementing new product offerings, integrating new customers and employees, and complying with applicable market rules and the infrastructure for product delivery.

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

Our financial results fluctuate on a seasonal, quarterly and annual basis.

Our overall operating results fluctuate substantially on a seasonal, quarterly and annual basis depending on: (1) the geographic mix of our customer base; (2) the concentration of our product mix; (3) the impact of weather conditions on commodity pricing and demand; (4) variability in market prices for natural gas and electricity, and (5) changes in the cost of delivery of commodities through energy delivery networks. These factors can have material short-term impacts on monthly and quarterly operating results, which may be misleading when considered outside of the context of our annual operating cycle. In addition, our accounts payable and accounts receivable are impacted by seasonality due to the timing differences between when we pay our suppliers for accounts payable versus when we collect from our customers on accounts receivable. We typically pay our suppliers for purchases of natural gas on a monthly basis and electricity on a weekly basis. However, it takes approximately two months from the time we deliver the electricity or natural gas to our customers before we collect from our customers on accounts receivable attributable to those supplies. This timing difference could affect our cash flows, especially during peak cycles in the winter and summer months. Furthermore, as a result of the seasonality of our business, we may reserve a portion of our excess cash available for distribution in the first and fourth quarters in order to fund our second and third quarter distributions.

Additionally, we enter into a variety of financial derivative and physical contracts to manage commodity price risk, and we use mark-to-market accounting to account for this hedging activity. Under the mark-to-market accounting method, changes in the fair value of our hedging instruments that are not qualifying or not designated as hedges under accounting rules are recognized immediately in earnings. As a result of this accounting treatment, changes in the forward prices of natural gas and electricity cause volatility in our quarterly and annual earnings, which we are unable to fully anticipate.

We could also incur volatility from quarter to quarter associated with gains and losses on settled hedges relating to natural gas held in inventory if we choose to hedge the summer-winter spread on our retail allocated storage capacity. We typically purchase natural gas inventory and store it from April to October for withdrawal from November through March. Since a portion of the inventory is used to satisfy delivery obligations to our fixed-price customers over the winter months, we hedge the associated price risk using derivative contracts. Any gains or losses associated with settled derivative contracts are reflected in the statement of operations as a component of retail cost of sales and net asset optimization.

We may have difficulty retaining our existing customers or obtaining a sufficient number of new customers, due to competition and for other reasons.

The markets in which we compete are highly competitive, and we may face difficulty retaining our existing customers or obtaining new customers due to competition. We encounter significant competition from local regulated utilities or their retail affiliates and traditional and new retail energy providers. Many of these competitors or potential competitors are larger than us, have access to more significant capital resources, have more well-established brand names and have larger existing installed customer bases.

Additionally, existing customers may switch to other retail energy service providers during their contract terms in the event of a significant decrease in the retail price of natural gas or electricity in order to obtain more favorable prices. Although we generally have a right to collect a termination fee from each customer on a fixed-price contract who terminates their contract early, we may not be able to collect the termination fees in full or at all. Our variable-price contracts can typically be terminated by our customers at any time without penalty. We may be unable to obtain new customers or maintain our existing customers due to competition or otherwise.

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Increased collateral requirements in connection with our supply activities may restrict our liquidity.

Our contractual agreements with certain local regulated utilities and our supplier counterparties require us to maintain restricted cash balances or letters of credit as collateral for credit risk or the performance risk associated with the future delivery of natural gas or electricity. These collateral requirements may increase as we grow our customer base. Collateral requirements will increase based on the volume or cost of the commodity we purchase in any given month and the amount of capacity or service contracted for with the local regulated utility. Significant changes in market prices also can result in fluctuations in the collateral that local regulated utilities or suppliers require.

The effectiveness of our operations and future growth depend in part on the amount of cash and letters of credit available to enter into or maintain these contracts. The cost of these arrangements may be affected by changes in credit markets, such as interest rate spreads in the cost of financing between different levels of credit ratings. These liquidity requirements may be greater than we anticipate or are able to meet.

We are subject to direct credit risk for certain customers who may fail to pay their bills as they become due.

We bear direct credit risk related to customers located in markets that have not implemented POR programs as well as indirect credit risk in those POR markets that pass collection efforts along to us after a specified non-payment period. For the year ended December 31, 2018, customers in non-POR markets represented approximately 34% of our retail revenues. We generally have the ability to terminate contracts with customers in the event of non-payment, but in most states in which we operate we cannot disconnect their natural gas or electricity service. In POR markets where the local regulated utility has the ability to return non-paying customers to us after specified periods, we may realize a loss for one to two billing periods until we can terminate these customers’ contracts. We may also realize a loss on fixed-price customers in this scenario due to the fact that we will have already fully hedged the customer’s expected commodity usage for the life of the contract and we also remain liable to our suppliers of natural gas and electricity for the cost of our supply commodities. Furthermore, in the Texas market, we are responsible for billing the distribution charges for the local regulated utility and are at risk for these charges, in addition to the cost of the commodity, in the event customers fail to pay their bills. Changing economic factors, such as rising unemployment rates and energy prices also result in a higher risk of customers being unable to pay their bills when due.

Our indebtedness could adversely affect our ability to raise additional capital to fund our operations or pay dividends. It could also expose us to the risk of increased interest rates and limit our ability to react to changes in the economy or our industry as well as impact our cash available for distribution.

We have $129.5 million of indebtedness outstanding and $49.4 million in issued letters of credit under our Senior Credit Facility, and $10.0 million of indebtedness outstanding under our Subordinated Facility as of December 31, 2018. Debt we incur under our Senior Credit Facility, Subordinated Facility or otherwise could have negative consequences, including:


—	increasing our vulnerability to general economic and industry conditions;


—	requiring cash flow from operations to be dedicated to the payment of principal and interest on our indebtedness, therefore reducing or eliminating our ability to pay dividends to holders of our Class A common stock and Series A Preferred Stock, or to use our cash flow to fund our operations, capital expenditures and future business opportunities;


—	limiting our ability to fund future acquisitions or engage in other activities that we view as in our long-term best interest;


—	restricting our ability to make certain distributions with respect to our capital stock and the ability of our subsidiaries to make certain distributions to us, in light of restricted payment and other financial covenants, including requirements to maintain certain financial ratios, in our credit facilities and other financing agreements;

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—	exposing us to the risk of increased interest rates because certain of our borrowings are at variable rates of interest; and


—	limiting our ability to obtain additional financing for working capital including collateral postings, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes.

If we are unable to satisfy financial covenants in our debt instruments, it could result in an event of default that, if not cured or waived, may entitle the lenders to demand repayment or enforce their security interests. Our Senior Credit Facility will mature in May 2020, and we cannot assure that we will be able to negotiate a new credit arrangement on commercially reasonable terms.

We depend on the accuracy of data in our information management systems, which subjects us to risks.

We depend on the accuracy and timeliness of our information management systems for billing, collections, consumption and other important data. We rely on many internal and external sources for this information, including:


—	our marketing, pricing and customer operations functions; and


—	various local regulated utilities and ISOs for volume or meter read information, certain billing rates and billing types (e.g., budget billing) and other fees and expenses.

Inaccurate or untimely information, which may be outside of our direct control, could result in:


—	inaccurate and/or untimely bills sent to customers;


—	incorrect tax remittances;


—	reduced effectiveness and efficiency of our operations;


—	inability to adequately hedge our portfolio;


—	increased overhead costs;


—	inaccurate accounting and reporting of customer revenues, gross margin and accounts receivable activity;


—	inaccurate measurement of usage rates, throughput and imbalances;


—	customer complaints; and


—	increased regulatory scrutiny.

We are also subject to disruptions in our information management systems arising out of events beyond our control, such as natural disasters, epidemics, failures in hardware or software, power fluctuations, telecommunications 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 successful 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 remedial action, heightened regulatory scrutiny, diminished customer confidence and damage to our reputation. Although we maintain cyber-liability insurance that covers certain damage caused by cyber events, it may not be sufficient to cover us in all circumstances.

Our success depends on key members of our management, the loss of whom could disrupt our business operations.

We depend on the continued employment and performance of key management personnel. A number of our senior executives have substantial experience in consumer and energy markets that have undergone regulatory restructuring and have extensive risk management and hedging expertise. We believe their experience is important to our continued success. We do not maintain key life insurance policies for our executive officers. Our key executives may not continue in their present roles and may not be adequately replaced.

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We rely on a third party vendor for our customer billing and transactions platform that exposes us to third party performance risk.

We have outsourced our back office customer billing and transactions functions to a third party, and we rely heavily on the continued performance of that vendor under the outsourcing agreement. Our vendor may fail to operate in accordance with the terms of the outsourcing agreement or a bankruptcy or other event may prevent it from performing under our outsourcing agreement.

A large portion of our current customers are concentrated in a limited number of states, making us vulnerable to customer concentration risks.

As of December 31, 2018, approximately 62% of our RCEs were located in five states. Specifically, 16%, 14%, 12%, 11% and 9% of our customers on an RCE basis were located in NY, MA, PA, CT and ME, respectively. If we are unable to increase our market share across other competitive markets or enter into new competitive markets effectively, we may be subject to continued or greater customer concentration risk. The states that contain a large percentage of our customers could reverse regulatory restructuring or change the regulatory environment in a manner that causes us to be unable to economically operate in that state.

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

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

Our access to marketing channels may be contingent upon the viability of our telemarketing and door-to-door agreements with our vendors.

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

Our vendors may expose us to risks.

We are subject to reputational risks that may arise from the actions of our vendors and their independent contractors that are wholly or partially beyond our control, such as violations of our marketing policies and procedures as well as any failure to comply with applicable laws and regulations. If our vendors engage in marketing practices that are

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not in compliance with local laws and regulations, we may be in breach of applicable laws and regulations that may result in regulatory proceedings, disadvantageous conditioning of our energy retailer license, or the revocation of our energy retailer license. Unauthorized activities in connection with sales efforts by agents of our vendors, including calling consumers in violation of the TCPA and predatory door-to-door sales tactics and fraudulent misrepresentation could subject us to class action lawsuits against which we will be required to defend. Such defense efforts will be costly and time consuming. In addition, the independent contractors of our vendors may consider us to be their employer and seek compensation.

Risks Related to Our Capital Stock

We cannot assure you that we will be able to continue paying our targeted quarterly dividend to the holders of our Class A common stock or dividends to the holders of our Series A Preferred Stock in the future.

The amount of our cash available for distribution principally depends upon the amount of cash we generate from our operations, which fluctuates from quarter to quarter based on, among other things:


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


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


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


—	seasonal variations in revenues generated by our business;


—	our debt service requirements and other liabilities;


—	fluctuations in our working capital needs;


—	our ability to borrow funds and access capital markets;


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

— management of customer credit risk;


—	abrupt changes in regulatory policies; and,


—	other business risks affecting our cash flows.

As a result of these and other factors, we cannot guarantee that we will have sufficient cash generated from operations to pay the dividends on our Series A Preferred Stock or to pay a specific level of cash dividends to holders of our Class A common stock.

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

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

Finally, dividends to holders of our Class A common stock are paid at the discretion of our board of directors. Our board of directors may decrease the level of or entirely discontinue payment of dividends.

We could be prevented from paying cash dividends on the Class A common stock and Series A Preferred Stock.

Holders of shares of Class A common stock and Series A Preferred Stock do not have a right to dividends on such shares unless declared or set aside for payment by our board of directors. Under Delaware law, cash dividends on capital stock may only be paid from “surplus” or, if there is no “surplus,” from the corporation’s net profits for the

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then-current or the preceding fiscal year. Unless we operate profitably, our ability to pay cash dividends on the Class A common stock and Series A Preferred Stock would require the availability of adequate “surplus,” which is defined as the excess, if any, of net assets (total assets less total liabilities) over capital. Our business may not generate sufficient cash flow from operations to enable us to pay dividends on the Series A Preferred Stock when payable, and quarterly dividends on the Class A common stock. Further, even if adequate surplus is available to pay cash dividends on the Class A common stock and Series A Preferred Stock, we may not have sufficient cash to pay dividends on the Class A common stock or Series A Preferred Stock.

Furthermore, no dividends on Class A common stock or Series A Preferred Stock shall be authorized by our board of directors or paid, declared or set aside for payment by us at any time when the authorization, payment, declaration or setting aside for payment would be unlawful under Delaware law or any other applicable law, or when the terms and provisions of any documents limiting the payment of dividends prohibit the authorization, payment, declaration or setting aside for payment thereof or would constitute a breach or a default under such document.

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

We are a holding company and have no material assets other than our equity interest in Spark HoldCo, and have no independent means of generating revenue. Spark HoldCo or its subsidiaries may be restricted from making distributions to us under applicable law or regulation or under the terms of their financing arrangements, or may otherwise be unable to provide such funds.

The Class A common stock and Series A Preferred Stock are subordinated to our existing and future debt obligations.

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

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

Numerous factors may affect the trading price of the Class A common stock and Series A Preferred Stock.

The trading price of the Class A common stock and Series A Preferred Stock may depend on many factors, some of which are beyond our control, including:


—	prevailing interest rates;


—	the market for similar securities;

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— general economic and financial market conditions;

— our issuance of debt or other preferred equity securities; and


—	our financial condition, results of operations and prospects.

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

In addition, over the last several years, prices of equity securities in the U.S. trading markets have been experiencing extreme price fluctuations. As a result of these and other factors, investors holding our Class A common stock and Series A Preferred Stock may experience a decrease in the value of their securities, which could be substantial and rapid, and could be unrelated to our financial condition, performance or prospects.

There may not be an active trading market for the Class A common stock or Series A Preferred Stock, which may in turn reduce the market value and your ability to transfer or sell your shares of Class A common stock or Series A Preferred Stock.

There are no assurances that there will be an active trading market for our Class A common stock or Series A Preferred Stock. The liquidity of any market for the Class A common stock and Series A Preferred Stock depends upon the number of stockholders, our results of operations and financial condition, the market for similar securities, the interest of securities dealers in making a market in the Class A common stock and Series A Preferred Stock, and other factors. To the extent that an active trading market is not maintained, the liquidity and trading prices for the Class A common stock and Series A Preferred Stock may be harmed.

Furthermore, because the Series A Preferred Stock does not have any stated maturity and is not subject to any sinking fund or mandatory redemption, stockholders seeking liquidity will be limited to selling their respective shares of Series A Preferred Stock in the secondary market. Active trading markets for the Series A Preferred Stock may not exist at such times, in which case the trading price of your shares of our Series A Preferred Stock could be reduced and your ability to transfer such shares could be limited.

Our Founder holds a substantial majority of the voting power of our common stock.

Holders of Class A and Class B common stock vote together as a single class on all matters presented to our stockholders for their vote or approval, except as otherwise required by applicable law or our certificate of incorporation and bylaws. Our Founder controls 66.1% of the combined voting power of the Class A and Class B common stock as of December 31, 2018 through his direct and indirect ownership in us.

Affiliated owners are entitled to act separately with respect to their investment in us, and they have the ability to elect all of the members of our board of directors, and thereby to control our management and affairs. In addition, affiliates are able to determine the outcome of all matters requiring Class A common stock and Class B common stock shareholder approval, including mergers and other material transactions, and is able to cause or prevent a change in the composition of our board of directors or a change in control of our company that could deprive our stockholders of an opportunity to receive a premium for their Class A common stock as part of a sale of our company. The existence of a significant shareholder, such as our Founder, may also have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other stockholders to approve transactions that they may deem to be in the best interests of our company.

So long as affiliates continue to control a significant amount of our common stock, they will continue to be able to strongly influence all matters requiring shareholder approval, regardless of whether other stockholders believe that a potential transaction is in their own best interests. In any of these matters, the interests of affiliates may differ or

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conflict with the interests of our other stockholders. Moreover, this concentration of stock ownership may also adversely affect the trading price of our Class A common stock or Series A Preferred Stock to the extent investors perceive a disadvantage in owning stock of a company with a controlling shareholder.

Holders of Series A Preferred Stock have extremely limited voting rights.

Voting rights of holders of shares of Series A Preferred Stock are extremely limited. Our Class A common stock and our Class B common stock are the only classes of our securities carrying full voting rights. Holders of the Series A Preferred Stock generally have no voting rights.

We are a “controlled company” under NASDAQ Global Select Market rules, and as such we are entitled to an exemption from certain corporate governance standards of the NASDAQ Global Select Market, and you may not have the same protections afforded to shareholders of companies that are subject to all of the NASDAQ Global Market corporate governance requirements.

We qualify as a “controlled company” within the meaning of NASDAQ Global Select Market corporate governance standards because an affiliated holder controls more than 50% of our voting power. Under NASDAQ Global Select Market rules, a company of which more than 50% of the voting power is held by an individual, a group or another company is a “controlled company” and may elect not to comply with certain corporate governance requirements.

In light of our status as a controlled company, our board of directors has determined to take partial advantage of the controlled company exemption. Our board of directors has determined not to have a nominating and corporate governance committee and that our compensation committee will not consist entirely of independent directors. As a result, non-independent directors may among other things, appoint future members of our board of directors, resolve corporate governance issues, establish salaries, incentives and other forms of compensation for officers and other employees and administer our incentive compensation and benefit plans.

Accordingly, you may not have the same protections afforded to shareholders of companies that are subject to all of NASDAQ Global Select Market corporate governance requirements.

We engage in transactions with our affiliates and expect to do so in the future. The terms of such transactions and the resolution of any conflicts that may arise may not always be in our or our stockholders’ best interests.

We have engaged in transactions and expect to continue to engage in transactions with affiliated companies. We have acquired companies and books of customers from our affiliates and may do so in the future. We will continue to enter into back-to-back transactions for purchases of commodities and derivatives on behalf of our affiliate. We will also continue to pay certain expenses on behalf of several of our affiliates for which we will seek reimbursement. We will also continue to share our corporate headquarters with certain affiliates. We cannot assure that our affiliates will reimburse us for the costs we have incurred on their behalf or perform their obligations under any of these contracts.

Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our Class A common stock.

Our amended and restated certificate of incorporation authorizes our board of directors to issue preferred stock without shareholder approval. On October 7, 2016, we filed a registration statement under the Securities Act on Form S-3 allowing us to offer and sell, from time to time, shares of preferred stock. The registration statement was declared effective on October 20, 2016. The election by our board of directors to issue preferred stock with anti-takeover provisions could make it more difficult for a third party to acquire us.

In addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be

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beneficial to our stockholders. Among other things, our amended and restated certificate of incorporation and amended and restated bylaws:

—

provide for our board of directors to be divided into three classes of directors, with each class as nearly equal in number as possible, serving staggered three year terms. Our staggered board may tend to discourage a third party from making a tender offer or otherwise attempting to obtain control of us, because it generally makes it more difficult for shareholders to replace a majority of the directors;


—	provide that the authorized number of directors may be changed only by resolution of the board of directors;


—	provide that all vacancies in our board, including newly created directorships, may, except as otherwise required by law or, if applicable, the rights of holders of a series of preferred stock, be filled by the affirmative vote of a majority of directors then in office, even if less than a quorum;

—

provide our board of directors the ability to authorize undesignated preferred stock. This ability makes it possible for our board of directors to issue, without shareholder approval, preferred stock with voting or other rights or preferences that could impede the success of any attempt to change control of us. These and other provisions may have the effect of deferring hostile takeovers or delaying changes in control or management of our company;

—

provide that at any time after the first date upon which W. Keith Maxwell III no longer beneficially owns more than fifty percent of the outstanding Class A common stock and Class B common stock, any action required or permitted to be taken by the shareholders must be effected at a duly called annual or special meeting of shareholders and may not be effected by any consent in writing in lieu of a meeting of such shareholders, subject to the rights of the holders of any series of preferred stock with respect to such series (prior to such time, such actions may be taken without a meeting by written consent of holders of the outstanding stock having not less than the minimum number of votes that would be necessary to authorize or take such action at a meeting);

—

provide that at any time after the first date upon which W. Keith Maxwell III no longer beneficially owns more than fifty percent of the outstanding Class A common stock and Class B common stock, special meetings of our shareholders may only be called by the board of directors, the chief executive officer or the chairman of the board (prior to such time, special meetings may also be called by our Secretary at the request of holders of record of fifty percent of the outstanding Class A common stock and Class B common stock);


—	provide that our amended and restated certificate of incorporation and amended and restated bylaws may be amended by the affirmative vote of the holders of at least two-thirds of our outstanding stock entitled to vote thereon;


—	provide that our amended and restated bylaws can be amended by the board of directors; and

—

establish advance notice procedures with regard to shareholder proposals relating to the nomination of candidates for election as directors or new business to be brought before meetings of our shareholders. These procedures provide that notice of shareholder proposals must be timely given in writing to our corporate secretary prior to the meeting at which the action is to be taken. These requirements may preclude shareholders from bringing matters before the shareholders at an annual or special meeting.

In addition, in our amended and restated certificate of incorporation, we have elected not to be subject to the provisions of Section 203 of the Delaware General Corporation Law (the “DGCL”) regulating corporate takeovers until the date on which W. Keith Maxwell III no longer beneficially owns in the aggregate more than fifteen percent of the outstanding Class A common stock and Class B common stock. On and after such date, we will be subject to the provisions of Section 203 of the DGCL.

In addition, certain change of control events have the effect of accelerating the payment due under our Tax Receivable Agreement, which could be substantial and accordingly serve as a disincentive to a potential acquirer of our company.

Our amended and restated certificate of incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our

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stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.

Our amended and restated certificate of incorporation provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim against us or any director or officer or other employee of ours arising pursuant to any provision of the DGCL, our amended and restated certificate of incorporation or our bylaws, or (iv) any action asserting a claim against us or any director or officer or other employee of ours that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of our amended and restated certificate of incorporation described in the preceding sentence. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our amended and restated certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.

Future sales of our Class A common stock and Series A Preferred Stock in the public market could reduce the price of the Class A common stock and Series A Preferred Stock, and may dilute your ownership in us.

On October 7, 2016, we filed a registration statement under the Securities Act on Form S-3 registering the primary offer and sale, from time to time, of Class A common stock, preferred stock, depositary shares and warrants. The registration statement also registers the Class A common stock held by our affiliates, Retailco and NuDevco (including Class A common stock that may be obtained upon conversion of Class B common stock). All of the shares of Class A common stock held by Retailco and NuDevco and registered on the registration statement may be immediately resold. The registration statement was declared effective on October 20, 2016.

We cannot predict the size of future issuances of our Class A common stock or securities convertible into Class A common stock or the effect, if any, that future issuances or sales of shares of our Class A common stock will have on the market price of our Class A common stock. Sales of substantial amounts of our Class A common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our Class A common stock.

We may also in the future sell additional shares of preferred stock, including shares of Series A Preferred Stock, on terms that may differ from those we have previously issued. Such shares could rank on parity with or, subject to the voting rights referred to above (with respect to issuances of new series of preferred stock), senior to the Series A Preferred Stock as to distribution rights or rights upon liquidation, winding up or dissolution. The subsequent issuance of additional shares of Series A Preferred Stock, or the creation and subsequent issuance of additional classes of preferred stock on parity with the Series A Preferred Stock, could dilute the interests of the holders of Series A Preferred Stock, and could affect our ability to pay distributions on, redeem or pay the liquidation preference on the Series A Preferred Stock. Any issuance of preferred stock that is senior to the Series A Preferred Stock would not only dilute the interests of the holders of Series A Preferred Stock, but also could affect our ability to pay distributions on, redeem or pay the liquidation preference on the Series A Preferred Stock.

Furthermore, subject to compliance with the Securities Act or exemptions therefrom, employees who have received Class A common stock as equity awards may also sell their shares into the public market.

We will be required to make payments under a Tax Receivable Agreement with our Founder for certain tax benefits we may claim, and the amounts of such payments could be significant.

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We are party to a Tax Receivable Agreement ("Tax Receivable Agreement" or "TRA") that generally provides for the payment by us to our Founder of 85% of the net cash savings, if any, in U.S. federal, state and local income tax or franchise tax that we actually realize (or are deemed to realize in certain circumstances) in future periods as a result of (i) any tax basis increase resulting from the purchase by us of units of our subsidiary from affiliates of our Founder, (ii) any tax basis increases resulting from the exchange of these units for shares of Class A common stock pursuant to the Exchange Right (or resulting from an exchange of units for cash pursuant to a Cash Option) and (iii) any imputed interest deemed to be paid by us as a result of, and additional tax basis arising from, any payments we make under the Tax Receivable Agreement. In addition, payments we make under the Tax Receivable Agreement will be increased by any interest accrued from the due date (without extensions) of the corresponding tax return. We retain the benefit of the remaining 15% of these tax savings. See Note 13 "Income Taxes" for further discussion.

We may be required to defer or partially defer any payment due to holders of rights under the Tax Receivable Agreement in certain circumstances during the five-year period commencing on October 1, 2014. Following the expiration of the five-year deferral period, we will be obligated to pay any outstanding deferred TRA Payments. While this payment obligation is subject to certain limitations, the obligation may nevertheless be significant and could adversely affect our liquidity and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock. As of December 31, 2018, we had no outstanding deferred TRA payments.

The payment obligations under the Tax Receivable Agreement are obligations of Spark Energy, Inc. and not obligations of Spark HoldCo. For purposes of the Tax Receivable Agreement, cash savings in tax generally are calculated by comparing our actual tax liability to the amount we would have been required to pay had we not been able to utilize any of the tax benefits subject to the Tax Receivable Agreement. The term of the Tax Receivable Agreement continues until all such tax benefits have been utilized or expired, unless we exercise our right to terminate the Tax Receivable Agreement by making the termination payment specified in the agreement.

The actual increase in tax basis, as well as the amount and timing of any payments under the Tax Receivable Agreement, will vary depending upon a number of factors, including the timing of the exchanges of Spark HoldCo units, the price of Class A common stock at the time of each exchange, the extent to which such exchanges are taxable, the amount and timing of the taxable income we generate in the future and the tax rate then applicable, and the portion of our payments under the Tax Receivable Agreement constituting imputed interest or depletable, depreciable or amortizable basis. We expect that the payments that we will be required to make under the Tax Receivable Agreement could be substantial.

The payments under the Tax Receivable Agreement will not be conditioned upon a holder of rights under the Tax Receivable Agreement having a continued ownership interest in either Spark HoldCo or us.

During 2018, we made the payments required under the TRA for the 2015, 2016 and 2017 tax years. See Note 15 "Transactions with Affiliates" for a discussion of amounts paid and accrued under the TRA.

In certain cases, payments under the Tax Receivable Agreement may be accelerated and/or significantly exceed the actual benefits, if any, we realize in respect of the tax attributes subject to the Tax Receivable Agreement.

If we elect to terminate the Tax Receivable Agreement early or it is terminated early due to certain mergers or other changes of control, we would be required to make an immediate payment equal to the present value of the anticipated future tax benefits subject to the Tax Receivable Agreement, which calculation of anticipated future tax benefits will be based upon certain assumptions and deemed events set forth in the Tax Receivable Agreement, including the assumption that we have sufficient taxable income to fully utilize such benefits and that any Spark HoldCo units that Retailco, LLC, NuDevco Retail, or their permitted transferees own on the termination date are deemed to be exchanged on the termination date. Any early termination payment may be made significantly in advance of the actual realization, if any, of such future benefits.

In these situations, our obligations under the Tax Receivable Agreement could have a substantial negative impact on our liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, other forms

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of business combinations or other changes of control due to the additional transaction cost a potential acquirer may attribute to satisfying such obligations. For example, if the Tax Receivable Agreement had been terminated as of December 31, 2018, the estimated contractual termination payment would be approximately $33.8 million (calculated using a discount rate equal to the London Inter-Bank Offered Rate ("LIBOR"), plus 200 basis points). The foregoing number is merely an estimate and the actual payment could differ materially. There can be no assurance that we will be able to finance our obligations under the Tax Receivable Agreement.

Payments under the Tax Receivable Agreement will be based on the tax reporting positions that we will determine. The holders of rights under the Tax Receivable Agreement will not reimburse us for any payments previously made under the Tax Receivable Agreement if such basis increases or other benefits are subsequently disallowed, except that excess payments made to any such holder will be netted against payments otherwise to be made, if any, to such holder after our determination of such excess. As a result, in such circumstances, we could make payments that are greater than our actual cash tax savings, if any, and may not be able to recoup those payments, which could adversely affect our liquidity.

We have issued preferred stock and may continue to do so, and the terms of such preferred stock could adversely affect the voting power or value of our Class A common stock.

Our certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our Class A common stock with respect to dividends and distributions, as our board of directors may determine. Through December 31, 2018, we have issued an aggregate of 3,707,256 shares of Series A Preferred Stock.

The terms of the preferred stock we offer or sell could adversely impact the voting power or value of our Class A common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock, such as the Series A Preferred Stock, could affect the residual value of the Class A common stock.

For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements, including those relating to accounting standards and disclosure about our executive compensation, that apply to other public companies.

In April 2012, the Jumpstart Our Business Startups Act (the "JOBS Act") was signed into law. We are classified as an “emerging growth company” under the JOBS Act. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things, (i) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act, (ii) comply with any new requirements adopted by the PCAOB requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer, (iii) provide certain disclosure regarding executive compensation required of larger public companies or (iv) hold nonbinding advisory votes on executive compensation. We will remain an "emerging growth company" until as late as the last day of our 2019 fiscal year. After we cease to be an "emerging growth company," we may incur significant additional expense and devote substantial management effort toward ensuring compliance with the requirements applicable to companies that are not "emerging growth companies," including Section 404(b) of the Sarbanes-Oxley Act.

As a result of our election to avail ourselves of certain provisions of the JOBS Act, the information that we provide may be different than what you may receive from other public companies in which you hold an equity interest. To the extent that we rely on any of the exemptions available to emerging growth companies, you will receive less information about our executive compensation and internal control over financial reporting than issuers that are not emerging growth companies. If some investors find our securities to be less attractive as a result, there may be a less active trading market for our securities and the price may be more volatile.

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Our amended and restated certificate of incorporation limits the fiduciary duties of one of our directors and certain of our affiliates and restricts the remedies available to our stockholders for actions taken by our Founder or certain of our affiliates that might otherwise constitute breaches of fiduciary duty.

