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, 2017.
 OR
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 and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted 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 (Do not check if a smaller reporting company) 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, 2017, the last business day of the registrant's most recently completed second fiscal quarter, based on the closing price on that date of $18.80, was approximately $215 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 13,135,636 shares of Class A common stock, 21,485,126 shares of Class B common stock and 3,707,256 shares of Series A Preferred Stock outstanding as of March 7, 2018.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant's definitive Proxy Statement in connection with the 2018 Annual Meeting of Stockholders are incorporated by reference into Part III of this Form 10-K.



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







Glossary
CFTC. The Commodity Futures Trading Commission.
CPUC. California Public Utility Commission.
ERCOT. The Electric Reliability Council of Texas, the independent system operator and the regional coordinator of various electricity systems within Texas.
ESCO. Energy service company.
FCC. Federal Communications Commission.
FERC. The Federal Energy Regulatory Commission, a regulatory body that regulates, among other things, the transmission and wholesale sale of electricity and the transportation of natural gas by interstate pipelines in the United States.
FTC. Federal Trade Commission.
ISO. An independent system operator. An ISO manages and controls transmission infrastructure in a particular region.
MMBtu. One million British Thermal Units, a standard unit of heating equivalent measure for natural gas. A unit of heat equal to 1,000,000 Btus, or 1 MMBtu, is the thermal equivalent of approximately 1,000 cubic feet of natural gas.
MWh. One megawatt hour, a unit of electricity equal to 1,000 kilowatt hours (kWh), or the amount of energy equal to one megawatt of constant power expended for one hour of time.
Non-POR Market. A non-purchase of accounts receivable market.
NYPSC. New York Public Service Commission.
POR Market. A purchase of accounts receivable market.
REC. Renewable Energy Credit.
RCE. A residential customer equivalent, refers to a natural gas customer with a standard consumption of 100 MMBtus per year or an electricity customer with a standard consumption of 10 MWhs per year.
REP. A retail electricity provider.
RTO. A regional transmission organization. A RTO, similar to an ISO, is a third party entity that manages transmission infrastructure in a particular region.
TCPA. Telephone Consumer Protection Act of 1991.

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,” “projects,” 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, 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 and the sufficiency of risk management and hedging policies;
extreme and unpredictable weather conditions, and the impact of hurricanes and other natural disasters;
federal, state and local regulation, including the industry's ability to address or adapt to potentially restrictive new regulations that may be enacted by the New York Public Service Commission;
our ability to borrow funds and access credit markets and restrictions in our debt agreements and collateral requirements;
credit risk with respect to suppliers and customers;
changes in costs to acquire customers and actual customer attrition rates;
accuracy of billing systems;
whether our majority stockholder or its affiliates offer us acquisition opportunities on terms that are commercially acceptable to us;
ability to successfully identify, complete, and efficiently integrate acquisitions into our operations;
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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Table of Contents

PART I.

Items 1 & 2. Business and Properties

General
We are a growing independent retail energy services company founded in 1999 and now organized as a Delaware corporation that provides residential and commercial customers in competitive markets across the United States with an alternative choice for their natural gas and electricity. We purchase our 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.
Our business consists of two operating segments:
Retail Electricity Segment. We purchase electricity supply through physical and financial transactions with market counterparts 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, 2017, 2016 and 2015, approximately 82%, 76% and 64%, respectively, of our retail revenue were derived from the sale of electricity. 

Retail Natural Gas Segment. We purchase natural gas supply through physical and financial transactions with market counterparts and supply natural gas to residential and commercial consumers pursuant to fixed-price and variable-price contracts. For the years ended December 31, 2017, 2016 and 2015, approximately 18%, 24% and 36%, respectively, of our retail revenues were derived from the sale of natural gas. We also identify wholesale natural gas arbitrage opportunities in conjunction with our retail procurement and hedging activities, which we refer to as asset optimization. 

See Note 15 "Segment Reporting" to the Company’s audited consolidated financial statements in this report for financial information relating to our operating segments.

Recent Developments

See “Management's Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments” for a discussion of recent developments affecting our business and operations.

Our Operations

As of December 31, 2017, we operated in 94 utility service territories across 19 states and the District of Columbia and had approximately 1,042,000 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 nine brands (Spark Energy, CenStar Energy, Electricity Maine, ENH Power, Major Energy, Oasis Energy, Provider Power Mass, Respond Power, and Verde Energy).