Our amended and restated certificate of incorporation contains provisions that we renounce any interest in existing and future investments in other entities by, or the business opportunities of, NuDevco Partners, LLC, NuDevco Partners Holdings, LLC and W. Keith Maxwell III, or any of their officers, directors, agents, shareholders, members, affiliates and subsidiaries (other than a director or officer who is presented an opportunity solely in his capacity as a director or officer). Because of this provision, these persons and entities have no obligation to offer us those investments or opportunities that are offered to them in any capacity other than solely as an officer or director. If one of these persons or entities pursues a business opportunity instead of presenting the opportunity to us, we will not have any recourse against such person or entity for a breach of fiduciary duty.

The Series A Preferred Stock represent perpetual equity interests in us, and investors should not expect us to redeem the Series A Preferred Stock on the date the Series A Preferred Stock becomes redeemable by us or on any particular date afterwards.

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

The Series A Preferred Stock is not rated.

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

The Change of Control Conversion Right may make it more difficult for a party to acquire us or discourage a party from acquiring us.

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

If we are unable to redeem the Series A Preferred Stock on or after April 15, 2022, a substantial increase in the Three-Month LIBOR Rate could negatively impact our ability to pay dividends on the Series A Preferred Stock and Class A common stock.

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If we do not repurchase or redeem our Series A Preferred Stock on or after April 15, 2022, a substantial increase in the Three-Month LIBOR Rate could negatively impact our ability to pay dividends on the Series A Preferred Stock. An increase in the dividends payable on our Series A Preferred Stock would negatively impact dividends on our Class A common stock. We cannot assure you that we will have adequate sources of capital to repurchase or redeem the Series A Preferred Stock on or after April 15, 2022. If we are unable to repurchase or redeem the Series A Preferred Stock and our ability to pay dividends on the Series A Preferred Stock and Class A common stock is negatively impacted, the market value of the Series A Preferred Stock and Class A common stock could be materially adversely impacted.

We may not have sufficient earnings and profits in order for dividends on the Series A Preferred Stock to be treated as dividends for U.S. federal income tax purposes.

The dividends payable by us on the Series A Preferred Stock may exceed our current and accumulated earnings and profits, as calculated for U.S. federal income tax purposes. If this occurs, it will result in the amount of the dividends that exceed such earnings and profits being treated for U.S. federal income tax purposes first as a return of capital to the extent of the beneficial owner’s adjusted tax basis in the Series A Preferred Stock, and the excess, if any, over such adjusted tax basis as capital gain. Such treatment will generally be unfavorable for corporate beneficial owners and may also be unfavorable to certain other beneficial owners.

You may be subject to tax if we make or fail to make certain adjustments to the conversion rate of the Series A Preferred Stock even though you do not receive a corresponding cash dividend.

The Conversion Rate as defined in the Certificate of Designation for the Series A Preferred Stock is subject to adjustment in certain circumstances. A failure to adjust (or to adjust adequately) the Conversion Rate after an event that increases your proportionate interest in us could be treated as a deemed taxable dividend to you. If you are a non-U.S. holder, any deemed dividend may be subject to U.S. federal withholding tax at a 30% rate, or such lower rate as may be specified by an applicable treaty, which may be set off against subsequent payments on the Series A Preferred Stock. In April 2016, the Internal Revenue Service issued new proposed income tax regulations in regard to the taxability of changes in conversion rights that will apply to the Series A Preferred Stock when published in final form and may be applied to us before final publication in certain instances.

Item 1B. Unresolved Staff Comments

None.

Item 3. Legal Proceedings

We are the subject of lawsuits and claims arising in the ordinary course of business from time to time. Management cannot predict the ultimate outcome of such lawsuits and claims. While the lawsuits and claims are asserted for amounts that may be material, should an unfavorable outcome occur, management does not currently expect that any currently pending matters will have a material adverse effect on our financial position or results of operations except as described in Part II, Item 8 “Financial Statements and Supplementary Data,” Note 14 "Commitment and Contingencies" to the audited consolidated financial statements, which are incorporated herein by reference.

Item 4. Mine Safety Disclosures.

Not applicable.

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PART II

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

Our Class A common stock is traded on the NASDAQ Global Select Market under the symbol “SPKE." There is no public market for our Class B common stock. On February 28, 2019, 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.”

Dividends

We 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.

Recent Sales of Unregistered Equity Securities

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

Stock Performance Graph

The following graph compares, since the IPO, 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 July 29, 2014 (the date our Class A common stock began trading on the NASDAQ Global Select Market), and that all dividends were reinvested. The stock performance shown on the graph below is not indicative of future price performance.

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

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Item 6. Selected Financial Data

The following table sets forth selected historical financial information for each of the years in the five year period ended December 31, 2018. The information as of and for the years ended December 31, 2018, 2017 and 2016 is derived from the consolidated financial statements contained in this Form 10-K and should be read in conjunction with the information contained in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Financial Statements and Supplementary Data." Financial information as of and for the years ended December 31, 2015 and 2014 was derived from information filed as part of our 2017 and 2016 Form 10-Ks.



(in thousands, except per share and volumetric data)	Year Ended December 31,
(in thousands, except per share and volumetric data)	2018			2017			2016			2015			2014
Income Statement Data:
Total revenues	$	1,005,928		$	798,055		$	546,697		$	358,153		$	322,876
Operating (loss) income	(3,654		)	102,420			84,001			29,905			(3,841		)
Net (loss) income	(14,392		)	75,044			65,673			25,975			(4,265		)
Net (loss) income attributable to Non-Controlling Interests	(13,206		)	55,799			51,229			22,110			(4,211		)
Net (loss) income attributable to Spark Energy, Inc. stockholders	(1,186		)	19,245			14,444			3,865			(54		)
Net (loss) income attributable to stockholders of Class A common stock	(9,295		)	16,207			14,444			3,865			(54		)


Net (loss) income attributable to Spark Energy, Inc. per share of Class A common stock
Basic	$	(0.69	)	$	1.23		$	1.27		$	0.63		$	(0.01	)
Diluted	$	(0.69	)	$	1.21		$	1.11		$	0.53		$	(0.01	)

Weighted average common shares outstanding
Basic	13,390			13,143			11,402			6,129			6,000
Diluted	13,390			13,346			12,690			6,655			6,000

Balance Sheet Data:
Current assets	$	291,980		$	296,738		$	197,983		$	102,680		$	105,989
Current liabilities	$	141,951		$	151,027		$	184,056		$	84,188		$	92,816
Total assets	$	488,738		$	503,741		$	367,749		$	162,234		$	138,397
Long-term liabilities	$	165,735		$	152,446		$	67,438		$	44,727		$	21,463

Cash Flow Data:
Cash flows from operating activities	$	59,763		$	62,131		$	66,950		$	45,931		$	5,874
Cash flows used in investing activities	$	(18,981	)	$	(77,558	)	$	(33,489	)	$	(41,943	)	$	(3,040	)
Cash flows (used in) provided by financing activities	$	(20,563	)	$	25,886		$	(18,975	)	$	(3,873	)	$	(5,664	)

Other Financial Data:
Adjusted EBITDA ⁽¹⁾	$	70,716		$	102,884		$	81,892		$	36,869		$	11,324
Retail gross margin ⁽¹⁾	$	185,109		$	224,509		$	182,369		$	113,615		$	76,944
Distributions paid to Class B non-controlling unit holders and dividends paid to Class A common shareholders	$	(45,261	)	$	(43,319	)	$	(43,297	)	$	(20,043	)	$	(3,305	)

Other Operating Data:
RCEs (thousands)	908			1,042			774			415			326
Electricity volumes (MWh)	8,630,653			6,755,663			4,170,593			2,075,479			1,526,652
Natural gas volumes (MMBtu)	16,778,393			18,203,684			16,819,713			14,786,681			15,724,708

(1) Adjusted EBITDA and retail gross margin are non-GAAP financial measures. For a definition and reconciliation of each of Adjusted EBITDA and retail gross margin to their most directly comparable financial measures calculated and presented in accordance with GAAP, please see “Management's Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Performance Measures."

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the consolidated financial statements and the related notes thereto included elsewhere in this Annual Report. In this Annual Report, the terms “Spark Energy,” “Company,” “we,” “us” and “our” refer collectively to Spark Energy, 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 their 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, 2018, we operated in 94 utility service territories across 19 states and the District of Columbia.

Our business consists of two operating segments:

•

Retail Electricity Segment. In this segment, we purchase electricity supply through physical and financial transactions with market counterparts and ISOs and supply electricity to residential and commercial consumers pursuant to fixed-price and variable-price contracts. For the years ended December 31, 2018, 2017 and 2016, approximately 86%, 82% and 76%, 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, 2018, 2017 and 2016, approximately 14%, 18% and 24%, respectively, of our retail revenues were derived from the sale of natural gas. We also attempt to improve our profitability on natural gas by identifying and executing on wholesale natural gas arbitrage opportunities, which we refer to as asset optimization.

Recent Developments

Increase in Commitments Under Our Senior Credit Facility

On January 28, 2019, the Company and Co-Borrowers exercised the accordion feature in the Senior Credit Facility, bringing total commitments under the Senior Credit Facility to $217.5 million.

Residential Customer Equivalents

We measure our number of customers using residential customer equivalents ("RCEs"). The following table shows our RCEs by segment as of December 31, 2018, 2017 and 2016:



RCEs:
	December 31,
(In thousands)	2018	2017	2016
Retail Electricity	754	868	571
Retail Natural Gas	154	174	203
Total Retail	908	1,042	774

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The following table details our count of RCEs by geographical region as of December 31, 2018:



RCEs by Geographic Region:
(In thousands)	Electricity	% of Total	Natural Gas	% of Total	Total	% of Total
New England	345	46%	29	19%	374	41%
Mid-Atlantic	272	36%	56	36%	328	36%
Midwest	65	9%	49	32%	114	13%
Southwest	72	9%	20	13%	92	10%
Total	754	100%	154	100%	908	100%

The geographical regions noted above include the following states:


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


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


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


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

Across our market areas, we have operated under a number of different retail brands. During 2018, we began consolidating brands and billing systems. In 2019, we expect to further consolidate our brands and systems as we simplify our business.

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 customer growth strategy includes growing organically through traditional sales channels complemented by customer portfolio and business acquisitions. During 2018, we added a total of approximately 432,000 RCEs, of which 29,000 RCEs were added as part of the acquisitions of HIKO Energy, LLC ("HIKO"), 52,000 RCEs were added as a result of customer portfolio acquisitions from Starion Energy Inc. ("Starion") and from an affiliated company, and the remaining were added were through our organic sales channels.

Organic Sales

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.

Acquisitions

We acquire companies and portfolios of customers through both external and affiliated channels. In 2016, we acquired approximately 341,000 RCEs through our acquisitions of Provider Power, LLC ("Provider Power") and Major Energy Companies ("Major Energy"). In 2017, we acquired approximately 206,000 RCEs through

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acquisitions of Verde Energy USA Holdings, LLC ("Verde Energy"), Perigee Energy, LLC ("Perigee Energy"), and a customer portfolio. In 2018, we have added approximately 81,000 RCEs through our acquisitions of HIKO, a customer portfolio from an affiliate, and a customer portfolio from Starion.

Our ability to realize returns from acquisitions that are acceptable to us is dependent on our ability to successfully identify, negotiate for finance and integrate acquisitions.

RCE Activity

The following table shows our RCE activity during the years ended December 31, 2018, 2017 and 2016.



(In thousands)	Retail Electricity	Retail Natural Gas	Total	% Net Annual Increase (Decrease)
December 31, 2015	257	158	415
Additions	550	131	681
Attrition	(236)	(86)	(322)
December 31, 2016	571	203	774	87%
Additions	659	61	720
Attrition	(362)	(90)	(452)
December 31, 2017	868	174	1,042	35%
Additions	363	69	432
Attrition	(477)	(89)	(566)
December 31, 2018	754	154	908	(13)%

The increase of our RCE counts in 2016 and 2017 related to the acquisition of customers and businesses in excess of natural customer attrition during those years. In 2018, our attrition exceeded customer adds due to lower organic sales spending, fewer acquisitions and slightly higher attrition impacted by our brand consolidation activities and our intentional non-renewable of certain larger C&I customer contracts. Average monthly attrition rates during 2016, 2017, and 2018 were as follows:




	Year Ended	Quarter Ended
	December 31	December 31	September 30	June 30	March 31
2016	4.3%	4.8%	3.8%	4.1%	4.4%
2017	4.3%	4.9%	4.2%	4.1%	3.8%
2018	4.7%	6.7%	4.0%	3.7%	4.2%

Customer attrition occurs primarily as a result of: (i) customer initiated switches; (ii) residential moves and (iii) disconnection for customer payment defaults. Customer attrition during the year ended December 31, 2018 was slightly higher than the prior year due to brand consolidations and our intentional non-renewal of certain large C&I contracts.

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, 2018, customer acquisition costs were as follows:

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(In thousands)	2018		2017		2016
Customer Acquisition Costs	$	13,673	$	25,874	$	24,934

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

Customer Credit Risk

Approximately 66% of our revenues are derived from customers in utilities where customer credit risk is borne by the utility in exchange for a discount on amounts billed. Where we have customer credit risk, we record bad debt based on an estimate of uncollectible amounts. Our bad debt expense on non-POR revenues was as follows:



	Year Ended December 31
	2018		2017		2016
Total Non-POR Bad Debt as Percent of Revenue	2.6	%	2.5	%	0.6	%

During the year ended December 31, 2018, we experienced higher bad debt expense versus 2017 primarily as a result of our brand consolidations. During the year ended December 31, 2017, we experienced higher bad debt expense versus 2016 due to Hurricane Harvey, coupled with the fact that the year ended December 31, 2016 included a reversal of a portion of our bad debt reserve as a result of improved collection efforts.

To manage our current exposure, we have increased our focus on collection efforts and timely billing along with tighter credit requirements for new enrollments in non-POR markets

For the years ended December 31, 2018, 2017 and 2016, approximately 66%, 66% and 67%, 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, 2018, 2017 and 2016, all of these local regulated utility companies had investment grade ratings. During these same periods, we paid these local regulated utilities a weighted average discount of approximately 1.0%, 1.1% and 1.3%, 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 in which 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 contracts from time to time to protect us from 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

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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 results were a gain of $4.5 million, a loss of $0.7 million and a loss of $0.6 million for the years ended December 31, 2018, 2017 and 2016, respectively.

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Non-GAAP Performance Measures

We use the Non-GAAP performance measures of Adjusted EBITDA and Retail Gross Margin to evaluate and measure our operating results. These measures for the three years ended December 31, 2018 were as follows:



	Year Ended December 31,
(in thousands)	2018		2017		2016
Adjusted EBITDA	$	70,716	$	102,884	$	81,892
Retail Gross Margin	$	185,109	$	224,509	$	182,369

Adjusted EBITDA. We define “Adjusted EBITDA” as EBITDA less (i) customer acquisition costs incurred in the current period, plus or minus (ii) net gain (loss) 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.

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. Finally, we also 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 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; and


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

The GAAP measures most directly comparable to Adjusted EBITDA are net income and net cash provided by operating activities. The following table presents reconciliations of Adjusted EBITDA to these GAAP measures for each of the periods indicated.

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	Year Ended December 31,
(in thousands)	2018			2017			2016
Reconciliation of Adjusted EBITDA to Net Income:
Net (loss) income	$	(14,392	)	$	75,044		$	65,673
Depreciation and amortization	52,658			42,341			32,788
Interest expense	9,410			11,134			8,859
Income tax expense	2,077			38,765			10,426
EBITDA	49,753			167,284			117,746
Less:
Net, (Losses) gains on derivative instruments	(18,170		)	5,008			22,407
Net, Cash settlements on derivative instruments	(10,587		)	16,309			(2,146		)
Customer acquisition costs	13,673			25,874			24,934
Plus:
Non-cash compensation expense	5,879			5,058			5,242
Contract termination charge related to Major Energy Companies change of control	—			—			4,099
Change in Tax Receivable Agreement liability ⁽¹⁾	—			(22,267		)	—
Adjusted EBITDA	$	70,716		$	102,884		$	81,892

(1) Represents the change in the value of the Tax Receivable Agreement liability due to U.S. Tax Reform. See discussion in Note 13 "Income Taxes."



	Year Ended December 31,
(in thousands)	2018			2017			2016
Reconciliation of Adjusted EBITDA to net cash provided by operating activities:
Net cash provided by operating activities	$	59,763		$	62,131		$	66,950
Amortization of deferred financing costs	(1,291		)	(1,035		)	(668		)
Bad debt expense	(10,135		)	(6,550		)	(1,261		)
Interest expense	9,410			11,134			8,859
Income tax expense	2,077			38,765			10,426
Change in Tax Receivable Agreement liability ⁽¹⁾	—			(22,267		)	—
Changes in operating working capital
Accounts receivable, prepaids, current assets	10,482			31,905			12,135
Inventory	(674		)	718			542
Accounts payable and accrued liabilities	(5,093		)	(13,672		)	(17,653		)
Other	6,177			1,755			2,562
Adjusted EBITDA	$	70,716		$	102,884		$	81,892
Cash Flow Data:
Cash flows provided by operating activities	$	59,763		$	62,131		$	66,950
Cash flows used in investing activities	$	(18,981	)	$	(77,558	)	$	(33,489	)
Cash flows (used in) provided by financing activities	$	(20,563	)	$	25,886		$	(18,975	)

(1) Represents the change in the value of the Tax Receivable Agreement liability due to U.S. Tax Reform. See discussion in Note 13 "Income Taxes."

Retail Gross Margin. We define retail gross margin as operating income (loss) plus (i) depreciation and amortization expenses and (ii) general and administrative expenses, less (iii) net asset optimization revenues, (iv) net gains (losses) on non-trading derivative instruments, and (v) net current period cash settlements on non-

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trading derivative instruments. 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’ operating performance, retail gross margin should not be considered an alternative to, or more meaningful than, operating income (loss), 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 operating income. The following table presents a reconciliation of Retail Gross Margin to operating income for each of the periods indicated.



	Year Ended December 31,
(in thousands)	2018			2017			2016
Reconciliation of Retail Gross Margin to Operating (Loss) Income:
Operating (loss) income	$	(3,654	)	$	102,420		$	84,001
Plus:
Depreciation and amortization	52,658			42,341			32,788
General and administrative expense	111,431			101,127			84,964
Less:
Net asset optimization revenue (expense)	4,511			(717		)	(586		)
(Losses) gains on non-trading derivative instruments	(19,571		)	5,588			22,254
Cash settlements on non-trading derivative instruments	(9,614		)	16,508			(2,284		)
Retail Gross Margin	$	185,109		$	224,509		$	182,369
Retail Gross Margin - Retail Electricity Segment	$	124,668		$	158,468		$	118,136
Retail Gross Margin - Retail Natural Gas Segment	$	60,441		$	66,041		$	64,233

Our non-GAAP financial measures of Adjusted EBITDA and Retail Gross Margin should not be considered as alternatives to net (loss) income, net cash provided by operating activities, or operating (loss) income. Adjusted EBITDA and Retail Gross Margin are not presentations made in accordance with GAAP and have limitations as analytical tools. You should not consider Adjusted EBITDA or Retail Gross Margin in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA and Retail Gross Margin exclude some, but not all, items that affect net (loss) income, net cash provided by operating activities, and operating (loss) income, and are defined differently by different companies in our industry, our definition of Adjusted EBITDA and Retail Gross Margin may not be comparable to similarly titled measures of other companies.

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

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Consolidated Results of Operations



(In Thousands)	Year Ended December 31,
	2018			2017			2016
Revenues:
Retail revenues	$	1,001,417		$	798,772		$	547,283
Net asset optimization revenues (expenses)	4,511			(717		)	(586		)
Total Revenues	1,005,928			798,055			546,697
Operating Expenses:
Retail cost of revenues	845,493			552,167			344,944
General and administrative expense	111,431			101,127			84,964
Depreciation and amortization	52,658			42,341			32,788
Total Operating Expenses	1,009,582			695,635			462,696
Operating (loss) income	(3,654		)	102,420			84,001
Other (expense)/income:
Interest expense	(9,410		)	(11,134		)	(8,859		)
Change in Tax Receivable Agreement liability⁽¹⁾	—			22,267			—
Interest and other income	749			256			957
Total other (expenses)/income	(8,661		)	11,389			(7,902		)
(Loss) income before income tax expense	(12,315		)	113,809			76,099
Income tax expense	2,077			38,765			10,426
Net (loss) income	$	(14,392	)	$	75,044		$	65,673
Other Performance Metrics:
Adjusted EBITDA ⁽²⁾	$	70,716		$	102,884		$	81,892
Retail Gross Margin ⁽²⁾	185,109			224,509			182,369
Customer Acquisition Costs	13,673			25,874			24,934
RCE Attrition	4.7		%	4.3		%	4.3		%
Distributions paid to Class B non-controlling unit holders and dividends paid to Class A common shareholders	$	(45,261	)	$	(43,319	)	$	(43,297	)

(1) Represents the change in the value of the Tax Receivable Agreement liability due to U.S. Tax Reform. See discussion in Note 13 "Income Taxes."

(2) 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 financial measures presented in accordance with GAAP.

Total Revenues. Total revenues for the year ended December 31, 2018 were approximately $1,005.9 million, an increase of approximately $207.8 million, or 26%, from approximately $798.1 million for the year ended December 31, 2017. This increase was primarily due to an increase in electricity volumes driven by the acquisitions of the HIKO and two customer portfolios, full year results from the Verde Companies, and higher-than-normal electricity and natural gas pricing in 2018, partially offset by a decrease in natural gas volumes due to warmer-than-normal weather in the second and third quarters of 2018. Total revenues for the year ended December 31, 2017 increased approximately $251.4 million, or 46%, from approximately $546.7 million for the year ended December 31, 2016. This increase was primarily due to an increase in electricity and natural gas volumes driven by full year results of the Major Energy Companies and the Provider Companies which were both acquired in 2016, and by the acquisition of the Verde Companies during 2017, partially offset by decreased electricity pricing.

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Analysis of the impact of changes in prices and volumes between the years ended December 31, 2018, 2017 and 2016 are as follows:



	2018 vs. 2017			2017 vs. 2016
Change in electricity volumes sold	$	182.5		$	258.6
Change in natural gas volumes sold	(11.1		)	10.7
Change in electricity unit revenue per MWh	23.4			(18.2		)
Change in natural gas unit revenue per MMBtu	7.9			0.4
Change in net asset optimization revenue (expense)	5.1			(0.1		)
Change in total revenues	$	207.8		$	251.4

Retail Cost of Revenues. Total retail cost of revenues for the year ended December 31, 2018 was approximately $845.5 million, an increase of approximately $293.3 million, or 53%, from approximately $552.2 million for the year ended December 31, 2017. This increase was primarily due to an increase in electricity volumes driven by the acquisitions of HIKO and two customer portfolios, full year results from the Verde Companies, higher-than-normal electricity and natural gas prices due to the extreme unpredictable weather in the first quarter of 2018, increased capacity costs in the second and third quarter of 2018, and additional hedges in ERCOT in the third quarter of 2018. Total retail cost of revenues for the year ended December 31, 2017 increased approximately $207.3 million, or 60%, from approximately $344.9 million for the year ended December 31, 2016. This increase was primarily due to additional volumes driven by full year results of the Major Energy Companies and the Provider Companies, and the acquisition of the Verde Companies, which resulted in higher electricity and natural gas supply costs, offset by a decrease in the value of our retail derivative portfolio.

Analysis of the impact of changes in prices and volumes between the years ended December 31, 2018, 2017, and 2016 are as follows:



	2018 vs. 2017			2017 vs. 2016
Change in electricity volumes sold	$	138.5		$	185.4
Change in natural gas volumes sold	(5.9		)	5.4
Change in electricity unit cost per MWh	101.2			14.6
Change in natural gas unit cost per MMBtu	8.2			4.0
Change in value of retail derivative portfolio	51.3			(2.1		)
Change in retail cost of revenues	$	293.3		$	207.3

General and Administrative Expense. General and administrative expense for the year ended December 31, 2018 was approximately $111.4 million, an increase of approximately $10.3 million, or 10%, as compared to $101.1 million for the year ended December 31, 2017. This increase was primarily attributable to reductions in the fair value of earnout liabilities, which decreased general and administrative expenses in 2017 to a greater extent than in 2018, increased commissions paid to commercial brokers, and variable costs associated with increased RCEs from our acquisitions. General and administrative expense for the year ended December 31, 2017 increased approximately $16.1 million or 19%, as compared to $85.0 million for the year ended December 31, 2016. This increase was primarily due to increased billing and other variable costs associated with increased RCEs, including those added as a result of full year results of the Major Energy Companies and the Provider Companies and the acquisition of the Verde Companies, as well as costs related to the acquisition of customers by the Verde Companies that we do not capitalize, partially offset by a net decrease in fair value of earnout liabilities, which decreased general and administrative expenses.

Depreciation and Amortization Expense. Depreciation and amortization expense for the year ended December 31, 2018 was approximately $52.7 million, an increase of approximately $10.4 million, or 24%, from approximately $42.3 million for the year ended December 31, 2017. This increase was primarily due to the increased amortization expense associated with customer relationship intangibles from the acquisitions of the Verde Companies, HIKO and customers from an affiliate, and the write-off of assets no longer in use as a result of integration activities.

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Depreciation and amortization expense for the year ended December 31, 2017 increased approximately $9.5 million, or 29%, from approximately $32.8 million for the year ended December 31, 2016. This increase was primarily due to the increased amortization expense associated with customer intangibles from full year results of the Major Energy Companies and the Provider Companies and the acquisition of the Verde Companies.

Customer Acquisition Cost. Customer acquisition cost for the year ended December 31, 2018 was approximately $13.7 million, a decrease of approximately $12.2 million, or 47% from approximately $25.9 million for the year ended December 31, 2017. This decrease was primarily due to a decrease in the number of organic sales in 2018 as we were more focused on acquisitions of businesses, customer portfolio additions, and integration. Customer acquisition cost for the year ended December 31, 2017 increased approximately $1.0 million, or 4% from approximately $24.9 million for the year ended December 31, 2016. This increase was primarily due to customer acquisition costs of the Major Energy Companies, the Provider Companies and Verde Companies offset by decreased organic sales in the second half of the year as we devoted resources to the acquisition and integration of the Verde Companies.

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Operating Segment Results



	Year Ended December 31,
	2018			2017		2016
	(in thousands, except volume and per unit operating data)
Retail Electricity Segment
Total Revenues	$	863,451		$	657,566	$	417,229
Retail Cost of Revenues	762,771			477,012		286,795
Less: Net (Losses) Gains on non-trading derivatives, net of cash settlements	(23,988		)	22,086		12,298
Retail Gross Margin ⁽¹⁾—Electricity	$	124,668		$	158,468	$	118,136
Volumes—Electricity (MWhs)	8,630,653			6,755,663		4,170,593
Retail Gross Margin ⁽²⁾—Electricity per MWh	$	14.44		$	23.46	$	28.33

Retail Natural Gas Segment
Total Revenues	$	137,966		$	141,206	$	130,054
Retail Cost of Revenues	82,722			75,155		58,149
Less: Net (Losses) Gains on non-trading derivatives, net of cash settlements	(5,197		)	10		7,672
Retail Gross Margin ⁽¹⁾ —Gas	$	60,441		$	66,041	$	64,233
Volumes—Gas (MMBtus)	16,778,393			18,203,684		16,819,713
Retail Gross Margin ⁽²⁾ —Gas per MMBtu	$	3.60		$	3.63	$	3.82

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

Retail Electricity Segment

Total revenues for the Retail Electricity Segment for the year ended December 31, 2018 were approximately $863.5 million, an increase of approximately $205.9 million, or 31%, from approximately $657.6 million for the year ended December 31, 2017. This increase was largely due to an increase in volumes, a result of our acquisitions of HIKO and two customer portfolios, full year results from the Verde Companies, a larger C&I customer book in 2018, extreme cold weather in the first quarter of 2018, and warmer than normal weather in the second and third quarters of 2018 resulting in an increase of $182.5 million. This increase was further impacted by the higher electricity pricing environment, which resulted in an increase of $23.4 million. Total revenues for the Retail Electricity Segment for the year ended December 31, 2017 increased approximately $240.4 million, or 58%, from approximately $417.2 million for the year ended December 31, 2016. This increase was primarily due to an increase in volume from the acquisitions of the Major Energy Companies, the Provider Companies and the Verde Companies and the addition of several higher volume commercial customers in the East, which resulted in an increase in revenues of $258.6 million. This increase was partially offset by a decrease in electricity pricing, driven by the lower electricity pricing environment from milder than anticipated weather, which resulted in a decrease of $18.2 million.

Retail cost of revenues for the Retail Electricity Segment for the year ended December 31, 2018 was approximately $762.8 million, an increase of approximately $285.8 million, or 60%, from approximately $477.0 million for the year ended December 31, 2017. This increase was primarily due to an increase in volumes as a result of the acquisitions of HIKO and two customers portfolios, full year results from the Verde Companies, a larger C&I customer book in 2018, extreme cold weather in the first quarter of 2018, and warmer than normal weather in second and third quarter of 2018, resulting in an increase of $138.5 million. This increase was further impacted by increased electricity prices, REC requirements and capacity costs, which resulted in an increase in retail cost of

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revenues of $101.2 million. Additionally, there was an increase of $46.1 million due to a change in the value of our retail derivative portfolio used in hedging. Retail cost of revenues for the Retail Electricity Segment for the year ended December 31, 2017 increased approximately $190.2 million, or 66%, from approximately $286.8 million for the year ended December 31, 2016. This increase was primarily due to an increase in volume as a result of the acquisitions of the Major Energy Companies, the Provider Companies and the Verde Companies and the addition of higher volume commercial customers in the East, which resulted in an increase of $185.4 million, increased electricity prices, which resulted in an increase in retail cost of revenues of $14.6 million. Additionally, there was a decrease of $9.8 million due to a change in the value of our retail derivative portfolio used in hedging.

Retail gross margin for the Retail Electricity Segment for the year ended December 31, 2018 decreased approximately $33.8 million, or 21%, as compared to the year ended December 31, 2017, and 2017 increased approximately $40.4 million or 34% as compared to December 31, 2016 as indicated in the table below (in millions).