Customer Contracts and Product Offerings

Fixed and variable-price contracts

We offer a variety of fixed-price and variable-price service options to our natural gas and electricity customers. Under our fixed-price service options, our customers purchase natural gas and electricity at a fixed price over the

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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, including the competitive landscape in the market and the regulatory environment. 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, 2017, approximately 54% of our natural gas RCEs were fixed-price, and the remaining 46% of our natural gas RCEs were variable-price. As of December 31, 2017, approximately 82% of our electricity RCEs were fixed-price, and the remaining 18% of our electricity RCEs were variable-price.
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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 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 amount 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


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Our customer acquisition strategy consists of customer growth obtained through traditional organic customer acquisitions, complemented by opportunistic acquisitions. We make decisions on how best to deploy capital on customer acquisitions based on a variety of factors, including cost to acquire customers, availability of opportunities and our view of attractive commodity pricing in particular regions. For example, we may seek to make an acquisition of a large number of customers in a particular group of markets even though the initial acquisition cost may be higher because long-term margins are higher. We expect to focus on organic growth through 2018.

Organic Growth

Our organic sales strategies are used 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 and the price the local regulated utility is offering. We then determine if there is an opportunity in a particular market based on our ability to create an attractive customer value proposition that is also able to enhance our profitability. 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 a 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, with an emphasis on door-to-door and web-based marketing. We identify and acquire customers through a variety of additional sales channels, including our inbound customer care call center, online marketing, email, direct mail, brokers and direct sales. 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 customer acquisition costs. We attempt to maintain a disciplined approach to recovery of our customer acquisition costs within defined periods.

Acquisitions

We acquire both portfolios of customers as well as retail energy companies through some combination of cash, borrowings under the Senior Credit Facility, the issuance of common or preferred stock or other financing arrangements with our Founder and his affiliates. Historically, a significant component of our customer acquisition strategy has been the relationship and growth strategy structure with NG&E. See “—Relationship with our Founder and Majority Shareholder” for a discussion of this relationship.

The following table provides a summary of our acquisitions over the past five years, including the name of the retail energy company or an indication if the acquisition was a portfolio of customers, the date completed, the RCE count, the segment and the source of the acquisition:


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Company / Portfolio
Date Completed
RCEs
Segment
Acquisition Source
 
 
Customer Portfolio
February 28, 2015
12,500
Electricity
Third Party
 
CenStar Energy Corp.
July 8, 2015
65,000
Natural Gas
Electricity
Third Party
 
Oasis Power Holdings, LLC
July 31, 2015
40,000
Natural Gas
Electricity
Founder / NG&E
 
Customer Portfolio
September 30, 2015
9,500
Natural Gas
Third Party
 
Provider Companies (1)
August 1, 2016
121,000
Electricity
Third Party
 
Major Energy Companies (2)
August 23, 2016
220,000
Natural Gas
Electricity
Founder / NG&E
 
Perigee Energy, LLC
April 1, 2017
17,000
Natural Gas
Electricity
Founder / NG&E
 
Verde Companies (3)
July 1, 2017
145,000
Electricity
Third Party
 
Customer Portfolio (4)
October 31, 2017 (4)
44,000
Electricity
Third Party
 
HIKO Energy, LLC
March 1, 2018
29,000
Natural Gas
Electricity
Third Party
 
Customer Portfolio
(5)
50,000
Natural Gas
Electricity
Founder / NG&E

(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)
Customers will begin transferring to the Company in April 2018.

Please see and Item 9B. “Other Information” and Note 3 "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.

We are actively monitoring acquisition opportunities that may arise in the domestic acquisition market as smaller retailers face difficulties in managing risk and liquidity issues caused by the recent extreme weather patterns. Our ability to grow at historic levels 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. Please see “Risk FactorsRisks Related to Our Business and Our IndustryWe may be subject to risks in connection with acquisitions, which could cause us to fail to realize many of the anticipated benefits of such acquisition” and “Risk FactorsRisks Related to Our Capital StockWe engage in transaction with our affiliates and expect to do so in the future. The terms of such transactions and the resolution of any conflict that may arise may not always be in our or our stockholders’ best interest.”

Growth Sources and Sales Channels

During the year ended December 31, 2017, our RCE acquisitions were generated from the following sources and sales channels:
Indirect Sales Brokers
30
%
Acquisitions
25
%
Web Based
14
%
Door to Door
13
%
Outbound
5
%
Other
13
%


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In 2017, we grew our commercial and industrial (“C&I”) customer base. C&I customers typically have larger natural gas and electricity volume requirements, but at lower margins than residential customers. These C&I customers also typically have longer contract terms. After significant growth in our C&I customer count in 2017, management is rebalancing our mix of customers in the first part of 2018 to focus on higher margin residential customers. At December 31, 2017, approximately 48% of the Company’s RCEs were C&I customers.