	2018 vs. 2017			2017 vs. 2016
Change in volumes sold	$	44.0		$	73.2
Change in unit margin per MWh	(77.8		)	(32.8		)
Change in retail electricity segment retail gross margin	$	(33.8	)	$	40.4

Unit margins were negatively impacted as a result of the higher volumes from our commercial customers, which tend to have lower unit margins than our residential customers.

The volumes of electricity sold increased from 6,755,663 MWh for the year ended December 31, 2017 to 8,630,653 MWh for the year ended December 31, 2018. This increase was primarily due to our acquisitions of HIKO and two customers portfolios, full year results from the Verde Companies, a larger C&I customer book in 2018, extreme cold weather in the first quarter of 2018, and warmer than normal weather in the second and third quarters of 2018. The volumes of electricity sold increased from 4,170,593 MWh for the year ended December 31, 2016 to 6,755,663 MWh for the year ended December 31, 2017. This increase was primarily due to full year results of the Major Energy Companies and the Provider Companies, the addition of customers through the acquisition of the Verde Companies, and an increased number of higher volume C&I customers.

Retail Natural Gas Segment

Total revenues for the Retail Natural Gas Segment for the year ended December 31, 2018 were approximately $138.0 million, a decrease of approximately $3.2 million, or 2%, from approximately $141.2 million for the year ended December 31, 2017. This decrease was attributable to an increase in price of $7.9 million, offset by a decrease in customer sales volume, which decreased total revenues by $11.1 million. Total revenues for the Retail Natural Gas Segment for the year ended December 31, 2017 increased by approximately $11.1 million, or 9%, from approximately $130.1 million for the year ended December 31, 2016. This increase was attributable to an increase in customer sales volume resulting from full year results of the Major Energy Companies and the acquisition of the Verde Companies, which increased total revenues by $10.7 million.

Retail cost of revenues for the Retail Natural Gas Segment for the year ended December 31, 2018 were approximately $82.7 million, an increase of approximately $7.5 million, or 10%, from approximately $75.2 million for the year ended December 31, 2017. This increase was due to increased supply costs of $8.2 million, $5.2 million change in the fair value of our retail derivative portfolio used for hedging, offset by $5.9 million related to decreased volumes. Retail cost of revenues for the Retail Natural Gas Segment for the year ended December 31, 2017 increased approximately $17.1 million, or 29%, from approximately $58.1 million for the year ended December 31, 2016. This increase was due to a $7.7 million change in the fair value of our retail derivative portfolio used for hedging, an increase of $5.4 million related to increased volume resulting from full year results of the Major Energy Companies, the acquisition of the Verde Companies, and increased supply costs of $4.0 million.

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Retail gross margin for the Retail Natural Gas Segment for the year ended December 31, 2018 decreased by approximately $5.6 million, or 8% from approximately $66.0 million for the year ended December 31, 2017, and 2017 increased approximately $1.8 million or 3% from approximately $64.2 million for the year ended December 31, 2016 as indicated in the table below (in millions).



	2018 vs. 2017			2017 vs. 2016
Change in volumes sold	$	(5.2	)	$	5.3
Change in unit margin per MMBtu	(0.4		)	(3.5		)
Change in retail natural gas segment retail gross margin	$	(5.6	)	$	1.8

Unit margins were negatively impacted as a result of increase in higher volume commercial customers, which typically have lower per unit margins than residential customers.

The volumes of natural gas sold decreased from 18,203,684 MMBtu for the year ended December 31, 2017 to 16,778,393 MMBtu for the year ended December 31, 2018. This decrease was primarily due to warmer-than-normal weather in the second and third quarters of 2018. The volumes of natural gas sold increased from 16,819,713 MMBtu for the year ended December 31, 2016 to 18,203,684 MMBtu for the year ended December 31, 2017. This increase was primarily due to our full year results of the Major Energy Companies and an increased number of higher volume C&I customers.

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. We believe that cash generated from operations and our available liquidity sources will be sufficient to sustain current operations and to pay required taxes and quarterly cash distributions, including the quarterly dividends to the holders of the Class A common stock and the Series A Preferred Stock, for the next twelve months. We believe that the financing of any additional growth through acquisitions or the need for more liquidity in 2019, may require further equity or debt financing and/or further expansion of our Senior Credit Facility. Estimating our liquidity requirements is highly dependent on then-current market conditions, including forward prices for natural gas and electricity, and market volatility and our then existing capital structure and requirements.

Liquidity Position

The following table details our available liquidity as of December 31, 2018:



	December 31,
($ in thousands)	2018
Cash and cash equivalents	$	41,002
Senior Credit Facility Availability ⁽¹⁾	4,360
Subordinated Debt Availability ⁽²⁾	15,000
Total Liquidity	$	60,362

(1) Reflects amount of Letters of Credit that could be issued based on existing covenants as of December 31, 2018.

(2) The availability of the Subordinated Facility is dependent on our Founder's willingness and ability to lend. See "Subordinated Debt Facility."

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Borrowings and related postings 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.

On January 28, 2019, the Company and Co-Borrowers exercised the accordion feature in the Senior Credit Facility, bringing total commitments under the Senior Credit Facility to $217.5 million.

Sources of Liquidity and Capital Resources

Senior Credit Facility

As of December 31, 2018, we had total commitments of $192.5 million, of which $178.9 million was outstanding, including $49.4 million of outstanding letters of credit. In January 2019, our total commitments under our Senior Credit Facility increased to $217.5 million. Under the Senior Credit Facility, we have various limits on advances for Working Capital Loans, Letters of Credit and Bridge Loans. The Senior Credit Facility matures on May 19, 2020. 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 10 "Debt" in the notes to our consolidated financial statements. As of December 31, 2018, we were in compliance with the covenants under our Senior Credit Facility.

Subordinated Debt Facility

Our Subordinated Facility allows us to draw advances in increments of no less than $1.0 million per advance up to $25.0 million. Although we may use the Subordinated Facility from time to time to enhance short term liquidity, we do not view the Subordinated Facility as a material source of liquidity. See Note 10 "Debt" for additional details. As of December 31, 2018, there was $10.0 million outstanding borrowings under the Subordinated Facility, which was repaid in January 2019.

Uses of Liquidity and Capital Resources

Repayment of Current Portion of Senior Credit Facility

Our Senior Credit Facility matures in 2020, and thus, no amounts are due currently. However, due to the revolving nature of the facility, excess cash available is generally used to reduce the balance outstanding, which at December 31, 2018 was $129.5 million. The current variable interest rate on the facility at December 31, 2018 was 5.48%.

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, 2018 and 2017, we spent a total of $13.7 million and $25.9 million, respectively, on organic customer acquisitions. Our ability to grow our customer base organically or by acquisition is important to our success as we experience ongoing customer attrition each period.

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, 2018 included approximately $1.4 million related to information systems improvements.

Dividends and Distributions

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For the year ended December 31, 2018, we paid dividends to holders of our Class A common stock of $0.725 per share or $9.8 million in the aggregate. In order to pay our stated dividends to holders of our Class A common stock, our subsidiary, Spark HoldCo is required to make corresponding distributions to holders of Class B common stock (our non-controlling interest holders). As a result, during the year ended December 31, 2018, Spark HoldCo made distributions of $15.5 million to our non-controlling interest holders related to the dividend payments to our Class A shareholders.

For the year ended December 31, 2018, we paid $7.0 million of dividends to holders of our Series A Preferred Stock, and as of December 31, 2018, we had accrued $2.0 million related to dividends to holders of our Series A Preferred Stock, which we paid on January 15, 2019. For the year ended December 31, 2018, we declared dividends of $2.1875 per share or $8.1 million in the aggregate on our Series A Preferred Stock.

On January 17, 2019, our Board of Directors declared a quarterly cash dividend in the amount of $0.18125 per share to holders of our Class A common stock and $0.546875 per share for the Series A Preferred Stock. Dividends on Class A common stock will be paid on March 15, 2019 to holders of record on March 1, 2019 and Series A Preferred Stock dividends will be paid on April 15, 2019 to holders of record on April 1, 2019.

Our ability to pay dividends in the future will depend on many factors, including the performance of our business and restrictions under our Senior Credit Facility. If our business does not generate sufficient cash for Spark HoldCo to make distributions to us to fund our Class A common stock and Series A Preferred Stock dividends, we may have to borrow to pay such amounts. Further, even if our business generates cash in excess of our current annual dividend (of $0.725 per share on our Class A common stock), we may reinvest such excess cash flows in our business and not increase the dividends payable to holders of our Class A common stock. Our future dividend policy is within the discretion of our Board of Directors and will depend upon the results of our operations, our financial condition, capital requirements and investment opportunities.

Tax Receivable Agreement

We are required to make payments under a Tax Receivable Agreement that we have entered into with companies affiliated with our Founder and majority shareholder. This agreement generally provides for the payment by the Company of 85% of the net cash savings, if any, in U.S. federal, state and local income tax or franchise tax that the Company actually realizes (or is deemed to have realized in certain circumstances) in future periods. The Company retains the benefit of the remaining 15% of these tax savings. Except in cases where we elect to terminate the Tax Receivable Agreement early (or the Tax Receivable Agreement is terminated early due to certain defined changes of control) or we have available cash but fail to make payments when due, we may request to defer payments due under the Tax Receivable Agreement for up to five years if we do not have available cash to satisfy our payment obligations, or if our contractual obligations limit our ability to make these payments. Any such deferred payments accrue interest. If we were to defer substantial payment obligations on an ongoing basis, the accrual of those obligations would reduce the availability of cash for other purposes, but we would not be prohibited from paying dividends on our Class A common stock. For the year ended December 31, 2018, we paid a total of $6.2 million related to TRA payments for the 2015, 2016, and 2017 tax years. As of December 31, 2018, we have a total liability related to the TRA on our balance sheet of $27.6 million. See Note 15 "Transactions with Affiliates" in the notes to our consolidated financial statements for additional details on the Tax Receivable Agreement.

Verde Promissory Note

In January 2018, we issued an amended and restated promissory note to the sellers of the Verde Companies (the "Verde Promissory Note"). As of December 31, 2018, there was $1.0 million outstanding under the Verde Promissory Note, all of which was paid in January 2019. The note bore interest at 9% per annum, and we made monthly payments of principal and associated interest, a portion of which was deposited into an escrow account to

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provide security for certain indemnification claims and obligations under the Verde purchase agreement. As of December 31, 2018, a total of $7.6 million was held in escrow for such claims.

Verde Earnout Termination Note

In January 2018, we issued a promissory note in the principal amount of $5.9 million in connection with an agreement to terminate the earnout obligation arising in connection with our acquisition of the Verde Companies. The note matures in June 2019 (subject to early maturity upon certain events) and bears interest at a rate of 9% per annum. We are permitted to withhold amounts otherwise due at maturity related to certain indemnifiable matters. Interest is payable monthly on the first day of each month in which the note is outstanding.

Cash Flows

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



	Year Ended December 31,
	2018			2017			2016
Net cash provided by operating activities	$	59,763		$	62,131		$	66,950
Net cash used in investing activities	$	(18,981	)	$	(77,558	)	$	(33,489	)
Net cash (used in) provided by financing activities	$	(20,563	)	$	25,886		$	(18,975	)

Cash Flows Provided by Operating Activities. Cash flows provided by operating activities for the year ended December 31, 2018 decreased by $2.4 million compared to the year ended December 31, 2017. The decrease was primarily the result of a decrease in the changes in working capital for the year ended December 31, 2018 and the impact of extreme weather events during the first quarter of 2018. Cash flows provided by operating activities for the year ended December 31, 2017 decreased by $4.8 million compared to the year ended December 31, 2016. The decrease was primarily the result of a decrease in the changes in working capital, offset by an increase in retail gross margin for the year ended December 31, 2017 following several significant acquisitions in 2016 and 2017.

Cash Flows Used in Investing Activities. Cash flows used in investing activities decreased by $58.6 million for the year ended December 31, 2018. The decrease was primarily the result of the $81.3 million acquisition of the Verde Companies, Perigee and other customers during the year ended December 31, 2017, offset by the acquisition of HIKO of $14.3 million during the year ended December 31, 2018. Cash flows used in investing activities increased by $44.1 million for the year ended December 31, 2017, which was primarily due to the funding of the acquisition of the Verde Companies and the acquisitions of Perigee and other customers during the year ended December 31, 2017, as well as earnout payments made during the year ended December 31, 2017 related to the Provider Companies and Major Energy Companies.

Cash Flows Used in Financing Activities. Cash flows used in financing activities increased by $46.4 million for the year ended December 31, 2018. The increase in cash flows used in financing activities was primarily due to increased net paydown of our Senior Credit Facility, additional dividends paid to holders of Series A Preferred Stock, payments related to the Verde Promissory Note and payments associated with the acquisition of customers from an affiliate for the year ended December 31, 2018. Cash flows provided by financing activities increased by $44.9 million for the year ended December 31, 2017 primarily due to increased net utilization of our Senior Credit Facility and proceeds from the issuance of Series A Preferred Stock, offset by additional dividends and distributions, respectively, made to holders of our Class A common stock, holders of our Series A Preferred Stock, and holders of the Class B units of Spark HoldCo.

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Summary of Contractual Obligations

The following table discloses aggregate information about our contractual obligations and commercial commitments as of December 31, 2018 (in millions):



	Total		2019		2020		2021		2022		2023		> 5 years
Operating leases ⁽¹⁾	$	1.0	$	0.6	$	0.3	$	0.1	$	—	$	—	$	—
Purchase obligations:
Pipeline transportation agreements	14.6		6.8		1.1		1.1		1.1		1.0		3.5
Other purchase obligations ⁽²⁾	10.4		5.4		3.3		1.7		—		—		—
Total purchase obligations	$	26.0	$	12.8	$	4.7	$	2.9	$	1.1	$	1.0	$	3.5
Senior Credit Facility	$	129.5	$	—	$	129.5	$	—	$	—	$	—	$	—
Note payable	6.9		6.9		—		—		—		—		—
Debt	$	136.4	$	6.9	$	129.5	$	—	$	—	$	—	$	—


(1)	Included in the total amount are future minimum payments for office leases.


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

Tax Receivable Agreement

As of December 31, 2018, the Company had a Tax Receivable Liability of $27.6 million, which is not reflected in the contractual obligations table above as the estimated timing of payments made under the Tax Receivable Agreement is imprecise by nature, uncertain, and dependent upon a variety of factors, as described in Note 15 "Transactions with Affiliates."

Off-Balance Sheet Arrangements

As of December 31, 2018 we had no material off-balance sheet arrangements.

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Related Party Transactions

For a discussion of related party transactions see Note 15 "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.

Business Combinations

When we acquire a business or a book of customers, we assign and allocate the purchase price to the identifiable assets acquired and liabilities assumed based upon their estimated fair value. Generally, the amount recorded in the financial statements for an acquisition’s assets and liabilities is equal to the purchase price (the fair value of the consideration paid); however, when the purchase price exceeds the underlying fair value of the net assets acquired, we recognize goodwill. Conversely, a purchase price that is below the fair value of the net assets acquired will result in the recognition of a bargain purchase in the income statement.

In addition to the potential for the recognition of goodwill or a bargain purchase, differing fair values will impact the allocation of the purchase price to the individual assets and liabilities and can impact the gross amount and classification of assets and liabilities recorded in our consolidated balance sheets, which can impact the timing and amount of depreciation and amortization expense recorded in any given period.

In estimating fair value, we use discounted cash flow (“DCF”) projections, recent comparable market transactions, if available, or quoted prices. We consider assumptions that third parties would make in estimating fair value,

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including, but not limited to, the highest and best use of the asset. There is a significant amount of judgment involved in cash-flow estimates, including assumptions regarding market convergence, discount rates, commodity prices, customer attrition, useful lives and growth factors. The assumptions used by another party could differ significantly from our assumptions.

We utilize our best effort to make our determinations and review all information available, including estimated future cash flows and prices of similar assets when making our best estimate. We also may hire independent appraisers or valuation specialists to help us make this determination as we deem appropriate under the circumstances. Refer to Note 4 "Acquisitions" for further discussion of assumptions used in acquisitions.

There is a significant amount of judgment in determining the fair value of acquisitions and in allocating the purchase price to individual assets and liabilities. Had different assumptions been used, the fair value of the assets acquired and liabilities assumed could have been significantly higher or lower with a corresponding increase or reduction in recognized goodwill, or could have required recognition of a bargain purchase.

In the case of acquisitions that involve potential future contingent consideration, we record on the date of acquisition a liability equal to the fair value of the estimated additional consideration we may be obligated to pay in the future. We re-measure this liability each reporting period and record changes in the fair value as general and administrative expense. Increase or decreases in the fair value of the contingent consideration can result from changes in in the timing or likelihood of achieving revenue or customer count thresholds. The use of alternative valuation assumptions, including estimated revenue projections, growth rates, cash flows and discount rates and alternative estimated probabilities surrounding revenue or customer count thresholds could result in different expense related to contingent consideration.

Goodwill

As noted above, Goodwill represents the excess of cost over fair value of the assets of businesses. The goodwill on our consolidated balance sheet as of December 31, 2018 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, 2018, we elected to perform a qualitative assessment of goodwill in accordance with guidance from ASC 350. This guidance permits an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. If we fail the qualitative test or if we elect to by-pass the qualitative assessment, then we must compare our estimate of the fair value of a reporting unit with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, we perform the second step of the goodwill impairment test to measure the amount of goodwill impairment loss to be recorded, as necessary. The second step compares the implied fair value of the reporting unit’s goodwill to the carrying value, if any, of that goodwill. We determine the implied fair value of the goodwill in the same manner as determining the amount of goodwill to be recognized in a business combination. 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, 2018, 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

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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 14 "Commitment and Contingencies" in the Company’s audited consolidated financial statements.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Commodity Price Risk

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

Our net loss on our non-trading derivative instruments, net of cash settlements, was $29.2 million for the year ended December 31, 2018.

We measure the commodity risk of our non-trading energy derivatives using a sensitivity analysis on our net open position. As of December 31, 2018, our Gas Non-Trading Fixed Price Open Position (hedges net of retail load) was a short position of 391,416 MMBtu. An increase of 10% in the market prices (NYMEX) from their December 31, 2018 levels would have increased the fair market value of our net non-trading energy portfolio by $0.1 million. Likewise, a decrease of 10% in the market prices (NYMEX) from their December 31, 2018 levels would have decreased the fair market value of our non-trading energy derivatives by $0.1 million. As of December 31, 2018, our Electricity Non-Trading Fixed Price Open Position (hedges net of retail load) was a long position of 48,125 MWhs. An increase of 10% in the forward market prices from their December 31, 2018 levels would have increased the fair market value of our net non-trading energy portfolio by $0.3 million. Likewise, a decrease of 10% in the forward market prices from their December 31, 2018 levels would have decreased the fair market value of our non-trading energy derivatives by $0.3 million.

Credit Risk

In many of the utility services territories where we conduct business, POR programs have been established, whereby the local regulated utility purchases our receivables, and becomes responsible for billing the customer and collecting payment from the customer. This service results in substantially all of our credit risk being with the utility and not to our end-use customer in these territories. Approximately 66%, 66% and 67% of our retail revenues were derived from territories in which substantially all of our credit risk was with local regulated utility companies as of December 31, 2018, 2017 and 2016, respectively, all of which had investment grade ratings as of such date. During the same period, we paid these local regulated utilities a weighted average discount of approximately 1.0%, 1.1% and 1.3%, respectively, of total revenues for customer credit risk protection. In certain of the POR markets in which we operate, the utilities limit their collections exposure by retaining the ability to transfer a delinquent account back to us for collection when collections are past due for a specified period.

If our collection efforts are unsuccessful, we return the account to the local regulated utility for termination of service. Under these service programs, we are exposed to credit risk related to payment for services rendered during the time between when the customer is transferred to us by the local regulated utility and the time we return the

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customer to the utility for termination of service, which is generally one to two billing periods. We may also realize a loss on fixed-price customers in this scenario due to the fact that we will have already fully hedged the customer's expected commodity usage for the life of the contract.

In non-POR markets (and in POR markets where we may choose to direct bill our customers), we manage customer credit risk through formal credit review in the case of commercial customers, and credit score screening, deposits and disconnection for non-payment, in the case of residential customers. Economic conditions may affect our customers' ability to pay bills in a timely manner, which could increase customer delinquencies and may lead to an increase in bad debt expense. Our bad debt expense for the year ended December 31, 2018, 2017 and 2016 was approximately 2.6%, 2.5% and 0.6% of non-POR market retail revenues, respectively. See “Management's Discussion and Analysis of Financial Condition and Results of Operations—Drivers of Our Business—Customer Credit Risk” for an analysis of our bad debt expense related to non-POR markets during 2018.

We are exposed to wholesale counterparty credit risk in our retail and asset optimization activities. We manage this risk at a counterparty level and secure our exposure with collateral or guarantees when needed. At December 31, 2018 and 2017, approximately $4.1 million and $5.3 million of our total exposure of $22.7 million and $34.2 million, respectively, was either with a non-investment grade counterparty or otherwise not secured with collateral or a guarantee. The credit worthiness of the remaining exposure with other customers was evaluated with no material allowance recorded at December 31, 2018 and 2017.

Interest Rate Risk

We are exposed to fluctuations in interest rates under our variable-price debt obligations. At December 31, 2018, we were co-borrowers under the Senior Credit Facility, under which $129.5 million of variable rate indebtedness was outstanding. Based on the average amount of our variable rate indebtedness outstanding during the year ended December 31, 2018, a 1% percent increase in interest rates would have resulted in additional annual interest expense of approximately $1.3 million. During the year ended December 31, 2018, we entered into two interest rate swap agreements to manage interest rate risk.

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Item 8. Financial Statements and Supplementary Data



ITEM 8. FINANCIAL STATEMENTS

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING		65

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMS		66

CONSOLIDATED BALANCE SHEETS AS OF DECEMBER 31, 2018 AND DECEMBER 31, 2017		68

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) FOR THE YEARS ENDED DECEMBER 31, 2018, 2017 AND 2016		69

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY FOR THE YEARS ENDED DECEMBER 31, 2018, 2017 AND 2016		70

CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 2018, 2017 AND 2016		73

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS		75

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MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

It is the responsibility of the management of Spark Energy, Inc. to establish and maintain adequate internal control over financial reporting. Internal control over financial reporting is defined in Rule 13a-15(f) or 15d-15(f) promulgated under the Securities Exchange Act of 1934, as amended, as a process designed by, or under the supervision of, our principal executive and principal financial officers and effected by our board of directors, management, and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that:


•	Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect our transactions and dispositions of the assets;


•	Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and the receipts and expenditures are being made only in accordance with authorizations of our management and directors; and


•	Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on our financial statements.

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

Management has assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2018, utilizing the criteria in the Committee of Sponsoring Organizations of the Treadway Commission’s Internal Control-Integrated Framework (2013). Based on its assessment, our management concluded the Company’s internal control over financial reporting was effective as of December 31, 2018.

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Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of Spark Energy, Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheet of Spark Energy, Inc. (the Company) as of December 31, 2018, the related consolidated statement of operations and comprehensive (loss) income, changes in equity, and cash flows for the year ended December 31, 2018, and the related notes. In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2018, and the results of its consolidated operations and its cash flows for the year ended December 31, 2018, in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

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

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audit we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

Our audit included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audit provides a reasonable basis for our opinion.

/s/ Ernst & Young LLP

We have served as Spark Energy, Inc.’s auditor since 2018.

Houston, Texas

March 4, 2019

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Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of Directors

Spark Energy, Inc.:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Spark Energy, Inc. and subsidiaries (the Company) as of December 31, 2017 and 2016, the related consolidated statements of operations and comprehensive (loss) income, changes in equity, and cash flows for each of the years in the two-year period ended December 31, 2017, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the years in the two-year period ended December 31, 2017, in conformity with U.S. generally accepted accounting principles.

Change in Accounting Principle

As discussed in note 2 to the consolidated financial statements, the Company has changed its method of accounting for employee taxes paid for shares withheld for tax withholding purposes in the year ended December 31, 2017 due to the adoption of Accounting Standards Update No. 2016-09, “Improvements to Employee Share-Based Payment Accounting.”

Basis for Opinion

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

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ KPMG LLP

We have served as the Company’s auditor since 2011.

Houston, Texas

March 9, 2018, except for note 3, as to which the date is March 4, 2019.

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AUDITED CONSOLIDATED FINANCIAL STATEMENTS

SPARK ENERGY, INC.

CONSOLIDATED BALANCE SHEETS AS OF DECEMBER 31, 2018 AND DECEMBER 31, 2017

(in thousands, except share counts)

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	December 31, 2018			December 31, 2017
Assets
Current assets:
Cash and cash equivalents	$	41,002		$	29,419
Restricted cash	8,636			—
Accounts receivable, net of allowance for doubtful accounts of $3,353 and $4,023 as of December 31, 2018 and 2017, respectively	150,866			158,814
Accounts receivable—affiliates	2,558			3,661
Inventory	3,878			4,470
Fair value of derivative assets	7,289			31,191
Customer acquisition costs, net	14,431			22,123
Customer relationships, net	16,630			18,653
Deposits	9,226			7,701
Renewable energy credit asset	25,717			12,839
Other current assets	11,747			7,867
Total current assets	291,980			296,738
Property and equipment, net	4,366			8,275
Fair value of derivative assets	3,276			3,309
Customer acquisition costs, net	3,893			6,949
Customer relationships, net	26,429			34,839
Deferred tax assets	27,321			21,977
Goodwill	120,343			120,154
Other assets	11,130			11,500
Total Assets	$	488,738		$	503,741
Liabilities, Series A Preferred Stock and Stockholders' Equity
Current liabilities:
Accounts payable	$	69,631		$	77,510
Accounts payable—affiliates	2,464			4,622
Accrued liabilities	10,004			10,202
Renewable energy credit liability	42,805			23,477
Fair value of derivative liabilities	6,478			1,637
Current portion of Senior Credit Facility	—			7,500
Current payable pursuant to tax receivable agreement—affiliates	1,658			5,937
Current contingent consideration for acquisitions	1,328			4,024
Current portion of note payable	6,936			13,443
Other current liabilities	647			2,675
Total current liabilities	141,951			151,027
Long-term liabilities:
Fair value of derivative liabilities	106			492
Payable pursuant to tax receivable agreement—affiliates	25,917			26,355
Long-term portion of Senior Credit Facility	129,500			117,750
Subordinated debt—affiliate	10,000			—
Note payable	—			7,051
Contingent consideration for acquisitions	—			626
Other long-term liabilities	212			172
Total liabilities	307,686			303,473
Commitments and contingencies (Note 14)
Series A Preferred Stock, par value $0.01 per share, 20,000,000 shares authorized, 3,707,256 shares issued and outstanding at December 31, 2018 and 1,704,339 shares issued and outstanding at December 31, 2017	90,758			41,173
Stockholders' equity:
Common Stock :
Class A common stock, par value $0.01 per share, 120,000,000 shares authorized, 14,178,284 issued and 14,078,838 outstanding at December 31, 2018 and 13,235,082 issued and 13,135,636 outstanding at December 31, 2017	142			132
Class B common stock, par value $0.01 per share, 60,000,000 shares authorized, 20,800,000 issued and outstanding at December 31, 2018 and 21,485,126 issued and outstanding at December 31, 2017	209			216
Additional paid-in capital	46,157			47,811
Accumulated other comprehensive (loss)/income	2			(11		)
Retained (deficit) earnings	1,307			11,399
Treasury stock, at cost, 99,446 shares at December 31, 2018 and December 31, 2017	(2,011		)	(2,011		)
Total stockholders' equity	45,806			57,536
Non-controlling interest in Spark HoldCo, LLC	44,488			101,559
Total equity	90,294			159,095
Total Liabilities, Series A Preferred Stock and stockholders' equity	$	488,738		$	503,741

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

SPARK ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE (LOSS) INCOME FOR THE YEARS ENDED DECEMBER 31, 2018, 2017 and 2016

(in thousands, except per share data)



	Year Ended December 31,
	2018			2017			2016
Revenues:
Retail revenues	$	1,001,417		$	798,772		$	547,283
Net asset optimization revenues (expense) ⁽¹⁾	4,511			(717		)	(586		)
Total revenues	1,005,928			798,055			546,697
Operating expenses:
Retail cost of revenues ⁽²⁾	845,493			552,167			344,944
General and administrative ⁽³⁾	111,431			101,127			84,964
Depreciation and amortization	52,658			42,341			32,788
Total operating expenses	1,009,582			695,635			462,696
Operating (loss) income	(3,654		)	102,420			84,001
Other (expense)/income:
Interest expense	(9,410		)	(11,134		)	(8,859		)
Change in tax receivable agreement liability	—			22,267			—
Interest and other income	749			256			957
Total other expenses	(8,661		)	11,389			(7,902		)
(Loss) income before income tax expense	(12,315		)	113,809			76,099
Income tax expense	2,077			38,765			10,426
Net (loss) income	(14,392		)	75,044			65,673
Less: Net (loss) income attributable to non-controlling interest	(13,206		)	55,799			51,229
Net (loss) income attributable to Spark Energy, Inc. stockholders	$	(1,186	)	$	19,245		$	14,444
Less: Dividend on Series A preferred stock	8,109			3,038			—
Net (loss) income attributable to stockholders of Class A common stock	(9,295		)	16,207			14,444
Other comprehensive (loss) income, net of tax:
Currency translation (loss) gain	31			(59		)	41
Other comprehensive (loss) income	31			(59		)	41
Comprehensive (loss) income	(14,361		)	74,985			65,714
Less: Comprehensive (loss) income attributable to non-controlling interest	(13,188		)	55,762			51,259
Comprehensive (loss) income attributable to Spark Energy, Inc. stockholders	(1,173		)	19,223			14,455

Net (loss) income attributable to Spark Energy, Inc. per share of Class A common stock
Basic	$	(0.69	)	$	1.23		$	1.27
Diluted	$	(0.69	)	$	1.21		$	1.11

Weighted average shares of Class A common stock outstanding
Basic	13,390			13,143			11,402
Diluted	13,390			13,346			12,690

(1) Net asset optimization revenues includes net asset optimization revenues/(expense) —affiliates of $2,328, $1,281 and $(1,479) for the years ended December 31, 2018, 2017 and 2016, respectively.

(2) Retail cost of revenues includes retail cost of revenues—affiliates of $0, $0 and $9 for the years December 31, 2018, 2017 and 2016, respectively.

(3) General and administrative includes general and administrative expense—affiliates of $9,849, $24,700 and $15,700 for the years ended December 31, 2018, 2017 and 2016, respectively.

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

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SPARK ENERGY, INC.

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2018, 2017 and 2016

(in thousands)



	Issued Shares of Class A Common Stock	Issued Shares of Class B Common Stock		Treasury Stock	Class A Common Stock		Class B Common Stock			Treasury Stock		Accumulated Other Comprehensive Income (Loss)		Additional Paid-In Capital			Retained Earnings (Deficit)			Total Stockholders' Equity			Non-controlling Interest			Total Equity
Balance at 12/31/2015:	6,238	21,500		—	$	62	$	216		$	—	$	—	$	7,770		$	(1,366	)	$	6,682		$	24,708		$	31,390
Stock based compensation	—	—		—	—		—			—				2,270			—			2,270			—			2,270
Restricted stock unit vesting	305	—		—	4		—			—		—		1,058			—			1,062			—			1,062
Excess tax benefit related to restricted stock vesting	—	—		—	—		—			—		—		186			—			186			—			186
Consolidated net income	—	—		—	—		—			—		—		—			14,444			14,444			51,229			65,673
Foreign currency translation adjustment for equity method investee	—	—		—	—		—			—		11		—			—			11			30			41
Beneficial conversion feature	—	—		—	—		—			—		—		243			—			243			—			243
Distributions paid to non-controlling unit holders	—	—		—	—		—			—		—		—			—			—			(34,931		)	(34,931		)
Net contribution of the Major Energy Companies	—	—		—	—		—			—		—		—			—			—			3,873			3,873
Dividends paid to Class A common stockholders	—	—		—	—		—			—		—		—			(8,367		)	(8,367		)	—			(8,367		)
Proceeds from disgorgement of stockholder short-swing profits	—	—		—	—		—			—		—		1,605			—			1,605			—			1,605
Tax impact from tax receivable agreement upon exchange of units of Spark HoldCo, LLC to shares of Class A Common Stock	—	—		—	—		—			—		—		4,768			—			4,768			—			4,768
Exchange of shares of Class B common stock to shares of Class A common stock	6,450	(6,450	)	—	64		(64		)	—		—		2,716			—			2,716			(2,716		)	—
Issuance of Class B Common Stock	—	5,400		—	—		54			—		—		—			—			54			53,940			53,994
Remeasurement of deferred tax assets	—	—		—	—		—			—		—		(5,552		)	—			(5,552		)	—			(5,552		)
Changes in ownership interest	—	—		—	—		—			—		—		24,123			—			24,123			(24,123		)	—
Balance at 12/31/2016:	12,993	20,450		—	$	130	$	206		$	—	$	11	$	39,187		$	4,711		$	44,245		$	72,010		$	116,255
Stock based compensation	—	—		—	—		—			—		—		2,754			—			2,754			—			2,754
Restricted stock unit vesting	242	—		—	2		—			—		—		1,052			—			1,054			—			1,054
Consolidated net income	—	—		—	—		—			—		—		—			19,245			19,245			55,799			75,044

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Foreign currency translation adjustment for equity method investee	—	—		—		—		—			—			(22		)	—			—			(22		)	(37		)	(59		)
Beneficial conversion feature	—	—		—		—		—			—			—			—			—			—			176			176
Distributions paid to non-controlling unit holders	—	—		—		—		—			—			—			—			—			—			(33,800		)	(33,800		)
Net contribution by NG&E	—	—		—		—		—			—			—			—			—			—			274			274
Dividends paid to Class A common stockholders	—	—		—		—		—			—			—			—			(9,519		)	(9,519		)	—			(9,519		)
Dividends to Preferred Stock	—	—		—		—		—			—			—			—			(3,038		)	(3,038		)	—			(3,038		)
Proceeds from disgorgement of stockholder short-swing profits	—	—		—		—		—			—			—			708			—			708			—			708
Tax receivable agreement liability true-up	—	—		—		—		—			—			—			(2,872		)	—			(2,872		)	—			(2,872		)
Conversion of Convertible Subordinated Notes to Class B Common Stock	—	1,035		—		—		10			—			—			—			—			10			7,608			7,618
Treasury Stock	—	—		(99	)	—		—			(2,011		)	—			—			—			(2,011		)	—			(2,011		)
Remeasurement of deferred tax assets	—	—		—		—		—			—			—			6,511			—			6,511			—			6,511
Changes in ownership interest	—	—		—		—		—			—			—			471			—			471			(471		)	—
Balance at 12/31/2017:	13,235	21,485		(99	)	$	132	$	216		$	(2,011	)	$	(11	)	$	47,811		$	11,399		$	57,536		$	101,559		$	159,095
Stock based compensation	—	—		—		—		—			—			—			5,703			—			5,703			—			5,703
Restricted stock unit vesting	258	—		—		3		—			—			—			(1,018		)	—			(1,015		)	—			(1,015		)
Consolidated net income	—	—		—		—		—			—			—			—			(1,186		)	(1,186		)	(13,206		)	(14,392		)
Foreign currency translation adjustment for equity method investee	—	—		—		—		—			—			13			—			—			13			18			31
Distributions paid to non-controlling unit holders	—	—		—		—		—			—			—			—			—			—			(35,478		)	(35,478		)
Dividends paid to Class A common stockholders	—	—		—		—		—			—			—			(4,932		)	(4,851		)	(9,783		)	—			(9,783		)
Dividends to Preferred Stock	—	—		—		—		—			—			—			(4,055		)	(4,055		)	(8,110		)	—			(8,110		)
Exchange of shares of Class B common stock to shares of Class A common stock	685	(685	)	—		7		(7		)	—			—			—			—			—			—			—
Acquisition of Customers from Affiliate	—	—		—		—		—			—			—			—			—			—			(7,129		)	(7,129		)
Remeasurement of deferred tax assets	—	—		—		—		—			—			—			1,372			—			1,372			—			1,372
Changes in ownership interest	—	—		—		—		—			—			—			1,276			—			1,276			(1,276		)	—

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Balance at 12/31/2018:	14,178	20,800	(99	)	$	142	$	209	$	(2,011	)	$	2	$	46,157	$	1,307	$	45,806	$	44,488	$	90,294

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

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SPARK ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2018, 2017 AND 2016

(in thousands)



	Year Ended December 31,
	2018			2017			2016
Cash flows from operating activities:
Net (loss) income	$	(14,392	)	$	75,044		$	65,673
Adjustments to reconcile net (loss) income to net cash flows provided by operating activities:
Depreciation and amortization expense	51,436			42,666			48,526
Deferred income taxes	(2,328		)	29,821			3,382
Change in TRA liability	—			(22,267		)	—
Stock based compensation	5,879			5,058			5,242
Amortization of deferred financing costs	1,291			1,035			668
Change in fair value of Earnout liabilities	(1,715		)	(7,898		)	(140		)
Accretion on fair value of Earnout liabilities	—			4,108			5,060
Excess tax benefit related to restricted stock vesting	(101		)	179			—
Bad debt expense	10,135			6,550			1,261
Loss (gain) on derivatives, net	18,170			(5,008		)	(22,407		)
Current period cash settlements on derivatives, net	11,038			(19,598		)	(24,427		)
Accretion of discount to convertible subordinated notes to affiliate	—			1,004			150
Earnout Payments	—			(1,781		)	(843		)
Other	(882		)	(5		)	(715		)
Changes in assets and liabilities:
Decrease (increase) in accounts receivable	2,692			(32,361		)	(12,088		)
Decrease (increase) in accounts receivable—affiliates	859			(1,459		)	(118		)
Decrease (increase) in inventory	674			(718		)	542
Increase in customer acquisition costs	(13,673		)	(25,874		)	(21,907		)
(Increase) decrease in prepaid and other current assets	(14,033		)	1,915			71
(Increase) decrease in other assets	(335		)	(465		)	1,321
Increase in accounts payable and accrued liabilities	10,301			14,831			14,831
(Decrease) increase in accounts payable—affiliates	(2,158		)	51			458
(Decrease) increase in other current liabilities	(3,050		)	(1,210		)	2,364
Increase (decrease) in other non-current liabilities	41			(1,487		)	46
Decrease in intangible assets—customer acquisitions	(86		)	—			—
Net cash provided by operating activities	59,763			62,131			66,950
Cash flows from investing activities:
Purchases of property and equipment	(1,429		)	(1,704		)	(2,258		)
Cash paid for acquisitions	(17,552		)	(75,854		)	(30,129		)
Contribution to equity method investment	—			—			(1,102		)
Net cash used in investing activities	(18,981		)	(77,558		)	(33,489		)
Cash flows from financing activities:
Proceeds from issuance of Series A Preferred Stock, net of issuance costs paid	48,490			40,241			—
Payment to affiliates for acquisition of customer book	(7,129		)	—			—
Borrowings on notes payable	417,300			206,400			79,048
Payments on notes payable	(403,050		)	(152,939		)	(66,652		)
Earnout Payments	(1,607		)	(18,418		)	(2,012		)
Payments on the Verde promissory note	(13,422		)	—			—
Restricted stock vesting	(2,895		)	(3,091		)	(1,183		)
Proceeds from issuance of Class B common stock	—			—			13,995
Proceeds from disgorgement of stockholders short-swing profits	244			1,129			941
Excess tax benefit related to restricted stock vesting	—			—			185
Payment of Tax Receivable Agreement Liability	(6,219		)	—			—
Payment of dividends to Class A common shareholders	(9,783		)	(9,519		)	(8,367		)
Payment of distributions to non-controlling unitholders	(35,478		)	(33,800		)	(34,930		)
Payment of dividends to Preferred Stock	(7,014		)	(2,106		)	—
Purchase of Treasury Stock	—			(2,011		)	—
Net cash (used in) provided by financing activities	(20,563		)	25,886			(18,975		)
Increase in Cash and cash equivalents and Restricted Cash	20,219			10,459			14,486
Cash and cash equivalents and Restricted cash—beginning of period	29,419			18,960			4,474
Cash and cash equivalents and Restricted cash—end of period	$	49,638		$	29,419		$	18,960
Supplemental Disclosure of Cash Flow Information:
Non-cash items:
Issuance of Class B common stock to affiliates for Major Energy Companies acquisition	$	—		$	—		$	40,000
Contingent consideration—earnout obligations incurred in connection with the Provider Companies and Major Energy Companies acquisitions	$	—		$	—		$	18,936
Assumption of legal liability in connection with the Major Energy Companies acquisition	$	—		$	—		$	5,000

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Net contribution of the Major Energy Companies	$	—		$	—		$	3,873
Net contribution by NG&E in excess of cash	$	—		$	274		$	—
Installment consideration incurred in connection with the Provider Companies acquisition	$	—		$	—		$	1,890
Installment consideration incurred in connection with the Verde Companies acquisition and Verde Earnout Termination Note	$	—		$	19,994		$	—
Tax benefit from tax receivable agreement	$	(1,508	)	$	(1,802	)	$	31,490
Liability due to tax receivable agreement	$	1,642		$	4,674		$	(26,722	)
Property and equipment purchase accrual	$	(123	)	$	91		$	(32	)
Cash paid during the period for:
Interest	$	7,883		$	5,715		$	2,280
Taxes	$	8,561		$	11,205		$	7,326

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

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SPARK ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Formation and Organization

Organization

We are an independent retail energy services company that provides residential and commercial customers in competitive markets across the United States with an alternative choice for natural gas and electricity. The Company is a holding company whose sole material asset consists of units in Spark HoldCo, LLC (“Spark HoldCo”). The Company is the sole managing member of Spark HoldCo, is responsible for all operational, management and administrative decisions relating to Spark HoldCo’s business and consolidates the financial results of Spark HoldCo and its subsidiaries. Spark HoldCo is the direct and indirect owner of the subsidiaries through which we operate. We conduct our business through several brands across our service areas, including CenStar Energy, Electricity Maine, Electricity N.H., HIKO Energy, Major Energy, Oasis Energy, Perigee Energy, Provider Power Massachusetts, Respond Power, Spark Energy, and Verde Energy.

Emerging Growth Company Status

The Company qualifies as an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012, or the JOBS Act. An emerging growth company may take advantage of specified reduced reporting and other regulatory requirements.

The Company will remain an “emerging growth company” until the earliest of (i) the date on which the Company issues more than $1.0 billion of non-convertible debt over a three-year period; or (ii) the last day of 2019.

2. Basis of Presentation and Summary of Significant Accounting Policies

Basis of Presentation

The accompanying consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) and pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Our financial statements are presented on a consolidated basis and include all wholly-owned and controlled subsidiaries. We account for investments over which we have significant influence but not a controlling financial interest using the equity method of accounting. All significant intercompany transactions and balances have been eliminated in the consolidated financial statements.

Immaterial Corrections to Prior Year Financial Information

The consolidated balance sheet, income statements, statement of changes in stockholders' equity and our cash flow statements reflect immaterial adjustments to the historical balances in additional paid in capital, non-controlling interest, deferred tax assets, retained earnings, income tax expense, net (loss) income attributable to non-controlling interest, and earnings per share for the years ended December 31, 2017 and 2016. We made these adjustments in accordance with GAAP, to reflect the amounts the owners of our Class A and Class B common stock would receive, respectively, if the assets of our subsidiary, Spark HoldCo, were sold, and its liabilities were settled at their recorded book values as of each balance sheet date. In addition, we adjusted income for the year ended December 31, 2017 to reflect the impact on income of the changes in deferred tax balances referenced above and to make certain immaterial corrections to the allocation of income between non-controlling interests and income available for common shareholders. Our adjustments had no impact on the manner in which distributions were paid in any current or prior period. The Company evaluated the materiality of the errors from quantitative and qualitative perspectives, and concluded that the errors were immaterial to the Company’s prior period interim and annual consolidated financial statements. Since the revision was not material to any prior period interim or annual consolidated financial statements, no amendments to previously filed interim or annual periodic reports was

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required. Consequently, the Company revised the historical consolidated financial information presented herein. Below are amounts as reported and as adjusted for each year presented (in thousands):



	December 31, 2016							December 31, 2017
	As Reported		Adjustments			As Adjusted		As Reported		Adjustments			As Adjusted

Deferred tax assets	$	54,109	$	(7,481	)	$	46,628	$	24,185	$	(2,208	)	$	21,977
Total Assets	375,230		(7,481		)	367,749		505,949		(2,208		)	503,741

Additional paid-in capital	25,272		13,915			39,187		26,914		20,897			47,811
Retained earnings	4,711		—			4,711		11,008		391			11,399
Total stockholders' equity	30,330		13,915			44,245		36,248		21,288			57,536
Non-controlling interest in Spark HoldCo, LLC	93,406		(21,396		)	72,010		125,055		(23,496		)	101,559
Total equity	123,736		(7,481		)	116,255		161,303		(2,208		)	159,095
Total liabilities, Series A Preferred Stock and stockholders' equity	375,230		(7,481		)	367,749		505,949		(2,208		)	503,741

Income tax expense								37,528		1,237			38,765
Net Income								76,281		(1,237		)	75,044
Net Income Available to Common Shareholders								15,816		391			16,207
Net income attributable to non-controlling interests								57,427		(1,628		)	55,799

Net income attributable to Spark Energy, Inc. per share of Class A common stock
Basic								1.20		0.03			1.23
Diluted								1.19		0.02			1.21

Cash flows from operating activities:
Net income								76,281		(1,237		)	75,044
Adjustments to reconcile net income to net cash flows from operating activities
Deferred income taxes								28,584		1,237			29,821
Net cash provided by operating activities ⁽¹⁾								63,912		(1,781		)	62,131

(1) Net cash provided by operating activities for the year ended December 31, 2017 changed from amounts previously reported due to the adoption of ASU No. 2016-15, Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments. See further discussion in the Recent Accounting Pronouncements section, below.

In addition, immaterial adjustments have been made to certain December 31, 2015 equity balances, as noted in the table below.



	December 31, 2015
	As Reported			Adjustments			As Adjusted

Additional paid-in capital	12,426			(4,656		)	7,770
Retained earnings	(1,366		)	—			(1,366		)
Total stockholders' equity	11,338			(4,656		)	6,682
Non-controlling interest in Spark HoldCo, LLC	21,981			2,727			24,708
Total equity	$	33,319		$	(1,929	)	$	31,390

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Subsequent Events

Subsequent events have been evaluated through the date these financial statements are issued. Any material subsequent events that occurred prior to such date have been properly recognized or disclosed in the consolidated financial statements.

Reclassifications

Prior to December 31, 2018, renewable energy credit asset and renewable energy credit liability balances were included in other current assets and accrued liabilities, respectively. In 2018, these amounts were separately presented and prior period financial statements have been reclassified to conform to the current period presentation. These reclassifications had no effect on reported earnings.

Use of Estimates and Assumptions

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

Relationship with our Founder and Majority Shareholder

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

We enter into transactions with and pay certain costs on behalf of affiliates that are commonly controlled by Mr. Maxwell, and these affiliates enter into transactions with and pay certain costs on our behalf. We undertake these transactions in order to reduce risk, reduce administrative expense, create economies of scale, create strategic alliances and supply goods and services among these related parties.

These transactions include, but are not limited to, employee benefits provided through the Company’s benefit plans, insurance plans, leased office space, certain administrative salaries, management due diligence, recurring management consulting, and accounting, tax, legal, or technology services. Amounts billed under these arrangements are based on services provided, departmental usage, or headcount, which are considered reasonable by management. As such, the accompanying consolidated financial statements include costs that have been incurred by the Company and then directly billed or allocated to affiliates, and costs that have been incurred by our affiliates and then directly billed or allocated to us, and are recorded net in general and administrative expense on the consolidated statements of operations with a corresponding accounts receivable—affiliates or accounts payable—affiliates, respectively, recorded in the consolidated balance sheets. Additionally, the Company enters into transactions with certain affiliates for sales or purchases of natural gas and electricity, which are recorded in retail revenues, retail cost of revenues, and net asset optimization revenues in the consolidated statements of operations with a corresponding accounts receivable—affiliate or accounts payable—affiliate in the consolidated balance sheets. The allocations and related estimates and assumptions are described more fully in Note 15 "Transactions with Affiliates."

Cash and Cash Equivalents

Cash and cash equivalents consist of all unrestricted demand deposits and funds invested in highly liquid instruments with original maturities of three months or less. The Company periodically assesses the financial

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condition of the institutions where these funds are held and believes that its credit risk is minimal with respect to these institutions.

Accounts Receivable

Trade accounts receivable are recorded at the invoiced amount and do not bear interest.

The Company accrues an allowance for doubtful accounts based upon estimated uncollectible accounts receivable considering historical collections, accounts receivable aging analysis, credit risk and other factors. The Company writes off accounts receivable balances against the allowance for doubtful accounts when the accounts receivable is deemed to be uncollectible. Bad debt expense of $10.1 million, $6.6 million and $1.3 million was recorded in general and administrative expense in the consolidated statements of operations for the years ended December 31, 2018, 2017 and 2016, respectively.

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”). This POR service results 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 such amounts are collectible. Trade accounts receivable that are part of a local regulated utility’s POR program are recorded on a gross basis in accounts receivable in the consolidated balance sheets. The discount paid to the local regulated utilities is recorded in general and administrative expense in the consolidated statements of operations.

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

Inventory

Inventory consists of natural gas used to fulfill and manage seasonality for fixed and variable-price retail customer load requirements and is valued at the lower of weighted average cost or market. Purchased natural gas costs are recognized in the consolidated statements of operations, within retail cost of revenues, when the natural gas is sold and delivered out of the storage facility using the weighted average cost of the gas sold.

Customer Acquisition Costs

The Company capitalizes direct response advertising costs that consist primarily of hourly and commission-based telemarketing costs, door-to-door agent commissions and other direct advertising costs associated with proven customer generation in its balance sheet. These costs are amortized over the estimated life of a customer.

As of December 31, 2018 and 2017, the net customer acquisition costs were $18.3 million and $29.0 million, of which $14.4 million and $22.1 million were recorded in current assets, and $3.9 million and $6.9 million were recorded in non-current assets. Amortization of customer acquisition costs were $24.4 million, $21.4 million, and $17.5 million for the years ended December 31, 2018, 2017 and 2016, respectively. Customer acquisition costs do not include customer acquisitions through merger and acquisition activities, which are recorded as customer relationships.

Recoverability of customer acquisition costs is evaluated based on a comparison of the carrying amount of such costs to the future net cash flows expected to be generated by the customers acquired, considering specific

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assumptions for customer attrition, per unit gross profit, and operating costs. These assumptions are based on forecasts and historical experience.

Customer Relationships

Customer contracts recorded as part of mergers or acquisitions are reflected as customer relationships in our balance sheet. The Company had capitalized customer relationship of $16.6 million and $18.7 million, net of amortization, as current assets as of December 31, 2018 and 2017, respectively, and $26.4 million and $34.8 million, net of amortization, as non-current assets as of December 31, 2018 and 2017, respectively, related to these intangible assets. These intangibles are amortized on a straight-line basis over the estimated average life of the related customer contracts acquired, which ranges from three to six years.

The acquired customer relationships intangibles related to Oasis, CenStar, Provider Companies, Major Energy Companies, Perigee Energy LLC, Verde Companies, and HIKO are reflective of the acquired companies’ customer base, and were valued at the respective dates of acquisition using an excess earnings method under the income approach. Using this method, the Company estimated the future cash flows resulting from the existing customer relationships, considering attrition as well as charges for contributory assets, such as net working capital, fixed assets, and assembled workforce. These future cash flows were then discounted using an appropriate risk-adjusted rate of return by retail unit to arrive at the present value of the expected future cash flows. CenStar, Oasis, Perigee, and HIKO customer relationships are amortized to depreciation and amortization based on the expected future net cash flows by year. The acquired customer relationship intangibles related to the Major Energy Companies, the Provider Companies and the Verde Companies were bifurcated between hedged and unhedged and amortized to depreciation and amortization based on the expected future cash flows by year and expensed to retail cost of revenue based on the expected term of the underlying fixed price contract in each reporting period, respectively.

Customer relationship amortization expense was $20.3 million, $17.8 million, and $28.6 million for the years ended December 31, 2018, 2017 and 2016, respectively, of which approximately $(1.2) million, $0.3 million, and $15.8 million was included in retail cost of revenue for those years.

We review customer relationships for impairment whenever events or changes in business circumstances indicate the carrying value of the intangible assets may not be recoverable. Impairment is indicated when the undiscounted cash flows estimated to be generated by the intangible assets are less than their respective carrying value. If an impairment exists, a loss is recognized for the difference between the fair value and carrying value of the intangible assets. No impairments of customer relationships were recorded for the years ended December 31, 2018, 2017 and 2016.

Non-compete agreements

We capitalize intangible costs associated with non-compete agreements in certain of our acquisitions. Non-compete agreements provide the Company with a certain level of assurance that acquired companies' expected earnings streams will not be disrupted by competition from the companies’ previous owners or members. These non-compete agreements are amortized over their estimated useful life of three years on a straight-line basis. As of December 31, 2018, the Company had $0.3 million of capitalized costs related to these non-compete agreements, of which $0.3 million was current, and of which zero was non-current. As of December 31, 2017, the Company had $1.4 million of capitalized costs related to non-compete agreements, of which $1.1 million was current, and of which $0.3 million was non-current. Amortization expense was $1.1 million, $1.2 million and $0.9 million for the years ended December 31, 2018, 2017 and 2016.

Trademarks

We record trademarks as part of our acquisitions which represent the value associated with the recognition and positive reputation of an acquired company to its target markets. This value would otherwise have to be internally developed through significant time and expense or by paying a third party for its use. These intangibles are amortized over the estimated five-year to ten-year life of the trademark on a straight-line basis. The fair values of

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trademark assets were determined at the date of acquisition using a royalty savings method under the income approach. Under this approach, the Company estimates the present value of expected cash flows resulting from avoiding royalty payments to use a third party trademark. The Company analyzes market royalty rates charged for licensing trademarks and applied an expected royalty rate to a forecast of estimated revenue, which was then discounted using an appropriate risk adjusted rate of return. As of December 31, 2018 and 2017, we had recorded $7.3 million and $8.6 million related to these trademarks in other assets. Amortization expense was $1.3 million, $0.8 million and $0.4 million for the years ended December 31, 2018, 2017 and 2016, respectively.

We review trademarks for impairment whenever events or changes in business circumstances indicate the carrying value of the intangible assets may not be recoverable. Impairment is indicated when the undiscounted cash flows estimated to be generated by the intangible assets are less than their respective carrying value. If an impairment exists, a loss is recognized for the difference between the fair value and carrying value of the intangible assets. No impairments of trademarks were recorded for the years ended December 31, 2018, 2017 and 2016.

Deferred Financing Costs

Costs incurred in connection with the issuance of long-term debt are capitalized and amortized to interest expense using the straight-line method over the life of the related long-term debt. These costs are included in other assets in our consolidated balance sheets.

Property and Equipment

The Company records property and equipment at historical cost. Depreciation expense is recorded on a straight-line method based on estimated useful lives, which range from 2 to 5 years, along with estimates of the salvage values of the assets. When items of property and equipment are sold or otherwise disposed of, any gain or loss is recorded in the consolidated statements of operations.

The Company capitalizes costs associated with certain of its internal-use software projects. Costs capitalized are those incurred during the application development stage of projects such as software configuration, coding, installation of hardware and testing. Costs incurred during the preliminary or post-implementation stage of the project are expensed in the period incurred, including costs associated with formulation of ideas and alternatives, training and application maintenance. After internal-use software projects are completed, the associated capitalized costs are depreciated over the estimated useful life of the related asset. Interest costs incurred while developing internal-use software projects are also capitalized. Capitalized interest costs for the years ended December 31, 2018, 2017 and 2016 were not material.

Goodwill

Goodwill represents the excess of cost over fair value of the assets of businesses acquired in accordance with FASB ASC Topic 350 Intangibles-Goodwill and Other ("ASC 350"). The goodwill on our consolidated balance sheet as of December 31, 2018 is associated with both our Retail Natural Gas and Retail Electricity segments. We determine our segments, which are also considered our reporting unit, by identifying each unit that engaged in business activities from which it may earn revenues and incur expenses, had operating results regularly reviewed by the segment manager for purposes of resource allocation and performance assessment, and had discrete financial information.

Goodwill is not amortized, but rather is assessed for impairment whenever events or circumstances indicate that impairment of the carrying value of goodwill is likely, but no less often than annually as of October 31. We compare our estimate of the fair value of the reporting unit with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, we compare the implied fair value of the reporting unit’s goodwill to the carrying value, if any, of that goodwill, the difference of which is recorded as an impairment in the financial statements. In accordance with our accounting policy, we completed our annual assessment of goodwill impairment as of October 31, 2018 during the fourth quarter of 2018, using a qualitative assessment approach,

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and the test indicated no impairment.

Treasury Stock

Treasury stock consists of Company's own stock that has been issued, but subsequently reacquired by the Company. Treasury stock does not reduce the number of shares issued but does reduce the number of shares outstanding. These shares are not eligible to receive cash dividends. We use the cost method to account for treasury shares.

Equity Method Investments

We use the equity method of accounting to account for investments where we have the ability to exercise significant influence over, but not control, the investee. Under the equity method of accounting, investments are stated at initial cost and are adjusted for subsequent additional investments and our share of earnings or losses and distributions. Equity investments are presented on the consolidated balance sheet under "Other assets" and our share of their income is reflected as "Interest and other income" on the consolidated statements of operations. We determine our equity investment earnings using the Hypothetical Liquidation at Book Value (HLBV) method. Under the HLBV method, a calculation is prepared at each balance sheet date to determine the amount the Company would receive if the investee were to liquidate all of its assets, as valued in accordance with U.S. GAAP, and distribute that cash to the investors. The difference between the calculated liquidation distribution amounts at the beginning and the end of the reporting period, after adjusting for capital contributions and distributions, is the Company's share of the earnings or losses from the equity investment for the period. See Note 17 "Equity Method Investment" for further discussion.

Revenues and Cost of Revenues

Our revenues are derived primarily from the sale of natural gas and electricity to customers, including affiliates. Revenues are recognized by the Company when: (1) persuasive evidence of an exchange arrangement exists, (2) delivery has occurred or services have been rendered, (3) the buyer’s price is fixed or determinable and (4) collection is reasonably assured. Utilizing these criteria, revenue is recognized when the natural gas or electricity is delivered to the customer. Similarly, cost of revenues is recognized when the commodity is delivered.

Revenues for natural gas and electricity sales are recognized under the accrual method. Natural gas and electricity sales that have been delivered but not billed by period end are estimated. Accrued unbilled revenues are based on estimates of customer usage since the date of the last meter read provided by the utility. Volume estimates are based on forecasted volumes and estimated customer usage by class. Unbilled revenues are calculated by multiplying these volume estimates by the applicable rate by customer class. Estimated amounts are adjusted when actual usage is known and billed.

Costs for natural gas and electricity sales are similarly recognized under the accrual method. Natural gas and electricity costs that have not been billed to the Company by suppliers but have been incurred by period end are estimated. The Company estimates volumes for natural gas and electricity delivered based on the forecasted revenue volumes, estimated transportation cost volumes and estimation of other costs associated with retail load that varies by commodity utility territory. These costs include items like ISO fees, ancillary services and renewable energy credits. Estimated amounts are adjusted when actual usage is known and billed.

Our asset optimization activities, which primarily include natural gas physical arbitrage and other short term storage and transportation transactions, meet the definition of trading activities and are recorded on a net basis in the consolidated statements of operations in net asset optimization revenues. The Company recorded asset optimization revenues, primarily related to physical sales or purchases of commodities, of $113.7 million, $178.3 million and $133.0 million for the years ended December 31, 2018, 2017 and 2016, respectively, and recorded asset optimization costs of revenues of $109.2 million, $179.0 million and $133.6 million for the years ended December 31, 2018, 2017 and 2016, respectively, which are presented on a net basis in asset optimization revenues.