Retaining customers and maximizing customer lifetime value

Following our acquisition of customers, management and marketing teams 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. Spark may elect to contact the customer through additional channels such as outbound telephone calls and electronic mail communication. We encourage retention and promote renewals by means of each of these contact methods.

We also apply a proprietary evaluation and segmentation process to optimize value both to 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

The Company and Spark HoldCo, together with eREX Co., Ltd., a Japanese company, are joint venture partners 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, 2017, the Company has contributed 156.4 million Japanese Yen, or $1.4 million, for a 20% ownership interest in ESM. As of December 31, 2017, ESM has approximately 100,000 customers, which are currently excluded from our count of residential customer equivalents ("RCEs").

Asset Optimization

Part of our business includes asset optimization activities in which we identify opportunities in the natural gas wholesale marketplace 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. With respect to our allocated storage assets, we are also 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 purchase and injection obligations in our allocated storage assets require us to take a seasonal long position in natural gas. Our asset optimization group determines whether market conditions justify hedging these long positions through additional derivative transactions.

Our asset optimization group utilizes these allocated transportation and storage assets for retail customer usage and to effect transactions in the wholesale market based on market conditions and opportunities. Our asset optimization group also contracts with third parties for transportation and storage capacity in the wholesale market. We 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 point or pool and ship it using our pipeline reservations for sale at another point or pool, in each case if we are able to capture a margin. We view these spot market transactions as low risk because we enter

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into the buy and sell transactions simultaneously on a back-to-back basis. We will also act as an intermediary for market participants who need assistance with short-term procurement requirements. Consumers and suppliers will contact us with a need for a certain quantity of natural gas to be bought or sold at a specific location. We are able to use our contacts in the wholesale market to source the requested supply, and we will capture a margin in these transactions.

The asset optimization group historically entered into long-term transportation and storage transactions. Our risk policies require that this business is limited to back-to-back purchase and sale transactions, or open positions subject to our 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 our risk committee. Hedges on our firm transportation obligations are limited to two years or less and hedging of interruptible capacity is prohibited.

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 buy 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.

Commodity Supply

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 in-house energy supply team is responsible for managing our commodity positions (including energy procurement, capacity, transmission, renewable energy, and resource adequacy requirements) within risk tolerances defined by 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.

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 customers’ locations. Additionally, we hedge our natural gas price exposure with financial products. During the year ended December 31, 2017, we transacted physical and financial settlement of natural gas with approximately 93 wholesale counterparties.

In most markets, we typically hedge our electricity exposure with financial products and then purchase the physical power directly from the ISO for delivery. From time to time, we use a combination of physical and financial products to hedge our electricity exposure before buying physical electricity in the day-ahead and real-time market from the ISO. During the year ended December 31, 2017, we transacted physical and financial settlement of electricity with approximately 17 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.

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Risk Management

Our management team operates 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 procurement, capacity, transmission, renewable energy, and resource adequacy requirements) within risk tolerances defined by our risk management policies. We attempt to increase the predictability of cash flows by following our various hedging strategies.

The 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.

Commodity Price and Volumetric Risk

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

Customer demand is also 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 financial results.

In addition to our forward price risk management approach described above, we may take further measures to reduce price risk and optimize our returns by: (i) maximizing the use of 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

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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 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.

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 collections program. Using risk models, past credit experience and different levels of exposure in each of the markets, we monitor our aging, bad debt forecasts and actual bad debt expenses and continually adjust as necessary.

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 then becomes responsible for billing the customer and collecting payment from the customer. This service results 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, 2017, 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 as of such date. During the same period, we paid these local regulated utilities a weighted average discount of approximately 1.1% 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 collection efforts are unsuccessful, we return the account to the local regulated utility for termination of service. Under these service programs, we are exposed to credit risk related to payment for services rendered during the time between when the customer is transferred to us by the local regulated utility and the time we return the customer to the utility for termination of service, which is generally one to two billing periods. We may also realize a loss on fixed-price customers in this scenario due to the fact that we will have already fully hedged the customer’s expected commodity usage for the life of the contract.

In non-POR markets (and in POR markets where we may choose to direct bill our customers), we manage 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

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also maintain an allowance for doubtful accounts, which represents our estimate of potential credit losses associated with accounts receivable from customers within non-POR markets.