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Natural Gas Imbalances

The consolidated balance sheets include natural gas imbalance receivables and payables, which primarily result when customers consume more or less gas than has been delivered by the Company to local distribution companies (“LDCs”). The settlement of natural gas imbalances varies by LDC, but typically the natural gas imbalances are settled in cash or in kind on a monthly, quarterly, semi-annual or annual basis. The imbalances are valued at their estimated net realizable value. The Company recorded an imbalance receivable of $0.8 million and $0.7 million in other current assets on the consolidated balance sheets as of December 31, 2018 and 2017, respectively. The Company recorded an imbalance payable of $0.3 million and $1.0 million in other current liabilities on the consolidated balance sheets as of December 31, 2018 and 2017, respectively.

Derivative Instruments

The Company uses derivative instruments such as futures, swaps, forwards and options to manage the commodity price risks of its business operations.

All derivatives are recorded in the consolidated balance sheets at fair value. Derivative instruments representing unrealized gains are reported as derivative assets while derivative instruments representing unrealized losses are reported as derivative liabilities. We offset amounts in the consolidated balance sheets for derivative instruments executed with the same counterparty where we have a master netting arrangement.

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

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

Income Taxes

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

The Company recognizes interest and penalties related to unrecognized tax benefits within the provision for income taxes on continuing operations in our consolidated statements of operations.

Earnings per Share

Basic earnings per share (“EPS”) is computed by dividing net income attributable to shareholders (the numerator) by the weighted-average number of Class A common shares outstanding for the period (the denominator). Class B

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common shares are not included in the calculation of basic earnings per share because they are not participating securities and have no economic interest in us. Diluted earnings per share is similarly calculated except that the denominator is increased for potentially dilutive securities. We use the treasury stock method to determine the potential dilutive effect of our outstanding unvested restricted stock units and use the if-converted method to determine the potential dilutive effect of our Class B common stock.

Non-controlling Interest

Net income attributable to non-controlling interest represents the Class B Common stockholders' interest in income and expenses of the Company. The weighted average ownership percentages for the applicable reporting period are used to allocate the income (loss) before income taxes to each economic interest owner.

Commitments and Contingencies

Liabilities for loss contingencies arising from claims, assessments, litigation, fines, penalties and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Legal costs incurred in connection with loss contingencies are expensed as incurred.

Recent Accounting Pronouncements

On January 1, 2018, we adopted ASU No. 2014-09, Revenue from Contracts with Customers, which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. We adopted the standard utilizing the full retrospective approach, and the adoption had no impact on our total revenues and operating income for the years ended December 31, 2018, 2017 and 2016. The standard requires expanded disclosures regarding the qualitative and quantitative information of an entity's nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. See Note 3 "Revenues" for further disclosure.

On January 1, 2018, we adopted ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business ("ASU 2017-01"). ASU 2017-01 clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. We utilized ASU 2017-01 in evaluating all acquisitions occurring after the date of adoption.

On January 1, 2018, we adopted ASU No. 2016-15, Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments ("ASU 2016-15"). ASU 2016-15 provides guidance on the presentation and classification of specific cash flow issues in the statement of cash flows, including contingent consideration payments made after a business combination. We applied this guidance using a retrospective transition method for each period presented. Because of the change in accounting guidance, we reclassified acquisition related payments of approximately $1.8 million and $0.8 million from cash flows from investing activities to cash flows from operating activities for the years ended December 31, 2017 and December 31, 2016, respectively. We reclassified acquisition related payments of approximately $18.4 million and $2.0 million from cash flows from investing activities to cash flows from financing activities for the years ended December 31, 2017 and December 31, 2016, respectively.

In October 2016, the FASB issued ASU No. 2016-16, Intra-Entity Transfers of Assets Other Than Inventory ("ASU 2016-16"), which states an entity should recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs and not when the asset has been sold to an outside party. The amendments in this guidance eliminate exceptions for intra-entity transfer of an asset, such as intellectual property and property, plant, and equipment. ASU 2016-16 is effective on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings for annual reporting periods beginning after December 15, 2017. We adopted ASU 2016-16 effective January 1, 2018, with no cumulative-effect adjustment.

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New Accounting Standards Being Evaluated But Not Yet Adopted

Below are accounting standards that have been issued, but not yet been adopted by the Company at December 31, 2018.

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) ("ASU 2016-02"). Under this new guidance, lessees will be required to recognize assets and liabilities on the balance sheet for the rights and obligations created by all leases with terms of greater than twelve months. The guidance requires qualitative disclosures along with certain specific quantitative disclosures for both lessees and lessors. In July 2018, the FASB issued ASU No. 2018-10, Codification Improvements to Topic 842, Leases (“ASU 2018-10”), and ASU No. 2018-11, Leases (Topic 842): Targeted Improvements (“ASU 2018-11”), to provide additional guidance for the adoption of Topic 842. The ASU and its related amendments are effective for fiscal years beginning after December 15, 2018, with early adoption permitted, and are effective for interim periods in the year of adoption. The ASU should be applied using a modified retrospective approach, which requires lessees and lessors to recognize and measure leases at the beginning of the earliest period presented with an option to use certain practical expedients, which we expect to use. We have evaluated the impact of this new guidance and reviewed lease or possible lease contracts and evaluated contract related processes. We believe the primary impact will be related to the recognition of right-of-use assets and liabilities for our real estate operating leases in the range of approximately $1.0 million to $1.5 million.

In January 2017, the FASB issued ASU No. 2017-04, Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment ("ASU 2017-04"). ASU 2017-04 simplifies the subsequent measurement of goodwill by eliminating Step 2 from the goodwill impairment test. Under this update, an entity should perform its annual or interim goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount, including goodwill. An entity should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit's fair value. However, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. ASU 2017-04 should be applied on a prospective basis and is effective for annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. We adopted ASU 2017-04 effective January 1, 2019, and the adoption of this standard did not have a material impact on the Company's consolidated financial statements.

In June 2018, the FASB issued ASU No. 2018-07, Compensation - Stock Compensation (Topic 718): Improvements to Non-employee Share-Based Payment Accounting ("ASU 2018-07"). ASU 2018-07 primarily expands the scope of Topic 718 to include share-based payment transactions for acquiring goods and services from non-employees. ASU 2018-07 is effective for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. We adopted ASU 2018-07 effective January 1, 2019, and the adoption of this standard did not have a material impact on the Company's consolidated financial statements.

3. Revenues

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

We record gross receipts taxes on a gross basis in retail revenues and retail cost of revenues. During the year ended December 31, 2018, 2017 and 2016 our retail revenues included gross receipts taxes of $6.9 million, $6.4 million and $3.9 million respectively. During the year ended December 31, 2018, 2017 and 2016, our retail cost of revenues included gross receipts taxes of $9.9 million, $9.0 million and $5.3 million, respectively.

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

The following is a description of our principal revenue generating activities.

Retail Electricity

Revenues for electricity sales are recognized under the accrual method when our performance obligation to a customer is satisfied, which is the point in time when the product is delivered and control of the product passes to the customer. Electricity products may be sold as fixed or variable rate products. The typical length of a contract to provide electricity is 12 months. Customers are billed and typically pay at least monthly, based on usage. Electricity sales that have been delivered but not billed by period end are estimated. Accrued unbilled revenues are based on estimates of customer usage since the date of the last meter read provided by the utility. Volume estimates are based on forecasted volumes and estimated residential and commercial customer usage. Unbilled revenues are calculated by multiplying these volume estimates by the applicable rate by customer class (residential or commercial). Estimated amounts are adjusted when actual usage is known and billed.

Retail Natural Gas

Revenues for natural gas sales are recognized under the accrual method when our performance obligation to a customer is satisfied, which is the point in time when the product is delivered and control of the product passes to the customer. Natural gas products may be sold as fixed-price or variable-price products. The typical length of a contract to provide natural gas is 12 months. Customers are billed and typically pay at least monthly, based on usage. Natural gas sales that have been delivered but not billed by period end are estimated and recorded as accrued unbilled revenues based on estimates of customer usage since the date of the last meter read provided by the utility. Volume estimates are based on forecasted volumes and estimated residential and commercial customer usage. Unbilled revenues are calculated by multiplying these volume estimates by the applicable rate by customer class (residential or commercial). Estimated amounts are adjusted when actual usage is known and billed.

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

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Reportable Segments
	Year Ended December 31, 2018									Year Ended December 31, 2017						Year Ended December 31, 2016
	Retail Electricity			Retail Natural Gas			Total Reportable Segments			Retail Electricity		Retail Natural Gas		Total Reportable Segments		Retail Electricity		Retail Natural Gas		Total Reportable Segments

Primary markets (a)
New England	$	395,682		$	21,221		$	416,903		$	229,546	$	21,196	$	250,742	$	115,360	$	21,758	$	137,118
Mid-Atlantic	291,046			54,815			345,861			272,127		52,737		324,864		197,511		38,387		235,898
Midwest	73,167			39,894			113,061			59,506		37,792		97,298		45,881		37,318		83,199
Southwest	103,556			22,036			125,592			96,387		29,481		125,868		58,477		32,591		91,068
	$	863,451		$	137,966		$	1,001,417		$	657,566	$	141,206	$	798,772	$	417,229	$	130,054	$	547,283

Customer type
Commercial	$	355,607		$	50,156		$	405,763		$	195,356	$	50,424	$	245,780	$	119,543	$	55,347	$	174,890
Residential	518,261			93,186			611,447			441,580		89,889		531,469		281,537		70,082		351,619
Unbilled revenue (b)	(10,417		)	(5,376		)	(15,793		)	20,630		893		21,523		16,149		4,625		20,774
	$	863,451		$	137,966		$	1,001,417		$	657,566	$	141,206	$	798,772	$	417,229	$	130,054	$	547,283

Customer credit risk
POR	$	586,901		$	71,565		$	658,466		$	447,581	$	76,002	$	523,583	$	307,836	$	57,198	$	365,034
Non-POR	276,550			66,401			342,951			209,985		65,204		275,189		109,393		72,856		182,249
	$	863,451		$	137,966		$	1,001,417		$	657,566	$	141,206	$	798,772	$	417,229	$	130,054	$	547,283

(a) The primary markets noted above include the following states:


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


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


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


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

(b) Unbilled revenue is recorded in total until it is actualized, at which time it is categorized between commercial and residential customers.

4. Acquisitions

Acquisition of the Provider Companies

In August 2016, we completed the purchase of all of the outstanding membership interests of the Provider Companies for approximately $34.1 million, which included $1.3 million in working capital, subject to adjustments. The acquisition also included an earnout provision of up to $9.0 million, which was initially valued at $4.8 million as of the purchase date, and which was to be paid by June 30, 2017, subject to the achievement of certain performance targets (the "Provider Earnout"). See Note 11 "Fair Value Measurements" for further information on the Provider Earnout. The Provider Companies serve electrical customers in Maine, New Hampshire and Massachusetts.

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The acquisition of the Provider Companies was accounted for under the acquisition method of accounting. The allocation of purchase consideration was based upon the estimated fair value of the tangible and identifiable intangible assets acquired and liabilities assumed in the acquisition. The allocation was made to major categories of assets and liabilities based on management’s best estimates, and supported by independent third-party analyses. The excess of the purchase price over the estimated fair value of tangible and intangible assets acquired and liabilities assumed was allocated to goodwill. The purchase price allocation for the acquisition of the Provider Companies was finalized as of December 31, 2016 as follows:



	Final Purchase Price Allocation
Cash	$	431
Net working capital, net of cash acquired	812
Intangible assets—customer relationships and non-compete agreements	24,417
Intangible assets—trademark	529
Goodwill	26,040
Fair value of derivative liabilities	(18,163		)
Total	$	34,066

The fair values of intangible assets were measured primarily based on significant inputs that are not observable in the market and thus represent a Level 3 fair value measurement. The fair value of derivative liabilities were measured by utilizing readily available quoted market prices and non-exchange-traded contracts fair valued using market price quotations available through brokers or over-the-counter and on-line exchanges and represent a Level 2 fair value measurement. See Note 11 "Fair Value Measurements" for further discussion on the fair values hierarchy. The valuation of intangible assets and goodwill are discussed later in this note. The Provider Earnout was settled at $5.5 million in 2017, including interest.

The Company’s consolidated statements of operations for the year ended December 31, 2016 included $46.8 million of revenue and $12.8 million of losses from operations related to the operations of the Provider Companies.

Acquisition of the Major Energy Companies

In August 2016, we completed the purchase of all of the outstanding membership interests of the Major Energy Companies, which are retail energy companies operating in Connecticut, Illinois, Maryland (including the District of Columbia), Massachusetts, New Jersey, New York, Ohio, and Pennsylvania across 43 utilities, from NG&E. The total purchase price was $64.1 million, which included $5.2 million in working capital; an assumed litigation reserve of $5.0 million, and up to $35.0 million in installment and earnout payments, valued at $13.1 million as of NG&E's April 15, 2016 purchase date, to be paid to the previous members of the Major Energy Companies, in annual installments on March 31, 2017, 2018 and 2019, subject to the achievement of certain performance targets (the “Major Earnout”). Additionally, the Company was potentially obligated to issue up to 400,000 shares of Class B common stock (and a corresponding number of Spark HoldCo units) to NG&E, subject to the achievement of certain performance targets, which were valued at $0.8 million as of the purchase date (the "Stock Earnout"). No shares were subsequently issued under the Stock Earnout provisions. See Note 11 "Fair Value Measurements" for further information on the Major Earnout and Stock Earnout.

The acquisition of the Major Energy Companies from NG&E was treated as a transfer of interests in entities under common control. Accordingly, the impact from the assets acquired and liabilities assumed were based on those values and results from the date NG&E acquired the Major Energy Companies, which was April 15, 2016. The fair value allocation of the net assets acquired was as follows (in thousands):

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	Final Purchase Price Allocation
Cash	$	17,368
Property and equipment	14
Intangible assets—customer relationships & non-compete agreements	24,271
Other assets—trademarks	4,973
Non-current deferred tax assets	1,042
Goodwill	34,988
Net working capital, net of cash acquired	(6,746		)
Fair value of derivative liabilities	(7,260		)
Total	$	68,650

In December 2016, certain executives of the Major Energy Companies exercised a change of control provision under employment agreements with the Major Energy Companies. As a result, the Company recorded employment contract termination costs of $4.1 million as of December 31, 2016. The Company paid employment contract termination costs totaling approximately $1.4 million and $2.5 million during the years ended December 31, 2018 and 2017, respectively, with the remaining costs of $0.2 million recorded as a liability as of December 31, 2018.

The Major Energy Companies contributed revenues of $125.6 million and earnings of $1.3 million to the Company for the year ended December 31, 2016. The following unaudited pro forma revenue and earnings summary presents consolidated information of the Company for 2016 as if the acquisition had occurred on January 1, 2015 (in thousands):



	Year Ended December 31,
	2016	2015
Revenue	$603,673	$547,381
Earnings	$15,776	$15,460

The pro forma results are not necessarily indicative of our consolidated results of operations that actually would have been realized had the companies operated on a combined basis during the period presented. The revenue and earnings for the twelve months ended December 31, 2016 reflects actual results of operations for the period from April 15, 2016 (the date of NG&E's acquisition) through December 31, 2016, the period the financial results were fully combined. The pro forma results include adjustments related to amortization of acquired intangibles, and certain accounting policy alignments as well as direct and incremental acquisition related costs reflected in the historical financial statements. The purchase price allocation was used to prepare the pro forma adjustments.

Acquisition of Perigee

In April 2017, we acquired all of the outstanding membership interests of Perigee Energy, LLC, a Texas limited liability company ("Perigee"), with operations across 14 utilities in Connecticut, Delaware, Massachusetts, New York and Ohio from our affiliate, NG&E. The purchase price for Perigee from NG&E was approximately $4.1 million, which consisted of a base price of $2.0 million, $0.2 million additional customer option payment, and $1.9 million in working capital, subject to adjustments. The acquisition was treated as a transfer of equity interests between entities under common control, and accordingly, the assets acquired and liabilities assumed were based on their historical value as of the date. NG&E acquired Perigee, which was on February 3, 2017, and the fair value of the net assets acquired was as follows (in thousands):

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	Final Purchase Price Allocation
Cash	$	23
Intangible assets—customer relationships	1,100
Goodwill	1,540
Net working capital, net of cash acquired	2,085
Fair value of derivative liabilities	(443		)
Total	$	4,305

The Perigee acquisition did not have a material impact on our financial position or results of operations.

Acquisition of Verde

In July 2017, we acquired, through our subsidiary CenStar Energy Corp. ("CenStar"), all of the outstanding membership interests and stock in a group of companies (the "Verde Companies") from Verde Energy USA Holdings, LLC (the “Seller”). Total consideration was approximately $90.7 million, of which $20.1 million represented positive net working capital, as adjusted. We also entered into an agreement to pay an additional amount based on achievement by the Verde Companies of certain performance targets over the 18 month period following closing of the acquisition (the "Verde Earnout"). The Verde Earnout was initially valued at $5.4 million. The acquisition of the Verde Companies was accounted for under the acquisition method. The allocation of purchase consideration was based upon the estimated fair value of the tangible and identifiable intangible assets acquired and liabilities assumed in the acquisition based on management's best estimates, and was supported by independent third-party analyses. The excess of the purchase price over the estimated fair value of tangible and intangible assets acquired and liabilities assumed was allocated to goodwill. The allocation of the purchase consideration was as follows (in thousands):



	December 31, 2017			Adjustments ⁽¹⁾			As of December 31, 2018
Cash and restricted cash	$	1,653		$	—		$	1,653
Property and equipment	4,560			—			4,560
Intangible assets—customer relationships	28,700			—			28,700
Intangible assets—trademarks	3,000			—			3,000
Goodwill	39,207			189			39,396
Net working capital, net of cash acquired	19,132			(659		)	18,473
Deferred tax liability	(3,126		)	—			(3,126		)
Fair value of derivative liabilities	(1,942		)	—			(1,942		)
Total	$	91,184		$	(470	)	$	90,714

(1) Changes to the purchase price allocation in 2018 were due to an agreement to settle the working capital balances with Verde Companies' sellers per the purchase agreement.

The Verde Earnout was based on achievement by the Verde Companies of certain performance targets over the 18 month period following the closing of the Verde acquisition. In January 2018, we settled the Verde Earnout by issuing a $5.9 million note payable to the Seller.

The Verde Companies contributed revenues of $76.0 million and earnings of $1.2 million to the Company for the year ended December 31, 2017.

The following unaudited pro forma revenue and earnings summary presents consolidated information of the Company as if the acquisition had occurred on January 1, 2016 (in thousands):

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	Year Ended December 31,
	2017		2016
Revenues	$	868,415	$	716,696
Earnings	$	18,047	$	17,860

The pro forma results are not necessarily indicative of our consolidated results of operations that actually would have been realized had the companies operated on a combined basis during the periods presented. The pro forma results above include actual results and costs as well as adjustments primarily related to amortization of acquired intangibles, and certain accounting policy alignments as well as direct and incremental acquisition related costs reflected in the historical financial statements. Our initial purchase price allocation was used to prepare the pro forma adjustments.

Acquisition of HIKO

In March 2018, we entered into a Membership Interest Purchase Agreement under which we acquired all of the membership interests of HIKO Energy, LLC ("HIKO"), a New York limited liability company, for a total purchase price of $6.0 million in cash, plus working capital. At the time of acquisition, HIKO had a total of approximately 29,000 RCEs located in 42 markets in seven states. The acquisition was accounted for under the acquisition method. Our preliminary allocation of the purchase price was based upon the estimated fair value of the tangible and identified intangible assets acquired and liabilities assumed in the acquisition. The preliminary allocation was made based on management’s best estimates, and supported by independent third-party analyses. The allocation of the purchase consideration is as follows (in thousands):



	Preliminary Purchase Price Allocation			2018 Adjustments ⁽¹⁾			Purchase Price Allocation as of December 31, 2018
Cash and restricted cash	$	309		$	66		$	375
Intangible assets—customer relationships	6,205			(174		)	6,031
Net working capital, net of cash acquired	9,041			(576		)	8,465
Fair value of derivative liabilities	(205		)	—			(205		)
Total	$	15,350		$	(684	)	$	14,666

(1) Changes to the purchase price allocation were due to an agreement to settle the working capital balances with HIKO sellers per the purchase agreement.

Our condensed consolidated statements of operations for the twelve months ended December 31, 2018 included $15.3 million of revenue and $3.8 million of net income related to the operations of HIKO.

In each of our acquisitions, we evaluate and allocate purchase price based on the following general assumptions.

Customer relationships. Acquired customer relationships were reflective of the acquired companies' customer bases, and were valued using an excess earnings method under the income approach. Using this method, we estimated the future cash flows resulting from the existing customer relationships, considering estimated attrition as well as charges for contributory assets, such as net working capital, intangible assets, fixed assets, and any assembled workforce. These future cash flows were then discounted using an appropriate risk-adjusted rate of return to arrive at the present value of the expected future cash flows.

In acquisitions where we acquired commodity contracts that we could match to fixed-price contracts, customer relationships were bifurcated between unhedged and hedged and are being amortized based on the expected term of the underlying fixed-price contract acquired in each reporting period, respectively.

Non-compete Agreements. The fair value of non-compete agreements were determined using the differential value approach. Under this approach, we estimated the present value of expected future cash flows of the business with

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and without the non-compete agreement. The difference in discounted cash flows was then adjusted by probability factors related to the likelihood that those with the non-compete agreements would be successful competitors.

Trademarks. The fair value of acquired trademarks is reflective of the value associated with the recognition and reputation of the acquired company to target markets. The fair value of trademarks was valued using a royalty savings method under the income approach. The value was based on the savings we would realize from owning the trademark rather than paying a royalty for the use of that trademark. Under this approach, we estimate the present value of the expected cash flows resulting from avoiding royalty payments to use a third party trademark. In the Verde acquisition, we analyzed market royalty rates charged for licensing trademarks and applied an expected royalty rate to a forecast of estimated revenue, which was then discounted using an appropriate risk adjusted rate of return.

Goodwill. The excess of the purchase consideration over the estimated fair value of the amounts initially assigned to the identifiable assets acquired and liabilities assumed was recorded as goodwill. Goodwill arose on the acquisitions of the Provider Companies, Verde Companies and Perigee primarily due to the value of their assembled workforce, proprietary sales channels, and/or access to new utility service territories. Goodwill arose on the acquisition of the Major Energy Companies primarily due to the value of the Major Energy Companies brand strength, established vendor relationships and access to new utility service territories. Goodwill recorded in connection with these acquisitions is deductible for income tax purposes because these were acquisitions of all of the assets of the companies.

Customer Acquisitions. We also, from time to time, acquire books of customers from affiliated and non-affiliated parties. These acquisitions do not involve an allocation of the purchase price but rather are recorded as customer relationships.

Acquisition of customers from Perigee

In April 2017, we acquired approximately 44,000 RCEs from the original owner of Perigee. During 2017, we paid $7.5 million for customers transferred.

Acquisition from Related Parties

In March 2018, we entered into an asset purchase agreement with our affiliate, NG&E, pursuant to which we agreed to acquire up to 50,000 RCEs for a cash purchase price of $250 for each RCE, or up to $12.5 million in the aggregate. These customers began transferring after April 1, 2018 and are located in 24 markets in 8 states. For the year ended December 31, 2018, we paid NG&E $8.8 million under the terms of the purchase agreement for approximately 35,000 RCEs. We do not anticipate any additional customer transfers or consideration will be paid on this transaction. The acquisition was treated as a transfer of assets between entities under common control, and accordingly, the assets were recorded at NG&E's historical value at the date of transfer, which was $1.7 million. The transaction resulted in $7.1 million recorded in equity as a net distribution to affiliate as of December 31, 2018. Of the $8.8 million paid to NG&E, $1.7 million was an investing cash outflow and remaining $7.1 million was deemed a distribution to our non-controlling interest and classified as financing activity.

Acquisitions of Customer Books

In October 2018, we entered into an asset purchase agreement pursuant to which we would acquire up to 60,000 RCEs from Starion Energy Inc., Starion Energy NY Inc. and Starion Energy PA Inc. for a cash purchase price of up to a maximum of $10.7 million. These customers began transferring in December 2018, and are located in our existing markets.

As part of the acquisition, we funded an escrow account, the balance of which is reflected as restricted cash in our consolidated balance sheet. As of December 31, 2018, the balance in the account was $8.6 million, and these funds will be released to the seller as acquired customers transfer from the seller to the Company in accordance with the

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asset purchase agreement, and any unallocated balance will be returned to the Company once the acquisition is complete.

5. Equity

Non-controlling Interest

We hold an economic interest and are the sole managing member in Spark HoldCo, with affiliates of our Founder and majority shareholder holding the remaining economic interests in Spark HoldCo. As a result, we consolidate the financial position and results of operations of Spark HoldCo and reflect the economic interests owned by these affiliates as a non-controlling interest. The Company and affiliates owned the following economic interests in Spark HoldCo at December 31, 2017 and December 31, 2018, respectively.



	The Company		Affiliated Owners
December 31, 2017	38.12	%	61.88	%
December 31, 2018	40.53	%	59.47	%

The Spark HoldCo Third Amended and Restated Limited Liability Company Agreement provides that if the Company issues a new share of Class A common stock, par value $0.01 per share (the "Class A common stock"), Series A Preferred Stock (as defined below), or other equity security of the Company (other than shares of Class B common stock, par value $0.01 per share ("Class B common stock"), and excluding issuances of Class A common stock upon an exchange of Class B common stock or Series A Preferred Stock), Spark HoldCo will concurrently issue a corresponding limited liability company unit either to the holder of the Class B common stock, or to the Company in the case of the issuance of shares of Class A common stock, Series A Preferred Stock or such other equity security. As a result, the number of Spark HoldCo units held by the Company always equals the number of shares of Class A common stock, Series A Preferred Stock or such other equity securities of the Company outstanding.

Each share of Class B common stock has no economic rights but entitles the holder to one vote on all matters to be voted on by stockholders generally. Holders of Class A common stock and Class B common stock vote together as a single class on all matters presented to our stockholders for their vote or approval, except as otherwise required by applicable law or by our certificate of incorporation.

We adjust the balances in additional paid in capital and non-controlling interest in our consolidated statements of stockholders’ equity and our balance sheet at the end of each balance sheet period to reflect the amounts the respective owners of our Class A and Class B common stock would receive if the assets of our subsidiary, Spark HoldCo were sold, and the liabilities were settled at their recorded book values as of each respective balance sheet date. These adjustments for changes in ownership interests do not impact the manner in which income is allocated or the manner in which distributions are paid to Class A or Class B shareholders.

The Class B holders have the right to exchange (the “Exchange Right”) all or a portion of their Spark HoldCo units (together with a corresponding number of shares of Class B common stock) for Class A common stock (or cash at Spark Energy, Inc.’s or Spark HoldCo’s election (the “Cash Option”)) at an exchange ratio of one share of Class A common stock for each Spark HoldCo unit (and corresponding share of Class B common stock) exchanged. In addition, Class B holders have the right, under certain circumstances, to cause the Company to register the offer and resale of such owners' shares of Class A common stock obtained pursuant to the Exchange Right.

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



	2018			2017			2016

Net (loss) income allocated to non-controlling interest	$	(12,140	)	$	55,068		$	52,300
Income tax expense (benefit) allocated to non-controlling interest	1,066			(731		)	1,071
Net (loss) income attributable to non-controlling interest	$	(13,206	)	$	55,799		$	51,229

Stock Split

In May 2017, the Company authorized and approved a two-for-one stock split of the Company's issued Class A common stock and Class B common stock, which was effected through a stock dividend (the "Stock Split"). Shareholders of record at the close of business on June 5, 2017 were issued one additional share of Class A common stock or Class B common stock of the Company for each share of Class A common stock or Class B common stock, respectively, held by such shareholder on that date. Such additional shares of Class A common stock or Class B common stock were distributed on June 16, 2017. All shares and per share amounts in this report have been retrospectively restated to reflect the Stock Split.

Issuance of Class A Common Stock Upon Vesting of Restricted Stock Units

For the years ended December 31, 2018, 2017, and 2016, 394,243, 356,014, and 395,056, respectively of restricted stock units vested, with 258,076, 241,965, and 305,872, respectively of shares of common stock distributed to the holders of these units. Differences between shares vested and issued were a result of 136,167, 114,049, and 89,184 shares of common stock withheld by the Company to cover taxes owed on the vesting of such units.

Conversion of Class B Common Stock to Class A Common Stock

In 2018 and 2016, holders of Class B common stock exchanged 685,126 and 6,450,000 respectively, of their Spark HoldCo units (together with a corresponding number of shares of Class B common stock) for shares of Class A common stock at an exchange ratio of one share of Class A common stock for each Spark HoldCo unit (and corresponding share of Class B common stock) exchanged.

Dividends on Class A Common Stock

During the years ended December 31, 2018, 2017, and 2016, we paid dividends on our Class A Common Stock of $9.8 million, $9.5 million, and $8.4 million. This dividend represented an annual rate of $0.725 per share on each share of Class A common stock.

On January 17, 2019, the Company declared a dividend of $0.18125 per share to holders of record of our Class A common stock on March 1, 2019 and payable on March 15, 2019.

Issuance of Class B Common Stock

In August 2016, the Company issued 1,399,484 shares of Class B common stock to an affiliate in connection with the acquisition of the Provider Companies and also issued 4,000,000 shares of Class B common stock to the affiliate in connection with the acquisition of Major Energy Companies.

Preferred Stock

The Company has 20,000,000 shares of authorized preferred stock for which there are 3,707,256 and 1,704,339 issued and outstanding shares at December 31, 2018 and 2017. See Note 6 "Preferred Stock" for a further discussion of preferred stock.

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Conversion of CenStar and Oasis Notes

In January 2017, several notes issued in connection with our acquisitions of CenStar and Oasis in 2016 were converted into 1,035,642 shares of Class B common stock (and related Spark HoldCo units). Refer to Note 10 "Debt" for further discussion.

Earnings Per Share

Basic earnings per share (“EPS”) is computed by dividing net income attributable to stockholders (the numerator) by the weighted-average number of Class A common shares outstanding for the period (the denominator). Class B common shares are not included in the calculation of basic earnings per share because they are not participating securities and have no economic interests. Diluted earnings per share is similarly calculated except that the denominator is increased by potentially dilutive securities. The following table presents the computation of basic and diluted (loss) earnings per share for the years ended December 31, 2018, 2017, and 2016 (in thousands, except per share data):



	Year Ended December 31,
	2018			2017		2016
Net income attributable to Spark Energy, Inc. stockholders	$	(1,186	)	$	19,245	$	14,444
Less: Dividend on Series A preferred stock	8,109			3,038		—
Net (loss) income attributable to stockholders of Class A common stock	$	(9,295	)	$	16,207	$	14,444

Basic weighted average Class A common shares outstanding	13,390			13,143		11,402
Basic (loss) earnings per share attributable to stockholders	$	(0.69	)	$	1.23	$	1.27

Net (loss) income attributable to stockholders of Class A common stock	$	(9,295	)	$	16,207	$	14,444
Effect of conversion of Class B common stock to shares of Class A common stock	—			—		—
Effect of conversion of convertible subordinated notes into shares of Class B common stock and shares of Class B common stock into shares of Class A common stock ⁽¹⁾	—			—		(310		)
Diluted net (loss) income attributable to stockholders of Class A common stock	$	(9,295	)	$	16,207	$	14,134

Basic weighted average Class A common shares outstanding	13,390			13,143		11,402
Effect of dilutive Class B common stock	—			—		—
Effect of dilutive convertible subordinated notes into shares of Class B common stock and shares of Class B common stock into shares of Class A common stock	—			—		1,010
Effect of dilutive restricted stock units	—			203		278
Diluted weighted average shares outstanding	13,390			13,346		12,690

Diluted (loss) earnings per share attributable to stockholders	$	(0.69	)	$	1.21	$	1.11

(1) The CenStar Note and Oasis Note converted into 269,462 and 766,180 shares of Class B common stock on January 8, 2017, and January 31, 2017, respectively.

The computation of diluted earnings per share for the year ended December 31, 2018 excludes 20.8 million shares of Class B common stock and 0.9 million restricted stock units because the effect of their conversion was antidilutive. The Company's outstanding shares of Series A Preferred Stock were not included in the calculation of diluted earnings per share because they contain only contingent redemption provisions which have not occurred.

Variable Interest Entity

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Spark HoldCo is a variable interest entity due to its lack of rights to participate in significant financial and operating decisions and its inability to dissolve or otherwise remove its management. Spark HoldCo owns all of the outstanding membership interests in each of our operating subsidiaries. We are the sole managing member of Spark HoldCo, manage Spark HoldCo's operating subsidiaries through this managing membership interest, and are considered the primary beneficiary of Spark HoldCo. The assets of Spark HoldCo cannot be used to settle our obligations except through distributions to us, and the liabilities of Spark HoldCo cannot be settled by us except through contributions to Spark HoldCo. The following table includes the carrying amounts and classification of the assets and liabilities of Spark HoldCo that are included in our consolidated balance sheet as of December 31, 2018 (in thousands):



	December 31, 2018		December 31, 2017
Assets
Current assets:
Cash and cash equivalents	$	36,724	$	29,385
Accounts receivable	150,866		158,814
Other current assets	92,963		105,165
Total current assets	280,553		293,364
Non-current assets:
Goodwill	120,343		120,154
Other assets	47,159		62,552
Total non-current assets	167,502		182,706
Total Assets	$	448,055	$	476,070

Liabilities
Current liabilities:
Accounts Payable and Accrued Liabilities	$	122,497	$	110,152
Current portion of Senior Credit Facility	—		7,500
Contingent consideration	1,328		4,024
Other current liabilities	16,525		8,933
Total current liabilities	140,350		130,609
Long-term liabilities:
Long-term portion of Senior Credit Facility	129,500		117,750
Subordinated debt—affiliate	10,000		—
Contingent consideration	—		626
Other long-term liabilities	319		663
Total long-term liabilities	139,819		119,039
Total Liabilities	$	280,169	$	249,648

6. Preferred Stock

In March 2017, we issued 1,610,000 shares of 8.75% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Stock ("Series A Preferred Stock"), par value $0.01 per share and having a liquidation preference $25.00 per share, plus accumulated and unpaid dividends, at a price to the public of $25.00 per share ($24.21 per share to us, net of underwriting discounts and commissions). We received approximately $39.0 million in net proceeds from the offering, after deducting underwriting discounts and commissions and a structuring fee. Offering expenses of $1.0 million were recorded as a reduction to the carrying value of the Series A Preferred Stock.

In July 2017, we entered into an At-the-Market Issuance Sales Agreement ("the ATM Agreement") with FBR Capital Markets & Co. as sales agent (the "Agent"). Pursuant to the terms of the ATM Agreement, we may sell,

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from time to time through the Agent, our Series A Preferred Stock, having an aggregate offering price of up to $50.0 million. During the year ended December 31, 2017, we issued an aggregate of 94,339 shares of Series A Preferred Stock under the ATM Agreement. We received net proceeds of $2.4 million and paid compensation to the sales agent of less than $0.1 million with respect to these sales. During the year ended December 31, 2018, we issued an aggregate of 2,917 shares of Series A Preferred Stock under the ATM Agreement. We received net proceeds of $0.1 million and paid compensation to the sales agent of less than $0.1 million with respect to these sales.

In January 2018, we issued 2,000,000 shares of Series A Preferred Stock, plus accumulated and unpaid dividends, at a price to the public of $25.25 per share ($24.45 per share, net of underwriting discounts and commissions). The Company received approximately $48.9 million in net proceeds from the offering, after deducting underwriting discounts and commissions and a structuring fee. Offering expenses of $0.5 million were recorded as a reduction to the carrying value of the Series A Preferred Stock.

Holders of the Series A Preferred Stock have no voting rights, except in specific circumstances of delisting or in the case the dividends are in arrears as specified in the Series A Preferred Stock Certificate of Designations. The Series A Preferred Stock accrue dividends at an annual percentage rate of 8.75%, and the liquidation preference provisions of the Series A Preferred Stock are considered contingent redemption provisions because there are rights granted to the holders of the Series A Preferred Stock that are not solely within our control upon a change in control of the Company. Accordingly, the Series A Preferred Stock is presented between liabilities and the equity sections in the accompanying consolidated balance sheet.

During the year ended December 31, 2018, the Company paid $7.0 million in dividends to holders of the Series A Preferred Stock and had accrued $2.0 million related to dividends to holders of the Series A Preferred Stock at December 31, 2018, which were paid on January 15, 2019. During the year ended December 31, 2017, the Company paid $2.1 million in dividends to holders of the Series A Preferred Stock and had accrued $0.9 million as of December 31, 2017.

On January 17, 2019, the Company declared a quarterly cash dividend in the amount of $0.546875 per share of Series A Preferred Stock. This amount represents an annualized dividend of $2.1875 per share. The dividend will be paid on April 15, 2019 to holders of record on April 1, 2019 of the Series A Preferred Stock.

A summary of our preferred equity balance for the years ended December 31, 2018 and 2017 is as follows:



	(in thousands)
Balance at December 31, 2016	$	—
Issuance of Series A Preferred Stock, net of issuance cost	40,241
Accumulated dividends on Series A Preferred Stock	932
Balance at December 31, 2017	$	41,173
Issuance of Series A Preferred Stock, net of issuance cost	48,490
Accumulated dividends on Series A Preferred Stock	1,095
Balance at December 31, 2018	$	90,758

In connection with the issuance of the Series A Preferred Stock, the Company and Spark HoldCo entered into the Third Amended and Restated Spark HoldCo Limited Liability Company Agreement to amend the prior agreement to provide for, among other things, the designation and issuance of Spark HoldCo Series A preferred units, as another equity security of Spark HoldCo to be issued concurrently with the issuance of Series A Preferred Stock by us, including specific terms relating to distributions by Spark HoldCo in connection with the payment by us of dividends on the Series A Preferred Stock, the priority of liquidating distributions by Spark HoldCo, the allocation of income and loss to us in connection with distributions by Spark HoldCo on Series A preferred units, and other terms relating to the redemption and conversion by us of the Series A Preferred Stock.

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7. Derivative Instruments

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

Derivative assets and liabilities are presented net in our consolidated balance sheets when the derivative instruments are executed with the same counterparty under a master netting arrangement. Our derivative contracts include transactions that are executed both on an exchange and centrally cleared, as well as over-the-counter, bilateral contracts that are transacted directly with third parties. To the extent we have paid or received collateral related to the derivative assets or liabilities, such amounts would be presented net against the related derivative asset or liability’s fair value. As of December 31, 2018 and 2017, we had paid zero and $0.1 million in collateral, respectively. The specific types of derivative instruments we may execute to manage the commodity price risk include the following:


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


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


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


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

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

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

•Natural gas transportation contracts and storage agreements.

Volumes Underlying Derivative Transactions

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

Non-trading



Commodity	Notional	December 31, 2018	December 31, 2017
Natural Gas	MMBtu	8,176	9,191
Natural Gas Basis	MMBtu	115	—
Electricity	MWh	6,781	8,091

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Commodity	Notional	December 31, 2018		December 31, 2017
Natural Gas	MMBtu	188		26
Natural Gas Basis	MMBtu	(380	)	(225	)

Gains (Losses) on Derivative Instruments

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



	Year Ended December 31,
	2018			2017			2016
(Loss) gain on non-trading derivatives, net	(19,571		)	5,588			22,254
Gain (loss) on trading derivatives, net	1,401			(580		)	153
(Loss) gain on derivatives, net	$	(18,170	)	$	5,008		$	22,407
Current period settlements on non-trading derivatives⁽¹⁾	(9,614		)	16,508			(2,284		)
Current period settlements on trading derivatives	(973		)	(199		)	138
Total current period settlements on derivatives ⁽¹⁾	$	(10,587	)	$	16,309		$	(2,146	)

(1) Excludes settlements of $(0.3) million, $3.4 million and $26.6 million, respectively, for the years ended December 31, 2018, 2017, and 2016 related to non-trading derivative liabilities assumed in various acquisitions.

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

Fair Value of Derivative Instruments

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



	December 31, 2018
Description	Gross Assets		Gross Amounts Offset			Net Assets		Cash Collateral Offset		Net Amount Presented
Non-trading commodity derivatives	$	18,649	$	(12,000	)	$	6,649	$	—	$	6,649
Trading commodity derivatives	734		(94		)	640		—		640
Total Current Derivative Assets	19,383		(12,094		)	7,289		—		7,289
Non-trading commodity derivatives	9,657		(6,381		)	3,276		—		3,276
Trading commodity derivatives	—		—			—		—		—
Total Non-current Derivative Assets	9,657		(6,381		)	3,276		—		3,276
Total Derivative Assets	$	29,040	$	(18,475	)	$	10,565	$	—	$	10,565

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Description	Gross Liabilities			Gross Amounts Offset		Net Liabilities			Cash Collateral Offset		Net Amount Presented
Non-trading commodity derivatives	$	(21,391	)	$	15,385	$	(6,006	)	$	—	$	(6,006	)
Trading commodity derivatives	(491		)	19		(472		)	—		(472		)
Total Current Derivative Liabilities	(21,882		)	15,404		(6,478		)	—		(6,478		)
Non-trading commodity derivatives	(71		)	40		(31		)			(31		)
Trading commodity derivatives	(135		)	60		(75		)	—		(75		)
Total Non-current Derivative Liabilities	(206		)	100		(106		)	—		(106		)
Total Derivative Liabilities	$	(22,088	)	$	15,504	$	(6,584	)	$	—	$	(6,584	)



	December 31, 2017
Description	Gross Assets		Gross Amounts Offset			Net Assets		Cash Collateral Offset		Net Amount Presented
Non-trading commodity derivatives	$	60,167	$	(29,432	)	$	30,735	$	—	$	30,735
Trading commodity derivatives	918		(462		)	456		—		456
Total Current Derivative Assets	61,085		(29,894		)	31,191		—		31,191
Non-trading commodity derivatives	16,055		(12,746		)	3,309		—		3,309
Trading commodity derivatives	—		—			—		—		—
Total Non-current Derivative Assets	16,055		(12,746		)	3,309		—		3,309
Total Derivative Assets	$	77,140	$	(42,640	)	$	34,500	$	—	$	34,500



Description	Gross Liabilities			Gross Amounts Offset		Net Liabilities			Cash Collateral Offset		Net Amount Presented
Non-trading commodity derivatives	$	(4,517	)	$	3,059	$	(1,458	)	$	65	$	(1,393	)
Trading commodity derivatives	(517		)	273		(244		)	—		(244		)
Total Current Derivative Liabilities	(5,034		)	3,332		(1,702		)	65		(1,637		)
Non-trading commodity derivatives	(676		)	732		56			—		56
Trading commodity derivatives	(566		)	18		(548		)	—		(548		)
Total Non-current Derivative Liabilities	(1,242		)	750		(492		)	—		(492		)
Total Derivative Liabilities	$	(6,276	)	$	4,082	$	(2,194	)	$	65	$	(2,129	)

Interest Rate Swaps

During the year ended December 31, 2018, we entered into two interest rate swap agreements to manage interest rate risk. The interest rate swap agreements were not designated as hedges for accounting purposes. As such, all changes in fair value were recognized in earnings, within interest and other income. As of December 31, 2018, the notional amount of the interest swap was $10.0 million. A fair value liability of less than $0.1 million was recorded in other current liabilities on the condensed consolidated balance sheet as of December 31, 2018.

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8. Property and Equipment

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



	Estimated useful lives (years)	December 31, 2018			December 31, 2017
Information technology	2 – 5	$	34,611		$	34,103
Leasehold improvements	2 – 5	4,568			4,568
Furniture and fixtures	2 – 5	1,964			1,964
Building improvements	2 – 5	268			809
Total		41,411			41,444
Accumulated depreciation		(37,045		)	(33,169		)
Property and equipment—net		$	4,366		$	8,275

Information technology assets include software and consultant time used in the application, development and implementation of various systems including customer billing and resource management systems. As of December 31, 2018 and 2017, information technology includes $0.3 million and $1.2 million, respectively, of costs associated with assets not yet placed into service.

Depreciation expense recorded in the consolidated statements of operations was $3.9 million, $2.6 million and $2.1 million for the years ended December 31, 2018, 2017 and 2016, respectively.

9. Intangible Assets

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




	December 31, 2018			December 31, 2017
Goodwill	$	120,343		$	120,154
Customer Relationships— Acquired
Cost	$	99,402		$	93,371
Accumulated amortization	(63,208		)	(46,681		)
Customer Relationships—Acquired & Non-Compete Agreements, net	$	36,194		$	46,690
Customer Relationships—Other
Cost	$	16,155		$	12,336
Accumulated amortization	(9,290		)	(5,534		)
Customer Relationships—Other, net	$	6,865		$	6,802
Trademarks
Cost	$	9,770		$	9,770
Accumulated amortization	(2,483		)	(1,212		)
Trademarks, net	$	7,287		$	8,558

Changes in goodwill, customer relationships (including non-compete agreements) and trademarks consisted of the following (in thousands):

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	Goodwill		Customer Relationships— Acquired & Non-Compete Agreements			Customer Relationships— Other			Trademarks
Balance at December 31, 2015	$	18,379	$	10,380		$	3,049		$	1,194
Acquisition of Provider Companies	26,040		24,417			—			529
Acquisition of Major Energy Companies	34,728		24,271			—			4,973
Amortization expense	—		(27,157		)	(1,437		)	(357		)
Balance at December 31, 2016	$	79,147	$	31,911		$	1,612		$	6,339
Adjustments ⁽¹⁾	$	260	$	—		$	—		$	—
Acquisition of Perigee	1,540		1,100			—			—
Acquisition of Verde	39,207		28,700			—			3,000
Additions (Other)	—		—			8,016			—
Amortization expense	—		(15,021		)	(2,826		)	(781		)
Balance at December 31, 2017	$	120,154	$	46,690		$	6,802		$	8,558
Additions	—		6,205			3,818			—
Adjustments⁽¹⁾	189		(174		)	—			—
Amortization	—		(16,527		)	(3,755		)	(1,271		)
Balance at December 31, 2018	$	120,343	$	36,194		$	6,865		$	7,287

(1) Related to working capital adjustments on various acquisitions.

The acquired customer relationship intangibles related to Major Energy Companies, the Provider Companies, and the Verde Companies were bifurcated between hedged and unhedged customer contracts. The unhedged customer contracts are amortized to depreciation and amortization based on the expected future cash flows by year. The hedged customer contracts were evaluated for favorable or unfavorable positions at the time of acquisition and amortized to retail cost of revenue based on the expected term and position of the underlying fixed price contract in each reporting period. For the years ended December 31, 2018, 2017, and 2016, respectively, approximately $(1.2) million, $0.3 million, and $15.8 million of the $16.5 million, $15.0 million, and $27.2 million acquired customer relationship amortization expense is included in the cost of revenues.

Estimated future amortization expense for customer relationships and trademarks at December 31, 2018 is as follows (in thousands):



Year Ending December 31,
2019	$	18,133
2020	12,257
2021	10,682
2022	5,780
2023	450
> 5 years	3,044
Total	$	50,346

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10. Debt

Debt consists of the following amounts as of December 31, 2018 and 2017 (in thousands):



	December 31, 2018		December 31, 2017
Current:
Senior Credit Facility—Bridge Loan ⁽¹⁾	$	—	$	7,500
Note Payable—Verde	6,936		13,443
Total current portion of debt	6,936		20,943
Long-term debt:
Senior Credit Facility ^{(1) (2)}	129,500		117,750
Subordinated Debt	10,000		—
Note Payable—Verde	—		7,051
Total long-term debt	139,500		124,801
Total debt	$	146,436	$	145,744

(1) As of December 31, 2018 and 2017, the weighted average interest rate on the Senior Credit Facility was 5.48% and 4.61%, respectively. (2) As of December 31, 2018 and 2017, we had $49.4 million and $47.2 million in letters of credit issued, respectively.

Capitalized financing costs associated with our Senior Credit Facility were $1.4 million and $1.6 million as of December 31, 2018 and 2017, respectively. Of these amounts, $1.0 million and $1.2 million are recorded in other current assets, and $0.4 million and $0.4 million are recorded in other non-current assets in the consolidated balance sheets as of December 31, 2018 and 2017, respectively.

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



	Years Ended December 31,
	2018		2017		2016
Senior Credit Facility	$	5,300	$	3,275	$	1,730
Accretion related to Earnouts	—		4,108		5,060
Letters of credit fees and commitment fees	1,604		1,125		883
Amortization of deferred financing costs	1,291		1,035		668
Convertible subordinated notes to affiliate	—		1,052		518
Subordinated debt	26		167		—
Verde promissory note	1,189		372		—
Interest expense	$	9,410	$	11,134	$	8,859

Senior Credit Facility

The Company, as guarantor, and Spark HoldCo (the “Borrower” and, together with each subsidiary of Spark HoldCo (“Co-Borrowers”) maintains a senior secured borrowing base credit facility (as amended, “Senior Credit Facility”) that allowed us to borrow up to $192.5 million as of December 31, 2018. Subject to applicable sublimits and terms of the Senior Credit Facility, as amended, borrowings are available for the issuance of letters of credit (“Letters of Credit”), working capital and general purpose revolving credit loans (“Working Capital Loans”), and bridge loans (“Bridge Loans”) for the purpose of partial funding for acquisitions. Borrowings under the Senior Credit Facility may be used to pay fees and expenses in connection with the Senior Credit Facility, finance ongoing working capital requirements and general corporate purpose requirements of the Co-Borrowers, to provide partial funding for acquisitions, as allowed under terms of the Senior Credit Facility, and to make open market purchases of our Class A common stock and Series A Preferred Stock. As of December 31, 2018, we had $129.5 million outstanding under the Senior Credit Facility, as well as $49.4 million of outstanding letters of credit.

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The Senior Credit Facility will mature on May 19, 2020, and all amounts outstanding thereunder will be payable on the maturity date. Borrowings under the Bridge Loan sublimit, if any, will be repaid 25% per year on a quarterly basis (or 6.25% per quarter), with the remainder due at maturity. As of December 31, 2018, there was zero in Bridge Loans outstanding.

At our election, the interest rate for Working Capital Loans and Letters of Credit under the Senior Credit Facility is generally determined by reference to the Eurodollar rate plus an applicable margin of up to 3.00% per annum (based on the prevailing utilization) or an alternate base rate plus an applicable margin of up to 2.00% per annum (based on the prevailing utilization). The alternate base rate is equal to the highest of (i) the prime rate (as published in the Wall Street Journal), (ii) the federal funds rate plus 0.50% per annum, or (iii) the reference Eurodollar rate plus 1.00%.

Bridge Loan borrowings, if any, under the Senior Credit Facility are generally determined by reference to the Eurodollar rate plus an applicable margin of 3.75% per annum or an alternate base rate plus an applicable margin of 2.75% per annum. The alternate base rate is equal to the highest of (i) the prime rate (as published in the Wall Street Journal), (ii) the federal funds rate plus 0.50% per annum, or (iii) the reference Eurodollar rate plus 1.00%.

The Co-Borrowers pay a commitment fee of 0.50% quarterly in arrears on the unused portion of the Senior Credit Facility. In addition, the Co-Borrowers are subject to additional fees including an upfront fee, an annual agency fee, and letter of credit fees based on a percentage of the face amount of letters of credit payable to any syndicate member that issues a letter of credit.

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

•

Minimum Fixed Charge Coverage Ratio. We must maintain a minimum fixed charge coverage ratio of not less than 1.25 to 1.00. The Fixed Charge Coverage Ratio is defined as the ratio of (a) Adjusted EBITDA to (b) the sum of consolidated (with respect to the Company and the Co-Borrowers) interest expense (other than interest paid-in-kind in respect of certain subordinated debt but including interest in respect of that certain promissory note made by CenStar in connection with the permitted acquisition from Verde Energy USA Holdings, LLC, letter of credit fees, commitment fees, acquisition earn-out payments (excluding earnout payments funded with proceeds from newly issued preferred or common equity), distributions, the aggregate amount of repurchases of our Class A common stock, Series A Preferred Stock, or commitments for such purchases, taxes and scheduled amortization payments.


•	Maximum Total Leverage Ratio. We must maintain a ratio of total indebtedness (excluding eligible subordinated debt and letter of credit obligations) to Adjusted EBITDA of no more than 2.50 to 1.00.

•

Maximum Senior Secured Leverage Ratio. We must maintain a Senior Secured Leverage Ratio of no more than 1.85 to 1.00. The Senior Secured Leverage Ratio is defined as the ratio of (a) all indebtedness of the loan parties on a consolidated basis that is secured by a lien on any property of any loan party (including the effective amount of all loans then outstanding (but, in any case, limited to 50% of the effective amount of letter of credit obligations attributable to performance standby letters of credit) but excluding subordinated debt permitted by the Credit Agreement as amended) to (b) Adjusted EBITDA.

The Senior Credit Facility contains various negative covenants that limit our ability to, among other things, incur certain additional indebtedness, grant certain liens, engage in certain asset dispositions, merge or consolidate, make certain payments, distributions, investments, acquisitions or loans, materially modify certain agreements, or enter into transactions with affiliates. The Senior Credit Facility also contains affirmative covenants that are customary for credit facilities of this type. As of December 31, 2018, we are in compliance with our various covenants under the Senior Credit Facility.

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The Senior Credit Facility is secured by pledges of the equity of the portion of Spark HoldCo owned by us, the equity of Spark HoldCo’s subsidiaries, the Co-Borrowers’ present and future subsidiaries, and substantially all of the Co-Borrowers’ and their subsidiaries’ present and future property and assets, including accounts receivable, inventory and liquid investments, and control agreements relating to bank accounts.

We are entitled to pay cash dividends to the holders of the Series A Preferred Stock and Class A common stock and will be entitled to repurchase up to an aggregate amount of 10,000,000 shares of our Class A common stock, and up to $92.7 million of Series A Preferred Stock through one or more normal course open market purchases through NASDAQ so long as: (a) no default exists or would result therefrom; (b) the Co-Borrowers are in pro forma compliance with all financial covenants before and after giving effect thereto; and (c) the outstanding amount of all loans and letters of credit does not exceed the borrowing base limits.

The Senior Credit Facility contains certain customary representations and warranties and events of default. Events of default include, among other things, payment defaults, breaches of representations and warranties, covenant defaults, cross-defaults and cross-acceleration to certain indebtedness, certain events of bankruptcy, certain events under ERISA, material judgments in excess of $5.0 million, certain events with respect to material contracts, actual or asserted failure of any guaranty or security document supporting the Senior Credit Facility to be in full force and effect, failure of Nathan Kroeker to retain his position as President and Chief Executive Officer of the Company, and failure of W. Keith Maxwell III to retain his position as chairman of the board of directors. A default will also occur if at any time W. Keith Maxwell III ceases to, directly or indirectly, own at least 13,600,000 Class A and Class B shares on a combined basis (to be adjusted for any stock split, subdivisions or other stock reclassification or recapitalization), and a controlling percentage of the voting equity interest of the Company, and certain other changes in control. If such an event of default occurs, the lenders under the Senior Credit Facility would be entitled to take various actions, including the acceleration of amounts due under the facility and all actions permitted to be taken by a secured creditor.

On January 28, 2019, the Company and Co-Borrowers exercised the accordion feature in the Senior Credit Facility, bringing total commitments under the Senior Credit Facility to $217.5 million.

Prior to May of 2017, the Company and its then subsidiaries were party to a senior secured revolving credit facility (“Prior Senior Credit Facility”), which included a senior secured revolving working capital facility up to $82.5 million ("Working Capital Line") and a secured revolving line of credit of $25.0 million ("Acquisition Line") to be used specifically for the financing of up to 75% of the cost of acquisitions with the remainder to be financed by the Company either through cash on hand or the issuance of subordinated debt or equity. The outstanding balances under the Working Capital Line and the Acquisition Line were paid in full upon execution of the Company's new Senior Credit Facility in May 2017.

Convertible Subordinated Notes to Affiliate

In connection with the financing of the CenStar and Oasis acquisitions, the Company issued Notes totaling $7.1 million, at an annual interest rate of 5%, payable semiannually. In October 2016, these Notes were converted into 1,035,642 shares of Class B common stock.

Subordinated Debt Facility

The Company maintains a subordinated note in the principal amount of up to $25.0 million with a company owned by our Founder. The subordinated note allows us to draw advances in increments of no less than $1.0 million per advance up to the maximum principal amount of the subordinated note. The subordinated note matures in July 2020, and advances thereunder accrue interest at 5% per annum from the date of the advance. We have the right to capitalize interest payments under the subordinated note. The subordinated note is subordinated in certain respects to our Senior Credit Facility pursuant to a subordination agreement. We may pay interest and prepay principal on the subordinated note so long as we are in compliance with the covenants under our Senior Credit Facility, are not in default under the Senior Credit Facility and have minimum availability of $5.0 million under the borrowing base under the Senior Credit Facility. Payment of principal and interest under the subordinated note is accelerated upon

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the occurrence of certain change of control or sale transactions. As of December 31, 2018, there was $10.0 million outstanding under the subordinated note, which was repaid in January 2019. No amounts were outstanding at December 31, 2017.

Verde Promissory Notes

In connection with the acquisition of the Verde Companies, in July 2017, we entered into a promissory note in the aggregate principal amount of $20.0 million (the "Verde Promissory Note"). The Verde Promissory Note required repayment in 18 monthly installments beginning in August 2017, and accrued interest at 5% per annum from the date of issuance. The Verde Promissory Note, including principal and interest, was unsecured, but is guaranteed by us. In January 2018, in connection with the Earnout Termination Agreement (defined below), we issued to the seller of the Verde Companies an amended and restated promissory note (the “Amended and Restated Verde Promissory Note”), which amended and restated the Verde Promissory Note. The Amended and Restated Verde Promissory Note matures in January 2019, and bears interest at a rate of 9% per annum. Principal and interest are payable monthly on the first day of each month, with a portion of each payment going into an escrow account, which serves as security for certain indemnification claims and obligations under the Verde purchase agreement. As of December 31, 2018 and 2017, there was $1.0 million and $14.6 million outstanding, respectively, under the Amended and Restated Verde Promissory notes.

In January 2018, we issued a promissory note in the principal amount of $5.9 million in connection with an agreement to terminate the earnout obligations arising in connection with our acquisition of the Verde Companies (the “Verde Earnout Termination Note”). The Verde Earnout Termination Note matures on June 30, 2019 (subject to early maturity upon certain events) and bears interest at a rate of 9% per annum. We are permitted to withhold amounts otherwise due at maturity related to certain indemnifiable matters. Interest is payable monthly on the first day of each month.

11. Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. Fair values are based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. This includes the credit standing of counterparties involved and the impact of credit enhancements.

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


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

•

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


•	Level 3—Unobservable inputs for the asset or liability, including situations where there is little, if any, observable market activity for the asset or liability. The Level 3 category includes estimated earnout obligations related to our acquisitions.

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

Other Financial Instruments

The carrying amount of cash and cash equivalents, accounts receivable, accounts payable, and accrued liabilities recorded in the condensed consolidated balance sheets approximate fair value due to the short-term nature of these items. The carrying amounts of the Senior Credit Facility recorded in the condensed consolidated balance sheets approximates fair value because of the variable rate nature of interest on the borrowings thereunder, and are considered Level 2 measurements because interest rates charged are similar to other financial instruments with similar terms and maturities. The fair value of our convertible subordinated notes to affiliates and the payable pursuant to tax receivable agreement—affiliate is not determinable for accounting purposes due to the affiliated nature and terms of the associated agreements with the affiliate.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

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



	Level 1			Level 2			Level 3		Total
December 31, 2018
Non-trading commodity derivative assets	$	104		$	9,821		$	—	$	9,925
Trading commodity derivative assets	44			596			—		640
Total commodity derivative assets	$	148		$	10,417		$	—	$	10,565
Non-trading commodity derivative liabilities	$	(352	)	$	(5,685	)	$	—	$	(6,037	)
Trading commodity derivative liabilities	(75		)	(472		)	—		(547		)
Total commodity derivative liabilities	$	(427	)	$	(6,157	)	$	—	$	(6,584	)
Contingent payment arrangement	$	—		$	—		$	1,328	$	1,328



	Level 1			Level 2			Level 3			Total
December 31, 2017
Non-trading commodity derivative assets	$	158		$	33,886		$	—		$	34,044
Trading commodity derivative assets	—			456			—			456
Total commodity derivative assets	$	158		$	34,342		$	—		$	34,500
Non-trading commodity derivative liabilities	$	(387	)	$	(950	)	$	—		$	(1,337	)
Trading commodity derivative liabilities	(555		)	(237		)	—			(792		)
Total commodity derivative liabilities	$	(942	)	$	(1,187	)	$	—		$	(2,129	)
Contingent payment arrangement	$	—		$	—		$	(4,650	)	$	(4,650	)

We had no transfers of assets or liabilities between any of the above levels during the years ended December 31, 2018, 2017 and 2016.

Our derivative contracts include exchange-traded contracts valued utilizing readily available quoted market prices and non-exchange-traded contracts valued using market price quotations available through brokers or over-the-counter and on-line exchanges. In addition, in determining the fair value of our derivative contracts, we apply a credit risk valuation adjustment to reflect credit risk, which is calculated based on our or the counterparty’s historical credit risks. As of December 31, 2018 and 2017, the credit risk valuation adjustment was not material.

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The contingent payment arrangements referred to above reflect estimated earnout obligations incurred in relation to our acquisition of the Major Energy Companies in 2016.

Contingent Payment Arrangements

The following tables present a roll forward of our contingent payment arrangements, which are measured at fair value on a recurring basis using significant unobservable inputs (Level 3):



	Major Earnout and Stock Earnout			Provider Earnout			Verde Earnout			Total
Fair Value at December 31, 2016	$	17,760		$	4,893		$	—		$	22,653
Purchase price consideration	$	—		$	—		$	5,400		$	5,400
Change in fair value of contingent consideration, net	(9,555		)	500			347			(8,708		)
Accretion of contingent earnout consideration (included within interest expense)	3,848			107			153			4,108
Payments and settlements ⁽¹⁾	(7,403		)	(5,500		)	(5,900		)	(18,803		)
Fair Value at December 31, 2017	$	4,650		$	—		$	—		$	4,650
Change in fair value of contingent consideration, net	$	(1,715	)	$	—		$	—		$	(1,715	)
Payments and settlements	(1,607		)	—			—			(1,607		)
Fair Value at December 31, 2018	$	1,328		$	—		$	—		$	1,328

(1) Payments and settlements include pay downs at maturity and the termination of the Verde Earnout liability, which was replaced with the Verde Earnout Termination Note. See discussion above and in Note 10 "Debt."

The Major Earnout is based on the achievement by the Major Energy Companies of certain performance targets over a 33 month period following the date our affiliate acquired the Major Energy Companies and ended on December 31, 2018. Under the Earnout provisions, the previous members of Major Energy Companies were entitled to a maximum of $20.0 million in earnout payments based on the level of performance targets attained, as defined by the Major Purchase Agreement. The Stock Earnout obligation was contingent upon the Major Energy Companies achieving the Major Earnout's performance target ceiling, thereby earning the maximum Major Earnout payments. If the Major Energy Companies earned such maximum Major Earnout payments, NG&E would be entitled to additional consideration up to a maximum of 400,000 shares of Class B common stock (and a corresponding number of Spark HoldCo units). In determining the fair value of the Major Earnout and the Stock Earnout, we forecasted certain expected performance targets and calculated the probability of such forecast being attained. The impact of the fair value decreases for the years ended December 31, 2018, 2017 and 2016 were recorded in general and administrative expenses.

The Provider Earnout was based on achievement by the Provider Companies of a certain customer count criteria over a nine month period following the closing of the Provider Companies acquisition. The sellers of the Provider Companies were entitled to a maximum of $9.0 million and a minimum of $5.0 million in earnout payments based on the level of customer count attained, as defined by the Provider Companies membership interest purchase agreement. In determining the fair value of the Provider Earnout, the Company forecasted an expected customer count and certain other related criteria and calculated the probability of such forecast being attained.

The Verde Earnout was based on achievement by the Verde Companies of certain performance targets over an 18 month period following the closing of the acquisition of the Verde Companies. In determining the fair value of the Verde Earnout, the Company forecasted certain expected performance targets and calculated the probability of such forecast being attained.

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12. Stock-Based Compensation

Restricted Stock Units

We maintain a Long-Term Incentive Plan ("LTIP") for employees, consultants and directors of the Company and its affiliates who perform services for the Company. The purpose of the LTIP is to provide a means to attract and retain individuals to serve as directors, employees and consultants who provide services to the Company by affording such individuals a means to acquire and maintain ownership of awards, the value of which is tied to the performance of the Company’s Class A common stock. The LTIP provides for grants of cash payments, stock options, stock appreciation rights, restricted stock or units, bonus stock, dividend equivalents, and other stock-based awards with the total number of shares of stock available for issuance under the LTIP not to exceed 2,750,000 shares.

Restricted stock units granted to our officers, employees, non-employee directors and certain employees of our affiliates who perform services for the Company vest over approximately one year for non-employee directors and ratably over approximately one to four years for officers, employees, and employees of affiliates, with the initial vesting date occurring in May of the subsequent year. Each restricted stock unit is entitled to receive a dividend equivalent when dividends are declared and distributed to shareholders of Class A common stock. These dividend equivalents are retained by the Company, reinvested in additional restricted stock units effective as of the record date of such dividends and vested upon the same schedule as the underlying restricted stock unit.

The Company measures the cost of awards classified as equity awards based on the grant date fair value of the award, and the Company measures the cost of awards classified as liability awards at the fair value of the award at each reporting period. The Company has utilized an estimated 6% annual forfeiture rate of restricted stock units in determining the fair value for all awards excluding those issued to executive level recipients and non-employee directors, for which no forfeitures are estimated to occur. The Company has elected to recognize related compensation expense on a straight-line basis over the associated vesting periods.

Although the restricted stock units allow for cash settlement of the awards at the sole discretion of management of the Company, management intends to settle the awards by issuing shares of the Company’s Class A common stock.

Total stock-based compensation expense for the years ended December 31, 2018, 2017 and 2016 was $5.9 million, $5.1 million and $5.2 million. Total income tax benefit related to stock-based compensation recognized in net (loss) income was $0.6 million, $0.8 million and $0.8 million for the years ended December 31, 2018, 2017 and 2016.

Equity Classified Restricted Stock Units

Restricted stock units issued to employees and officers of the Company are classified as equity awards. The fair value of the equity classified restricted stock units is based on the Company’s Class A common stock price as of the grant date. The Company recognized stock based compensation expense of $5.3 million, $2.8 million and $2.3 million for the years ended December 31, 2018, 2017 and 2016, respectively, in general and administrative expense with a corresponding increase to additional paid in capital. The following table summarizes equity classified restricted stock unit activity and unvested restricted stock units for the year ended December 31, 2018:



	Number of Shares (in thousands)		Weighted Average Grant Date Fair Value
Unvested at December 31, 2017	640		$	11.56
Granted	567		9.34
Dividend reinvestment issuances	53		9.11
Vested	(324	)	10.61
Forfeited	(109	)	12.75
Unvested at December 31, 2018	827		$	10.09

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For the year ended December 31, 2018, 323,894 restricted stock units vested, with 213,076 shares of Class A common stock distributed to the holders of these units and 110,818 shares of Class A common stock withheld by the Company to cover taxes owed on the vesting of such units. As of December 31, 2018, there was $6.2 million of total unrecognized compensation cost related to the Company’s equity classified restricted stock units, which is expected to be recognized over a weighted average period of approximately 2.2 years.

Change in Control Restricted Stock Units

In 2018, the Company granted Change in Control Restricted Stock Units ("CIC RSUs") to certain officers that vest upon a "Change in Control", if certain conditions are met. The terms of the CIC RSUs define a "Change in Control" to generally mean:


–	the consummation of an agreement to acquire or tender offer for beneficial ownership by any person, of 50% or more of the combined voting power of our outstanding voting securities entitled to vote generally in the election of directors, or by any person of 90% or more of the then total outstanding shares of Class A common stock;


–	individuals who constitute the incumbent board cease for any reason to constitute at least a majority of the board;


–	consummation of certain reorganizations, mergers or consolidations or a sale or other disposition of all or substantially all of our assets;


–	approval by our stockholders of a complete liquidation or dissolution;


–	a public offering or series of public offerings by Retailco and its affiliates, as a selling shareholder group, in which their total interest drops below 10 million of our total outstanding voting securities;


–	a disposition by Retailco and its affiliates in which their total interest drops below 10 million of our total outstanding voting securities; or


–	any other business combination, liquidation event of Retailco and its affiliates or restructuring of us which the Compensation Committee deems in its discretion to achieve the principles of a Change in Control.

The equity classified restricted stock unit table above excludes unvested CIC RSUs as the conditions for Change in Control have not been met. The Company has not recognized stock compensation expense related to the CIC RSUs as the Change in Control conditions have not been met.

Liability Classified Restricted Stock Units

Restricted stock units issued to non-employee directors of the Company and employees of certain of our affiliates are classified as liability awards as the awards are either to a) non-employee directors that allow for the recipient to choose net settlement for the amount of withholding taxes dues upon vesting or b) to employees of certain affiliates of the Company and are therefore not deemed to be employees of the Company. The fair value of the liability classified restricted stock units is based on the Company’s Class A common stock price as of the reported period ending date. The Company recognized stock based compensation expense of $0.6 million, $2.3 million and $3.0 million for years ended December 31, 2018, 2017 and 2016, respectively, in general and administrative expense with a corresponding increase to liabilities. As of December 31, 2018, the Company’s liabilities related to these restricted stock units recorded in current liabilities was $0.2 million. As of December 31, 2017, the Company's liabilities related to these restricted stock units recorded in current liabilities was $0.7 million. The following table summarizes liability classified restricted stock unit activity and unvested restricted stock units for the year ended December 31, 2018:

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	Number of Shares (in thousands)		Weighted Average Reporting Date Fair Value
Unvested at December 31, 2017	224		$	12.40
Granted	28		7.43
Dividend reinvestment issuances	8		7.43
Vested	(70	)	10.19
Forfeited	(122	)	11.17
Unvested at December 31, 2018	68		$	7.43

For the year ended December 31, 2018, 70,349 restricted stock units vested, with 45,000 shares of Class A common stock distributed to the holders of these units and 25,349 shares of Class A common stock withheld by the Company to cover taxes owed on the vesting of such units. As of December 31, 2018, there was $0.3 million of total unrecognized compensation cost related to the Company’s liability classified restricted stock units, which is expected to be recognized over a weighted average period of approximately 1.6 years.

13. Income Taxes

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

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

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

In December 2017, the President signed the U.S. Tax Reform legislation, which enacted a wide range of changes to the U.S. Corporate income tax system. Accordingly, we adjusted the value of our U.S. deferred tax assets and liabilities based on the rates at which they are expected to be recognized in the future. For U.S. federal purposes the corporate statutory income tax rate was reduced from 35% to 21%, effective for the 2018 tax year. During 2018, we completed our analysis of the impact of U.S. Tax Reform based on further guidance provided on the new tax law by the U.S. Treasury Department and Internal Revenue Service, with no material changes from our assessment performed as of December 31, 2017.

The provision for income taxes included the following components:

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(in thousands)	2018			2017		2016
Current:
Federal	$	3,862		$	6,992	$	5,361
State	1,099			1,952		1,683
Total Current	4,961			8,944		7,044

Deferred:
Federal	(2,792		)	27,820		2,944
State	(92		)	2,001		438
Total Deferred	(2,884		)	29,821		3,382
Provision for income taxes	$	2,077		$	38,765	$	10,426

The effective income tax rate was (17)% and 34% for the years ended December 31, 2018 and 2017, respectively. The following table reconciles the income tax benefit that would result from application of the statutory federal tax rate, 21% and 35% for the years ended December 31, 2018 and 2017, respectively, to the amount included in the consolidated statement of operations:



(in thousands)	2018			2017
Expected provision at federal statutory rate	$	(2,586	)	$	39,833
Increase (decrease) resulting from:
Non-controlling interest	1,738			(19,810		)
Class A Preferred Stock dividends	1,579			1,758
Impact of U.S. Tax Reform	—			14,454
Intra-entity transfer of customer contracts	473			—
State income taxes, net of federal income tax effect	428			2,569
Non-deductible expenses	256			234
Other	189			(273		)
Provision for income taxes	$	2,077		$	38,765

Total income tax expense for the years ended December 31, 2018 and 2017 differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income primarily due to state income taxes and the impact of permanent differences between book and taxable income, most notably the income attributable to non-controlling interest, which gets taxed at the non-controlling interest partner level. The effective rate in 2017 was also impacted by the enactment of U.S. Tax Reform. Since we were in a net deferred tax asset position, the rate reduced our overall asset having an unfavorable effect on tax expense.

The components of our deferred tax assets as of December 31, 2018 and 2017 are as follows:

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(in thousands)	2018			2017
Deferred Tax Assets:
Investment in Spark HoldCo	$	22,251		$	16,132
Benefit of TRA Liability	7,016			8,175
Federal net operating loss carryforward	—			660
State net operating loss carryforward	—			166
Other	78			—
Total deferred tax assets	29,345			25,133

Deferred Tax Liabilities:
Derivative liabilities	(715		)	(811		)
Intangibles	(849		)	(2,287		)
Property and equipment	(460		)	—
Other	—			(58		)
Total deferred tax liabilities	(2,024		)	(3,156		)
Total deferred tax assets/liabilities	$	27,321		$	21,977

The benefit of the TRA Liability relates to the step up in tax basis resulting from the purchase by the Company of Spark HoldCo units from our Founder at the time of our IPO. Subsequent issuances of Series A common stock, exchanges of Series A Common Stock for Series B Shares and vesting of incentive stock compensation since our IPO has also resulted in step ups in the basis of our stock similarly resulting in a liability under our Tax Receivable Agreement. As of December 31, 2018 and 2017, we have a current liability of $1.7 million and $5.9 million and a long-term liability of $25.9 million and $26.4 million to record the overall effect of the Tax Receivable Agreement. See Note 15 "Transactions with Affiliates" for further discussion.

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

The tax years 2013 through 2017 remain open to examination by the major taxing jurisdictions to which the Company is subject to income tax. An affiliate owned by our Founder would be responsible for any audit adjustments incurred in connection with transactions occurring prior to July 2014 for Spark Energy, Inc. and Spark HoldCo.

Accounting for uncertainty in income taxes prescribes a recognition threshold and measurement methodology for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. As of December 31, 2018 and 2017 there was no liability, and for the years ended December 31, 2018, 2017 and 2016, there was no expense recorded for interest and penalties associated with uncertain tax positions or unrecognized tax positions. Additionally, the Company does not have unrecognized tax benefits as of December 31, 2018 and 2017.

14. Commitment and Contingencies

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

Legal Proceedings

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

Katherine Veilleux, et. al. v. Electricity Maine LLC, Provider Power, LLC, Spark HoldCo, LLC, Kevin Dean, and Emile Clavet is a purported class action lawsuit filed on November 18, 2016 in the United States District Court of Maine, alleging that Electricity Maine, LLC (Electricity Maine), an entity acquired by Spark Holdco, LLC (Spark Holdco) in mid-2016, enrolled and re-enrolled customers through fraudulent and misleading advertising, promotions, and other communications prior to and following the acquisition. Plaintiffs allege claims under RICO, the Maine Unfair Trade Practice Act, civil conspiracy, fraudulent misrepresentation, unjust enrichment and breach of contract. Plaintiffs seek damages for themselves and the purported class, rescission of contracts with Electricity Maine, injunctive relief, restitution, and attorney’s fees. Discovery is ongoing in this matter. Spark HoldCo and Electricity Maine intend to vigorously defend this matter and the allegations asserted therein, including the request to certify a class. Electricity Maine and Spark HoldCo intend to file a motion to compel arbitration of certain Plaintiffs’ claims as the applicable Terms of Service in this case contain an arbitration provision and class action waiver. The Company believes it has full indemnity coverage for any actual exposure in this case at this time.

Gillis et al. v. Respond Power, LLC is a purported class action lawsuit that was originally filed on May 21, 2014 in the Philadelphia Court of Common Pleas but was later removed to the United States District Court for the Eastern District of Pennsylvania. On September 15, 2014, the plaintiffs filed an amended class action complaint seeking a declaratory judgment that the disclosure statement contained in Respond Power, LLC’s variable rate contracts with Pennsylvania consumers limited the variable rate that could be charged to no more than the monthly rate charged by the consumers’ local utility company and alleged claims of deceptive conduct in violation of Pennsylvania Unfair Trade Practices and Consumer Protection Act, negligent misrepresentation, fraudulent concealment, and breach of contract and of the covenant of good faith and fair dealing by charging rates above the utility. The amount of damages sought is not specified. By order dated August 31, 2015, the district court denied class certification. The plaintiffs appealed the district court’s denial of class certification to the United States Court of Appeals for the Third Circuit and that court vacated the district court’s denial of class certification and remanded the matter to the district court for further proceedings. On July 16, 2018, the district court granted Respond Power LLC's motion to dismiss the Plaintiff’s class action claims. Plaintiffs filed their notice of appeal to the Third Circuit Court on August 7, 2018. The Third Circuit has not yet ruled or set any hearings on this appeal. The Company believes it has full indemnity coverage for any actual exposure in this case at this time.

Jurich v. Verde Energy USA, Inc., is a class action originally filed on March 3, 2015 in the United States District Court for the District of Connecticut and subsequently re-filed on October 8, 2015 in the Superior Court of Judicial District of Hartford, State of Connecticut. The Amended Complaint asserts that the Verde Companies charged rates in violation of its contracts with Connecticut customers and alleges (i) violation of the Connecticut Unfair Trade Practices Act, Conn. Gen. Stat. §§ 42-110a et seq., and (ii) breach of the covenant of good faith and fair dealing. Plaintiffs are seeking unspecified actual and punitive damages for the class and injunctive relief. The parties have exchanged initial discovery. On December 6, 2017, the Court granted the plaintiffs’ class certification motion. As part of an agreement in connection with the acquisition of the Verde Companies, the original owners of the Verde Companies are handling this matter. The Company believes it has full indemnity coverage for any actual exposure in this case at this time.

Richardson et. al. v. Verde Energy USA, Inc. is a purported class action filed on November 25, 2015 in the United States District Court for the Eastern District of Pennsylvania alleging that the Verde Companies violated the Telephone Consumer Protection Act (TCPA) by placing marketing calls using an automatic telephone dialing system (ATDS) or a prerecorded voice to the purported class members’ cellular phones without prior express consent and by continuing to make such calls after receiving requests for the calls to cease. Plaintiffs are seeking

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statutory damages for the purported class and injunctive relief prohibiting Verde Companies' alleged conduct. Discovery closed and dispositive motions on the named plaintiffs’ claims were filed on November 24, 2017. The Verde Companies received a favorable ruling on summary judgment with the court agreeing with the Verde Companies that the call system used in this case was not an ATDS as defined by the TCPA. As part of an agreement in connection with the acquisition of the Verde Companies, the original owners of the Verde Companies are handling this matter. The Company believes it has full indemnity coverage for any actual exposure in this case at this time.

Saul Horowitz, as Sellers’ Representative for the former owners of the Major Energy Companies v. National Gas & Electric, LLC (NG&E) and Spark Energy, Inc., filed a lawsuit on October 17, 2017 in the United States District Court for the Southern District of New York asserting claims of fraudulent inducement against NG&E, breach of contract against NG&E and us, and tortious interference with contract against us related to the membership interest purchase, subsequent transfer, and associated earnout agreements with the Major Energy Companies' former owners. The relief sought includes unspecified compensatory and punitive damages, prejudgment and post judgment interest, and attorneys’ fees. On September 24, 2018, the court granted our motion to dismiss in part and dismissed the plaintiffs’ fraudulent inducement claims but allowed the tortious interference claims to remain as well as the claims for consequential damages and punitive damages. NG&E and the Company filed their affirmative defenses and answer to the remaining claims on October 15, 2018. Discovery has commenced and written discovery requests have been exchanged between the parties. This case is currently set for trial on September 9, 2019. The Company and NG&E deny the allegations asserted and intend to vigorously defend this matter. Given the early stages of this matter, we cannot predict the outcome or consequences of this case at this time.

Regulatory Matters

On April 9, 2018 the Attorney General for the State of Illinois filed a complaint against Major Energy Electric Services, LLC (Major) asserting claims that Major engaged in a pattern and practice of deceptive conduct intended to defraud Illinois consumers through door-to-door and telephone solicitations, in-person solicitations at retail establishments, advertisements on its website and direct mail advertisements to sign up for electricity services. The complaint seeks injunctive relief and monetary damages representing the amounts Illinois consumers have allegedly lost due to fraudulent marketing activities. The Attorney General also requests civil penalties under the Consumer Fraud Act and to revoke Major’s authority to operate in the state. The complaint was filed in the Circuit Court of Cook County, Illinois, County Department, Chancery Division. Major filed its motion to dismiss on August 1, 2018. On October 10, 2018, the court denied Major’s Motion to Dismiss and subsequently its motion for reconsideration. Major is appealing the lower court’s ruling with a Motion for Entry of a Certified Question. Appellate briefs are due in February 2019 and discovery has begun. Major denies the allegations asserted and intends to vigorously defend this matter, however, we cannot predict the outcome or consequences of this case at this time.

Spark Energy, LLC (Spark) is the subject of two current investigations by the Connecticut Public Utilities Regulatory Authority (PURA). The first investigation constitutes a notice of violation (NOV) and assessment of a proposed civil penalty in the amount of $0.9 million primarily for Spark's alleged failure to comply with requirements implemented in 2016 that customer bills include any changes to existing rates effective for the next billing cycle. After a hearing process was concluded and Spark Energy, LLC filed a brief challenging the legal authority of PURA to enforce the NOV and impose civil penalties for the alleged violations, PURA suspended the proceeding and opened a proceeding offering amnesty to ESCOs that self-report violations and offer to voluntarily remit refunds to customers. Spark has announced its intention to participate in the amnesty proceeding. The second investigation involves a NOV alleging improper marketing practices of one of Spark Energy, LLC's former outbound telemarketing vendors and assessment of a proposed civil penalty of $0.8 million. Certain agents managed by this vendor were allegedly using an unauthorized script in outbound marketing calls. We are unable to predict the outcome of these proceedings but have accrued $0.2 million as of December 31, 2018, which represents our current estimate for penalty exposure for these two matters. While investigations of this nature have become common and are often resolved in a manner that allows the retailer to continue operating in Connecticut, there can be no assurance that PURA will not take more severe action.

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Indirect Tax Audits

We are undergoing various types of indirect tax audits spanning from years 2013 to 2018 for which we may have additional liabilities arise. At the time of filing these consolidated financial statements, these indirect tax audits are at an early stage and subject to substantial uncertainties concerning the outcome of audit findings and corresponding responses.

As of December 31, 2018, we have accrued $0.9 million related to litigation and regulatory matters and $0.6 million related to indirect tax audits. The outcome of each of these may result in additional expense.

15. Transactions with Affiliates

Transactions with Affiliates

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

Master Service Agreement with Retailco Services, LLC

Prior to April 1, 2018, we were a party to a Master Service Agreement with an affiliated company owned by our Founder. The Master Service Agreement provided us with operational support services such as: enrollment and renewal transaction services; customer billing and transaction services; electronic payment processing services; customer service and information technology infrastructure and application support services under the Master Service Agreement. Effective April 1, 2018, we terminated the agreement, and these operational support services were transferred back to us. See "Cost Allocations" below for further discussion of the fees paid to affiliates during the years ended December 31, 2018, 2017, and 2016 respectively.

Cost Allocations

Where costs incurred on behalf of the affiliate or us cannot be determined by specific identification for direct billing, the costs are allocated to the affiliated entities or us based on estimates of percentage of departmental usage, wages or headcount. The total net amount direct billed and allocated from affiliates was $10.3 million, $25.4 million and $17.0 million for the years ended December 31, 2018, 2017 and 2016, respectively.

Of the amounts directly billed and allocated from affiliates, we recorded general and administrative expense of $5.9 million, $22.0 million, and $14.7 million for the years ended December 31, 2018, 2017 and 2016, respectively, in the consolidated statement of operations in connection with fees paid under the Master Service Agreement. Additionally under the Master Service Agreement, we capitalized $0.5 million, 0.7 million, and $1.3 million of

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property and equipment for the application, development and implementation of various systems during the years ended December 31, 2018, 2017 and 2016, respectively.

Accounts Receivable and Payable—Affiliates

As of December 31, 2018 and 2017, we had current accounts receivable—affiliates of $2.6 million and $3.7 million, respectively, and current accounts payable—affiliates of $2.5 million and $4.6 million, respectively.

Revenues and Cost of Revenues—Affiliates

Revenues recorded in net asset optimization revenues in the consolidated statements of operations for the years ended December 31, 2018, 2017 and 2016 related to affiliated sales were $2.4 million, $1.3 million, and $0.2 million, respectively, and cost of revenues recorded in net asset optimization revenues in the consolidated statements of operations for the years ended December 31, 2018, 2017 and 2016 related to this agreement were $0.1 million, $0.1 million and $1.6 million, respectively. These amounts are presented as net on the Consolidated Statements of Operations.

Acquisitions from Affiliates

In 2017, we acquired Perigee from our affiliate, NG&E, for total consideration of approximately $4.1 million.

In connection with the Major Energy Companies acquisition, we issued 4,000,000 shares of Class B common stock (and a corresponding number of Spark HoldCo units) to NG&E, valued at $40.0 million. In connection with the financing of the Provider Companies acquisition, we issued 1,399,484 shares of Class B common stock (and a corresponding number of Spark HoldCo units) to RetailCo, valued at $14.0 million.

In March 2018, we entered into an asset purchase agreement with NG&E to acquire up to 50,000 RCEs from NG&E for a cash purchase price of $250 for each RCE, or up to $12.5 million in the aggregate. A total of $8.8 million was paid in 2018 under the terms of the purchase agreement for approximately 35,000 RCEs, and no further material payments are anticipated. The acquisition was treated as a transfer of assets between entities under common control, and accordingly, the assets were recorded at their historical value at the date of transfer. The transaction resulted in $7.1 million recorded in equity as a net distribution to affiliate as of December 31, 2018.

Distributions to and Contributions from Affiliates

During the years ended December 31, 2018, 2017 and 2016, we made distributions to affiliates of our Founder of $15.5 million, $15.6 million and $23.7 million, respectively, for payments of quarterly distributions on their respective Spark HoldCo units. During the years ended December 31, 2018, 2017 and 2016, we also made distributions to these affiliates for gross-up distributions of $16.5 million, $18.2 million, and $11.3 million, respectively, in connection with distributions made between Spark HoldCo and Spark Energy, Inc. for payment of income taxes incurred by us.

Proceeds from Disgorgement of Stockholder Short-swing Profits

During the years ended December 31, 2018, 2017 and 2016, we recorded zero, $0.7 million, and $1.6 million, respectively, for the disgorgement of stockholder short-swing profits under Section 16(b) under the Exchange Act. The amount was recorded as an increase to additional paid-in capital in our consolidated balance sheet as of December 31, 2018, 2017 and 2016. We received $0.5 million cash during the year ended December 31, 2017 and received $0.2 million cash in February 2018. In addition, the Company received $0.7 million cash during the year ended December 31, 2017 related to the disgorgement of stockholder short-swing profit recorded in our consolidated balance sheet as of December 31, 2016.

Subordinated Debt Facility

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On December 27, 2016, we and Spark HoldCo jointly issued to an affiliate owned by our Founder, a 5% subordinated note in the principal amount of up to $25.0 million. The subordinated note allows us to draw advances in increments of no less than $1.0 million per advance up to the maximum principal amount of the subordinated note. Advances thereunder accrue interest at 5% per annum from the date of the advance. As of December 31, 2018 and 2017, there was $10.0 million and zero, respectively, outstanding under the subordinated note. See Note 10 "Debt" for a further description of terms and conditions of the facility.

Tax Receivable Agreement

We maintain a Tax Receivable Agreement with affiliates that generally provides for the payment by us to affiliates of 85% of the net cash savings, if any, in U.S. federal, state and local income tax or franchise tax that we realize or will realize (or are deemed to realize in certain circumstances) in future periods as a result of (i) any tax basis increases resulting from the initial purchase by us of Spark HoldCo units from entities owned by our Founder, (ii) any tax basis increases resulting from the exchange of Spark HoldCo units for shares of Class A common stock pursuant to the Exchange Right (or resulting from an exchange of Spark HoldCo units for cash pursuant to the Cash Option) and (iii) any imputed interest deemed to be paid by us as a result of, and additional tax basis arising from, any payments we make under the Tax Receivable Agreement. We retain the benefit of the remaining 15% of these tax savings. See Note 13 "Income Taxes" for further discussion.

In certain circumstances, we may defer or partially defer any payment due (a “TRA Payment”) to the holders of rights under the Tax Receivable Agreement for a five-year period that ends September 30, 2019. Deferral of payment is required to the extent that Spark HoldCo does not generate sufficient Cash Available for Distribution (as defined below) during the four-quarter period ending September 30th of the applicable year in which the TRA Payment is to be made in an amount that equals or exceeds 130% (the “TRA Coverage Ratio”) of the Total Distributions (as defined below) paid in such four-quarter period by Spark HoldCo. For purposes of computing the TRA Coverage Ratio:


•	“Cash Available for Distribution” is generally defined as the Adjusted EBITDA of Spark HoldCo for the applicable period, less (i) cash interest paid by Spark HoldCo, (ii) capital expenditures of Spark HoldCo (exclusive of customer acquisition costs) and (iii) any taxes payable by Spark HoldCo; and

•

“Total Distributions” are defined as the aggregate distributions necessary to cause us to receive distributions of cash equal to (i) the targeted quarterly distribution we intend to pay to holders of our Class A common and Series A Preferred Stock payable during the applicable four-quarter period, plus (ii) the estimated taxes payable by us during such four-quarter period, plus (iii) the expected TRA Payment payable during the calendar year for which the TRA Coverage Ratio is being tested.

At the end of the deferral period, we are obligated to pay any outstanding deferred TRA Payments to the extent such deferred TRA Payments do not exceed (i) the lesser of our proportionate share of aggregate Cash Available for Distribution of Spark HoldCo during the five-year deferral period or the cash distributions actually received by us during the five-year deferral period, reduced by (ii) the sum of (a) the aggregate target quarterly dividends (which, for the purposes of the Tax Receivable Agreement, will be $0.18125 per Class A common stock share and $0.546875 per Series A Preferred Stock share per quarter) during the five-year deferral period, (b) our estimated taxes during the five-year deferral period, (c) all prior TRA Payments and (d) if with respect to the quarterly period during which the deferred TRA Payment is otherwise paid or payable, Spark HoldCo has or reasonably determines it will have amounts necessary to cause us to receive distributions of cash equal to the target quarterly distribution payable during that quarterly period. Any portion of the deferred TRA Payments not payable due to these limitations will no longer be payable.

For the four-quarter periods ending September 30, 2016, 2017, and 2018, we met the threshold coverage ratio required to fund the payments required under the Tax Receivable Agreement. Our affiliates, however, granted us the right to defer the TRA payment related to the four-quarter period ending September 30, 2016 until May 2018. In April, May, and December of 2018, we paid a total of $6.2 million related to our obligations under the TRA for the 2015, 2016, and 2017 tax years.

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As of December 31, 2018 and 2017, we had a total liability related to the TRA of $27.6 million and $32.3 million, of which $1.7 million and $5.9 million, respectively, were classified as current liabilities.

16. Segment Reporting

Our determination of reportable business segments considers the strategic operating units under which we make financial decisions, allocate resources and assess performance of our business. Our reportable business segments are retail electricity and retail natural gas. The retail electricity segment consists of electricity sales and transmission to residential and commercial customers. The retail natural gas segment consists of natural gas sales to, and natural gas transportation and distribution for, residential and commercial customers. Corporate and other consists of expenses and assets of the retail natural gas and retail electricity segments that are managed at a consolidated level such as general and administrative expenses. Asset optimization activities are also included in Corporate and other. For the years ended December 31, 2018, 2017 and 2016, we recorded asset optimization revenues of $113.7 million, $178.3 million and $133.0 million and asset optimization cost of revenues of $109.2 million, $179.0 million and $133.6 million, respectively, which are presented on a net basis in asset optimization revenues.

We use retail gross margin to assess the performance of our operating segments. Retail gross margin is defined as operating income (loss) plus (i) depreciation and amortization expenses and (ii) general and administrative expenses, less (i) net asset optimization revenues (expenses), (ii) net gains (losses) on non-trading derivative instruments, and (iii) net current period cash settlements on non-trading derivative instruments. We deduct net gains (losses) on non-trading derivative instruments, excluding current period cash settlements, from the retail gross margin calculation in order to remove the non-cash impact of net gains and losses on these derivative instruments. Retail gross margin should not be considered an alternative to, or more meaningful than, operating income, as determined in accordance with GAAP.

Below is a reconciliation of retail gross margin to (loss) income before income tax expense (in thousands):



	Years Ended December 31,
(in thousands)	2018			2017			2016
Reconciliation of Retail Gross Margin to Income before taxes
(Loss) income before income tax expense	$	(12,315	)	$	113,809		$	76,099
Change in Tax Receivable Agreement Liability	—			(22,267		)	—
Interest and other income	(749		)	(256		)	(957		)
Interest expense	9,410			11,134			8,859
Operating (loss) income	(3,654		)	102,420			84,001
Depreciation and amortization	52,658			42,341			32,788
General and administrative	111,431			101,127			84,964
Less:
Net asset optimization revenue (expenses)	4,511			(717		)	(586		)
Net, (losses) gain on non-trading derivative instruments	(19,571		)	5,588			22,254
Net, Cash settlements on non-trading derivative instruments	(9,614		)	16,508			(2,284		)
Retail Gross Margin	$	185,109		$	224,509		$	182,369

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

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Year Ended December 31,
2018	Retail Electricity			Retail Natural Gas			Corporate and Other		Eliminations			Consolidated
Total Revenues	$	863,451		$	137,966		$	4,511	$	—		$	1,005,928
Retail cost of revenues	762,771			82,722			—		—			845,493
Less:
Net asset optimization revenue	—			—			4,511		—			4,511
Net, Losses on non-trading derivative instruments	(15,200		)	(4,371		)	—		—			(19,571		)
Current period settlements on non-trading derivatives	(8,788		)	(826		)	—		—			(9,614		)
Retail gross margin	$	124,668		$	60,441		$	—	$	—		$	185,109
Total Assets	$	1,857,790		$	649,969		$	361,697	$	(2,380,718	)	$	488,738
Goodwill	$	117,813		$	2,530							$	120,343



Year Ended December 31,
2017	Retail Electricity		Retail Natural Gas			Corporate and Other			Eliminations			Consolidated
Total Revenues ⁽¹⁾	$	657,566	$	141,206		$	(717	)	$	—		$	798,055
Retail cost of revenues	477,012		75,155			—			—			552,167
Less:
Net asset optimization expense ⁽¹⁾	—		—			(717		)	—			(717		)
Net, Gains (losses) on non-trading derivative instruments	5,784		(196		)	—			—			5,588
Current period settlements on non-trading derivatives	16,302		206			—			—			16,508
Retail gross margin	$	158,468	$	66,041		$	—		$	—		$	224,509
Total Assets ⁽²⁾	$	1,218,243	$	421,896		$	281,176		$	(1,417,574	)	$	503,741
Goodwill	$	117,624	$	2,530		$	—		$	—		$	120,154



Year Ended December 31,
2016	Retail Electricity			Retail Natural Gas		Corporate and Other			Eliminations			Consolidated
Total Revenues ⁽¹⁾	$	417,229		$	130,054	$	(586	)	$	—		$	546,697
Retail cost of revenues	286,795			58,149		—			—			344,944
Less:
Net asset optimization expense ⁽¹⁾	—			—		(586		)	—			(586		)
Net, Gains on non-trading derivative instruments	17,187			5,067		—			—			22,254
Current period settlements on non-trading derivatives	(4,889		)	2,605		—			—			(2,284		)
Retail gross margin	$	118,136		$	64,233	$	—		$	—		$	182,369
Total Assets ⁽²⁾	$	551,338		$	242,739	$	192,101		$	(618,429	)	$	367,749
Goodwill	$	76,617		$	2,530	$	—		$	—		$	79,147

(1) Previously reported amounts have been adjusted to reclassify net asset optimization actives from the Retail Natural Gas segment to Corporate and Other.

(2) Previously reported amounts have been adjusted for immaterial corrections. See Footnote 2 "Basis of Presentation and Summary of Significant Accounting Policies" for further discussion.

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Significant Customers

For each of the years ended December 31, 2018, 2017 and 2016, we did not have any significant customers that individually accounted for more than 10% of our consolidated retail revenue.

Significant Suppliers

For each of the years ended December 31, 2018, 2017 and 2016, we had two significant suppliers that individually accounted for more than 10% of our consolidated retail cost of revenues and net asset optimization revenues. For each of the years ended December 31, 2018, 2017 and 2016, these suppliers accounted for 28%, 20% and 27% of our consolidated cost of revenue and net asset optimization revenue.

17. Equity Method Investment

Investment in eREX Spark Marketing Co., Ltd

In September 2015, we, together with eREX Co., Ltd., a Japanese company, entered into an agreement ("eREX JV Agreement") to form a new joint venture, eREX Spark Marketing Co., Ltd ("eREX Spark"). As part of this agreement, we made contributions of 156.4 million Japanese Yen, or $1.4 million, for a 20% ownership interest in eREX Spark. We are entitled to share in 30% of the dividends distributed by eREX Spark for the first year a qualifying dividend is paid and for the subsequent four years thereafter. After this period, dividends will be distributed proportionately with the equity ownership of eREX Spark. eREX Spark's board of directors consists of four directors, one of whom is appointed by us.

Based on our significant influence, as reflected by the 20% equity ownership and 25% control of the eREX Spark board of directors, we recorded the investment in eREX Spark as an equity method investment. Our investment in eREX Spark was $3.1 million as of December 31, 2018, reflecting contributions made by us through December 31, 2018 and our proportionate share of earnings as determined under the HLBV method as of December 31, 2018, and recorded in other assets in the consolidated balance sheet. There were no basis differences between our initial contribution and the underlying net assets of eREX Spark. We recorded our proportionate share of eREX Spark's earnings of $0.5 million in our consolidated statement of operations for the year ended December 31, 2018.

Supplemental Quarterly Financial Data (unaudited)

Summarized unaudited quarterly financial data is as follows:

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	Quarter Ended
	2018
	December 31, 2018			September 30, 2018		June 30, 2018		March 31, 2018
	(In thousands, except per share data)
Total Revenues	$	228,514		$	258,475	$	232,251	$	286,688
Operating (loss) income	(11,795		)	25,454		28,941		(46,254		)
Net (loss) income	(15,315		)	18,827		23,927		(41,831		)

Net (loss) income attributable to Spark Energy, Inc. stockholders (As reported)	—			5,609		7,500		(12,326		)
Adjustments	—			1,158		1,285		1,221
Net (loss) income attributable to Spark Energy, Inc. stockholders (As adjusted)	(5,633		)	6,767		8,785		(11,105		)

Net (loss) income attributable to stockholders of Class A common stock (As reported)	—			3,582		5,473		(14,353		)
Adjustments	$	—		1,158		1,284		1,221
Net (loss) income attributable to stockholders of Class A common stock (As adjusted)	(7,660		)	4,740		6,757		(13,132		)

Net (loss) income attributable to Spark Energy, Inc. per common share—basic (As reported)	$	—		$	0.27	$	0.41	$	(1.09	)
Adjustments	$	—		$	0.08	$	0.10	$	0.09
Net (loss) income attributable to Spark Energy, Inc. per common share—basic (As adjusted)	$	0.56		$	0.35	$	0.51	$	(1.00	)

Net (loss) income attributable to Spark Energy, Inc. per common share—diluted (As reported)	$	—		$	0.27	$	0.41	$	(1.09	)
Adjustments	$	—		$	0.08	$	0.10	$	0.05
Net (loss) income attributable to Spark Energy, Inc. per common share—diluted (As adjusted)	$	0.58		$	0.35	$	0.51	$	(1.04	)

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	Quarter Ended
	2017
	December 31, 2017			September 30, 2017		June 30, 2017		March 31, 2017
	(In thousands, except per share data)
Total Revenues	$	234,776		$	215,536	$	151,436	$	196,307
Operating income	59,752			18,088		7,797		16,783

Net income	47,536			12,942		4,671		11,132
Adjustments	(1,237		)	—		—		—
Net income (As adjusted)	46,299			12,942		4,671		11,132

Net income attributable to Spark Energy, Inc. stockholders	13,158			2,347		1,079		2,270
Adjustments	(698		)	533		501		55
Net income attributable to Spark Energy, Inc. stockholders (As adjusted)	12,460			2,880		1,580		2,325

Net income attributable to stockholders of Class A common stock	12,226			1,415		88		2,087
Adjustments	(698		)	533		501		55
Net income attributable to stockholders of Class A common stock (As adjusted)	11,528			1,948		589		2,142

Net income attributable to Spark Energy, Inc. per common share—basic	$	0.92		$	0.11	$	0.01	$	0.16
Adjustments	$	(0.05	)	$	0.04	$	0.07	$	—
Net income attributable to Spark Energy, Inc. per common share—basic (As adjusted)	$	0.87		$	0.15	$	0.08	$	0.16

Net income attributable to Spark Energy, Inc. per common share—diluted	$	0.92		$	0.11	$	0.01	$	0.16
Adjustments	$	(0.05	)	$	0.04	$	0.06	$	—
Net income attributable to Spark Energy, Inc. per common share—diluted (As adjusted)	$	0.87		$	0.15	$	0.07	$	0.16

Previously reported amounts have been adjusted for immaterial corrections. See Footnote 2 "Basis of Presentation and Summary of Significant Accounting Policies" for further discussion.

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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our Chief Executive Officer and our Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Annual Report on Form 10-K. The term “disclosure controls and procedures,” as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the company’s management, including its principal executive and principal financial officers or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving their objectives, and management necessarily applies its judgment in evaluating the cost benefit relationship of possible controls and procedures. Based on this evaluation, management concluded that our disclosure controls and procedures were effective as of December 31, 2018 at the reasonable assurance level.

Management's Annual Report on Internal Control Over Financial Reporting

See "Management's Report on Internal Control Over Financial Reporting" under Item 8 of this Annual Report on Form 10-K.

Attestation Report of the Independent Registered Public Accounting Firm

This Annual Report on Form 10-K does not include an attestation report of our independent registered public accounting firm on our internal control over financial reporting because Section 103 of the JOBS Act provides that an emerging growth company is not required to provide an auditor's report on internal control over financial reporting for as long as we qualify as an emerging growth company.

Changes in Internal Control over Financial Reporting

There was no change in our internal control over financial reporting identified in connection with the evaluation required by Rule 13a-15(d) and 15d-15(d) of the Exchange Act that occurred during the three months ended December 31, 2018 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting, expect as described below.

Item 9B. Other Information

None.

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PART III.

Item 10. Directors, Executive Officers and Corporate Governance

Information as to Item 10 will be set forth in the Proxy Statement for the 2019 Annual Meeting of Shareholders (the “Annual Meeting”) and is incorporated herein by reference.

Item 11. Executive Compensation

Information as to Item 11 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management, and Related Stockholder Matters

Except as provided below, information as to Item 12 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.

Equity Compensation Plan Information

The following table shows information about our Class A common stock that may be issued under the Spark Energy, Inc. Amended and Restated Incentive Plan (the “Incentive Plan”) as of December 31, 2018.



Plan category	(a) Number of securities to be issued upon exercise of outstanding options, warrants and rights (1)	(c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)(2))
Equity compensation plans approved by the security holders	1,087,788	603,513
Equity compensation plans not approved by the security holders	—	—
Total	1,087,788	603,513

(1) This column reflects the maximum number of shares of Class A common stock that may be issued under outstanding and unvested restricted stock units ("RSUs") at December 31, 2018. No stock options or warrants have been granted under the Incentive Plan.

(2) This column reflects the total number of shares of Class A common stock remaining available for issuance under the LTIP.

The Incentive Plan is the only plan under which our equity securities are authorized for issuance. The Incentive Plan was approved by our shareholder prior to our initial public offering but as of December 31, 2018 had not been approved by our public shareholders. Please read Note 12 to our consolidated financial statements, entitled “Stock-Based Compensation,” for a description of the Incentive Plan.

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Item 13. Certain Relationships and Related Transactions, and Director Independence

Information as to Item 13 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.

Item 14. Principal Accounting Fees and Services

Information as to Item 14 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.

PART IV.

Item 15. Exhibits, Financial Statement Schedules

(1) The consolidated financial statements of Spark Energy, Inc. and its subsidiaries and the report of the independent registered public accounting firm are included in Part II, Item 8 of this Annual Report.

(2) All schedules have been omitted because they are not required under the related instructions, are not applicable or the information is presented in the consolidated financial statements or related notes.

(3) The exhibits listed on the accompanying Exhibit Index are filed as part of, or incorporated by reference into, this Annual Report.

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Item 16. Form 10-K Summary

None.



INDEX TO EXHIBITS
		Incorporated by Reference
Exhibit	Exhibit Description	Form	Exhibit Number		Filing Date	SEC File No.
2.1#	Membership Interest Purchase Agreement, by and among Spark Energy, Inc., Spark HoldCo, LLC, Provider Power, LLC, Kevin B. Dean and Emile L. Clavet, dated as of May 3, 2016.	10-Q		2.1	5/5/2016	001-36559
2.2#	Membership Interest Purchase Agreement, by and among Spark Energy, Inc., Spark HoldCo, LLC, Retailco, LLC and National Gas & Electric, LLC, dated as of May 3, 2016.	10-Q		2.2	5/5/2016	001-36559
2.3#	Amendment No. 1 to the Membership Interest Purchase Agreement, dated as of July 26, 2016, by and among Spark Energy, Inc., Spark HoldCo, LLC, Provider Power, LLC, Kevin B. Dean and Emile L. Clavet.	8-K		2.1	8/1/2016	001-36559
2.4#	Membership Interest and Stock Purchase Agreement, by and among Spark Energy, Inc., CenStar Energy Corp. and Verde Energy USA Holdings, LLC, dated as of May 5, 2017.	10-Q		2.4	5/8/2017	001-36559
2.5	First Amendment to the Membership Interest and Stock Purchase Agreement, dated July 1, 2017, by and among Spark Energy, Inc., CenStar Energy Corp., and Verde Energy USA Holdings, LLC.	8-K		2.1	7/6/2017	001-36559
2.6#	Agreement to Terminate Earnout Payments, effective January 12, 2018, by and among Spark Energy, Inc., CenStar Energy Corp., Woden Holdings, LLC (fka Verde Energy USA Holdings, LLC), Verde Energy USA, Inc., Thomas FitzGerald, and Anthony Mench.	8-K		2.1	1/16/2018	001-36559
2.7#	Asset Purchase Agreement, dated March 7, 2018, by and between Spark HoldCo, LLC and National Gas & Electric, LLC	10-K		2.7	3/9/2018	001-36559
2.8#	Asset Purchase Agreement by and between Spark HoldCo, LLC and Starion Energy Inc., Starion Energy NY Inc. and Starion Energy PA Inc., dated October 19, 2018.	8-K		2.1	10/25/2018	001-36559
3.1	Amended and Restated Certificate of Incorporation of Spark Energy, Inc.	8-K		3.1	8/4/2014	001-36559
3.2	Amended and Restated Bylaws of Spark Energy, Inc.	8-K		3.2	8/4/2014	001-36559

3.3	Certificate of Designations of Rights and Preferences of 8.75% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Stock.	8-A		5	3/11/2017	001-36559
4.1	Class A Common Stock Certificate	S-1		4.1	6/30/2014	333-196375

4.2	Convertible Subordinated Promissory Note of Spark HoldCo, LLC and Spark Energy, Inc. dated July 8, 2015 payable to Retailco Acquisition Co, LLC	10-Q		10.8	8/13/2015	001-36559

4.3	Convertible Subordinated Promissory Note of Spark HoldCo, LLC and Spark Energy, Inc. dated July 31, 2015 payable to Retailco Acquisition Co, LLC	10-Q		10.9	8/13/2015	001-36559

4.4	Promissory Note of CenStar Energy Corp., effective July 1, 2017, payable to Verde USA Holdings, LLC.	8-K		10.1	7/6/2017	001-36559

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4.5	Amended and Restated Promissory Note of CenStar Energy Corp., effective January 12, 2018, payable to Woden Holdings, LLC.	8-K	10.2	1/16/2018	001-36559
4.6	Promissory Note of CenStar Energy Corp., effective January 12, 2018, payable to Woden Holdings, LLC.	8-K	10.1	1/16/2018	001-36559
10.1	Credit Agreement, dated as of May 19, 2017, among Spark Energy, Inc., Spark HoldCo, LLC, Spark Energy, LLC, Spark Energy Gas, LLC, CenStar Energy Corp, CenStar Operating Company, LLC, Oasis Power, LLC, Oasis Power Holdings, LLC, Electricity Maine, LLC, Electricity N.H., LLC, Provider Power Mass, LLC, Major Energy Services LLC, Major Energy Electricity Services LLC, Respond Power LLC and Perigee Energy, LLC as Co-Borrowers, Coöperatieve Rabobank U.A., New York Branch, as Administrative Agent, an Issuing Bank and a Bank, and Coöperatieve Rabobank U.A., New York Branch and BBVA Compass, as Joint Lead Arrangers and Sole Bookrunner, and the Other Financial Institutions Signatory Thereto.	8-K	10.1	5/24/2017	001-36559
10.2	Amendment No. 1 to the Credit Agreement, dated as of November 2, 2017, among Spark HoldCo, LLC, Spark Energy, LLC, Spark Energy Gas, LLC, CenStar Energy Corp, CenStar Operating Company, LLC, Oasis Power, LLC, Oasis Electricity Maine, LLC, Electricity N.H., LLC, Provider Power Mass, LLC, Major Energy Services, LLC, Perigee Energy, LLC, Verde Energy USA, Inc. as Co-Borrowers.	10-Q	10.1	11/3/2017	001-36559
10.3	Amendment No. 2 to the Credit Agreement, dated as of July 17, 2018, by and among Spark Energy, Inc., the Co-Borrowers, the Banks party thereto, and Brown Borthers Harrisman & Co., as existing bank.	8-K	10.1	7/20/2018	001-36559
10.4	Amended and Restated Credit Agreement, dated as of July 8, 2015, among Spark Energy, Inc., as parent, Spark HoldCo, LLC, Spark Energy, LLC, Spark Energy Gas, LLC, CenStar Energy Corp, and CenStar Operating Company, LLC, as co-borrowers, Société Générale, as administrative agent, an Issuing Bank and a Bank, and SG Americas Securities, LLC and Compass Bank, as co-lead arranger, SG Americas Securities, LLC, as sole bookrunner, Compass Bank, as syndication agent, Cooperative Centrale Raiffeisen-Boerenleenbank B.A., “Rabobank Nederland,” New York Branch, as documentation agent, and the other financial institutions signatory thereto.	8-K	10.1	7/9/2015	001-36559

10.5	Amendment No. 1 to Amended and Restated Credit Agreement, dated October 30, 2015 and effective as of October 31, 2015, by and among Spark HoldCo, LLC, Spark Energy, LLC, Spark Energy Gas, LLC, CenStar Energy Corp, CenStar Operating Company, LLC, Oasis Power Holdings, LLC, Oasis Power, LLC, Spark Energy, Inc., the Banks party thereto and Société Générale, as administrative agent.	10-K	10.2	3/24/2016	001-36559

10.6	Amendment No. 2 to Amended and Restated Credit Agreement, dated and effective as of December 30, 2015, by and among Spark HoldCo, LLC, Spark Energy, LLC, Spark Energy Gas, LLC, CenStar Energy Corp, CenStar Operating Company, LLC, Oasis Power Holdings, LLC, Oasis Power, LLC, Spark Energy, Inc., the Banks party thereto and Société Générale, as administrative agent.	10-K	10.3	3/24/2016	001-36559

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10.7	Amendment No. 3 to Amended and Restated Credit Agreement, dated as of June 1, 2016, by and among the Company, Spark HoldCo, Spark Energy, LLC, Spark Energy Gas, LLC, CenStar Energy Corp, CenStar Operating Company, LLC, Oasis Power Holdings, LLC and Oasis Power, LLC, as co-borrowers, the banks party thereto and Société Générale, as administrative agent.	10-Q	10.4	8/11/2016	001-36559
10.8	Amendment No. 4 to Amended and Restated Credit Agreement, effective as of August 1, 2016, by and among the Company, Spark HoldCo, Spark Energy, LLC, Spark Energy Gas, LLC, CenStar Energy Corp, CenStar Operating Company, LLC, Oasis Power Holdings, LLC and Oasis Power, LLC, as co-borrowers, the banks party thereto and Société Générale, as administrative agent.	8-K	10.2	8/1/2016	001-36559

10.9	Tax Receivable Agreement, dated as of August 1, 2014, by and among Spark Energy, Inc., Spark HoldCo LLC, NuDevco Retail Holdings, LLC, NuDevco Retail, LLC and W. Keith Maxwell III.	8-K	10.2	8/4/2014	001-36559

10.10+	Master Service Agreement, effective as of January 1, 2016, by and among Spark HoldCo, LLC, Retailco Services, LLC, and NuDevco Retail,. LLC.	10-K	10.6	3/24/2016	001-36559

10.11†	Spark Energy, Inc. Long-Term Incentive Plan	S-8	4.3	7/31/2014	333-197738

10.12†	Spark Energy, Inc. Amended and Restated Long-Term Incentive Plan.	10-Q	10.3	11/10/2016	001-36559
10.13†	Form of Restricted Stock Unit Agreement	S-1	10.4	6/30/2014	333-196375

10.14†	Form of Notice of Grant of Restricted Stock Unit	S-1	10.5	6/30/2014	333-196375

10.15†	Form of Notice of Grant of Restricted Stock Unit (Change in Control Restricted Stock Units).	10-Q	10.5	8/3/2018	001-36559
10.15†		10-Q	10.5	8/3/2018	001-36559
10.16	Spark HoldCo. Third Amended and Restated Limited Liability Agreement, dated as of March 15, 2017, by and among Spark Energy, Inc., Retailco, LLC and NuDevco Retail, LLC.	10-Q	10.5	5/8/2017	001-36559
10.17	Amendment No. 1, dated as of January 26, 2018, to Third Amended and Restated Limited Liability Company Agreement of Spark Holdco, LLC.	8-K	10.1	1/26/2018	001-36559
10.18†	Indemnification Agreement, dated August 1, 2014, by and between Spark Energy, Inc. and W. Keith Maxwell III.	8-K	10.5	8/4/2014	001-36559
		8-K	10.5	8/4/2014	001-36559
10.19†	Indemnification Agreement, dated August 1, 2014, by and between Spark Energy, Inc. and Nathan Kroeker.	8-K	10.6	8/4/2014	001-36559

10.20†	Indemnification Agreement, dated August 1, 2014, by and between Spark Energy, Inc. and Gil Melman.

10.21†	Indemnification Agreement, dated August 1, 2014, by and between Spark Energy, Inc. and James G. Jones II.	8-K	10.10	8/4/2014	001-36559

10.22†	Indemnification Agreement, dated August 1, 2014, by and between Spark Energy, Inc. and Kenneth M. Hartwick.	8-K	10.12	8/4/2014	001-36559
		8-K	10.12	8/4/2014	001-36559
10.23†	Indemnification Agreement, dated May 25, 2016, by and between Spark Energy, Inc. and Jason Garrett.	8-K	10.2	5/27/2016	001-36559

10.24†	Indemnification Agreement, dated May 25, 2016, by and between Spark Energy, Inc. and Nick W. Evans, Jr.	8-K	10.1	5/27/2016	001-36559

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10.25†	Indemnification Agreement, dated June 2, 2016, by and between Spark Energy, Inc. and Robert Lane.	8-K	10.3	6/3/2016	001-36559
10.26	Registration Rights Agreement, dated as of August 1, 2014, by and among Spark Energy, Inc., NuDevco Retail Holdings, LLC and NuDevco Retail LLC.	8-K	10.4	8/4/2014	001-36559

10.27	Transaction Agreement II, dated as of July 30, 2014, by and among Spark Energy, Inc., Spark HoldCo, LLC, NuDevco Retail LLC, NuDevco Retail Holdings, LLC, Spark Energy Ventures, LLC, NuDevco Partners Holdings, LLC and Associated Energy Services, LP.	8-K	4.1	8/4/2014	001-36559

10.28†	Employment Agreement, dated April 15, 2015, by and between Spark Energy, Inc. and Nathan Kroeker.	8-K	10.1	4/20/2015	001-36559

10.29†	Employment Agreement, dated April 15, 2015, by and between Spark Energy, Inc. and Gil Melman.	8-K	10.4	4/20/2015	001-36559

10.30†	Employment Agreement, dated August 3, 2015, by and between Spark Energy, Inc. and Jason Garrett.	8-K	10.1	8/4/2015	001-36559

10.31†	Amended and Restated Employment Agreement, dated June 2, 2016, by and between Spark Energy, Inc. and Robert Lane.	8-K	10.1	6/3/2016	001-36559
10.32†	Amended Employment Agreement between Spark Energy, Inc. and Nathan Kroeker dated August 1, 2018.	10-Q	10.2	8/3/2018	001-36559
10.33†	Amended and Restated Employment Agreement between Spark Energy, Inc. and Jason Garrett dated August 1, 2018.	10-Q	10.3	8/3/2018	001-36559
10.34†	Amended and Restated Employment Agreement between Spark Energy, Inc. and Gil Melman dated August 1, 2018.	10-Q	10.4	8/3/2018	001-36559
10.35†	Transition and Resignation Agreement and Mutual Release of Claims, by and between Spark Energy, Inc. and Gil Melman, dated December 13, 2018.	10-Q	10.1	12/14/2018	001-36559
10.36	Membership Interest Purchase Agreement, dated as of May 12, 2015, by and between Retailco Acquisition Co, LLC and Spark HoldCo, LLC.	10-Q	10.5	5/14/2015	001-36559

10.37	Subscription Agreement, by and between Spark Energy, Inc., Spark HoldCo, LLC and Retailco, LLC, dated as of May 3, 2016.	10-Q	10.1	5/5/2016	001-36559
10.38	Amended and Restated Subscription Agreement, dated as of July 27, 2016, by and among Spark Energy, Inc., Spark HoldCo, LLC and Retailco, LLC.	8-K	10.1	8/1/2016	001-36559
10.39	Subordinated Promissory Note of Spark HoldCo, LLC and Spark Energy, Inc., dated December 27, 2016.	8-K	10.1	12/30/2016	001-36559
10.40	Termination Agreement, dated March 7, 2018, by and among Spark HoldCo, LLC, Retailco Services, LLC and NuDevco Retail, LLC.	10-K	10.43	3/9/2018	001-36559
16.1	Letter of KPMG LLP, dated August 16, 2018 to the SEC	8-K	16.1	8/16/2018	001-36559
21.1*	List of Subsidiaries of Spark Energy, Inc.

23.1*	Consent of EY

23.2 *	Consent of KPMG

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

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

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

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101.INS*	XBRL Instance Document.

101.SCH*	XBRL Schema Document.

101.CAL*	XBRL Calculation Document.

101.LAB*	XBRL Labels Linkbase Document.

101.PRE*	XBRL Presentation Linkbase Document.

101.DEF*	XBRL Definition Linkbase Document.

* Filed herewith

** Furnished herewith

† Compensatory plan or arrangement

+ Portions of this exhibit have been omitted and filed separately with the SEC pursuant to an order granting confidential treatment.

# The registrant agrees to furnish supplementally a copy of any omitted schedule to the Commission upon request.

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SIGNATURES

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



March 4, 2019	Spark Energy, Inc.
	By:	/s/ Robert Lane
		Robert Lane
		Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant in the capacities indicated on March 4, 2019:

	By:	/s/ Nathan Kroeker
		Nathan Kroeker
		Director, President and Chief Executive Officer (Principal Executive Officer)

		/s/ W. Keith Maxwell III
		W. Keith Maxwell III
		Chairman of the Board of Directors, Director

		/s/ Robert Lane
		Robert Lane
		Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)

		/s/ James G. Jones II
		James G. Jones II
		Director

		/s/ Nick Evans Jr.
		Nick Evans Jr.
		Director

		/s/ Kenneth M. Hartwick
		Kenneth M. Hartwick
		Director

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