We assess the adequacy of the allowance for doubtful accounts through review of the 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, 2017 was $6.6 million, or 0.8% of retail revenues. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Drivers of Our Business—Customer Credit Risk” for a more detailed discussion of our bad debt expense during the year ended December 31, 2017.

We have limited exposure to high concentrations of sales volumes to individual customers. For the year ended December 31, 2017, our largest customer accounted for less than 1% of total retail energy sales volume.

Counterparty Credit Risk in Wholesale Market

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 as a result of being unable to secure replacement supplies of natural gas or electricity on a timely and cost-effective basis or at all. At December 31, 2017, approximately 84% of our total exposure of $34.2 million was either with an investment grade customer or otherwise secured with collateral or a guarantee.

Operational Risk

As with all companies, the Company is 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 continue to enhance awareness with employee education and accountability. As of December 31, 2017, we have not experienced any material loss related to cyber-attacks or other information security breaches.

Relationship with our Founder and Majority Shareholder

Growth Support

We have historically leveraged our relationship with affiliates of our founder, chairman and majority shareholder, W. Keith Maxwell III (our "Founder"), to execute on our growth strategy, which includes sourcing of acquisitions, financing support, and operating cost efficiencies. To support this relationship, our Founder formed National Gas & Electric, LLC, an affiliate of the Company (“NG&E”), in 2015 for the purpose of purchasing retail energy companies and retail customer books that could ultimately be resold to the Company. This relationship affords us access to opportunities that might not otherwise be available to us due to our size and availability of capital.

On March 7, 2018, we entered into an asset purchase agreement with NG&E pursuant to which we will acquire approximately 50,000 RCEs from NG&E for a cash purchase price of $250 for each RCE, or approximately $12.5 million in the aggregate. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments—Acquisition of Customers from NG&E.” For a summary of historical acquisitions with our Founder and NG&E, please see “—Customer Acquisition and Retention—Acquisitions.”

We may engage in additional transactions with NG&E in the future. We currently expect that we would fund any future transactions with NG&E with some combination of cash, subordinated debt, or the issuance of Class A common stock or Class B common stock to NG&E. However, actual consideration paid for the assets will depend, among other things, on our capital structure and liquidity at the time of any transaction.

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Given our Founder's significant economic interest in us, we believe that he is incentivized to offer us opportunities to grow through this drop-down structure. However, our Founder and his affiliates are under no obligation to offer us acquisition opportunities, and we are under no obligation to buy assets from them. Additionally, as we grow and our access to capital and opportunities improves, we may rely less upon NG&E as a source of acquisitions and seek to enter into more transactions directly with third parties. 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 the Board of Directors consisting solely of independent directors. Please see “Risk Factors—Risks Related to Our Business and Our Industry—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" and "Risk Factors—Risks Related to Our Capital Stock—We engage in transactions with our affiliates and expect to do so in the future. The terms of such transactions and resolution of any conflicts that may arise may not always be in our or our stockholders' best interest."

Master Service Agreement

We entered into a Master Service Agreement (the “Master Service Agreement”) effective January 1, 2016 with Retailco Services, LLC ("Retailco Services"), which is wholly owned by our Founder. The Master Service Agreement is for a one-year term and renews automatically for successive one-year terms unless the Master Service Agreement is terminated by either party. On January 1, 2018, the Master Service Agreement renewed automatically pursuant to its terms for a one year period ending on December 31, 2018.

Retailco Services provides us with 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 under the Master Service Agreement (collectively, the "Services"). Spark HoldCo pays Retailco Services a monthly fee consisting of a monthly fixed fee plus a variable fee per customer per month depending on market complexity. We meet with Retailco Services quarterly to discuss fees and Service Levels (as defined below) based on changes in assumptions; to date, we have not adjusted fees or the Service Levels. The Master Service Agreement provides that Retailco Services perform the Services in accordance with specified service levels (the “Service Levels”), and in the event Retailco Services fails to meet the Service Levels, Spark HoldCo receives a credit against invoices or a cash payment (the “Penalty Payment”). The amount of the Penalty Payment was initially limited to $0.1 million monthly, but adjusts annually based upon the amount of fees charged by Retailco Services for Services over the prior year. Furthermore, in the event that the Service Levels are not satisfied and Spark HoldCo suffers damages in excess of $0.5 million as a result of such failure, Retailco Services will make a payment (the “Damage Payment”) to Spark HoldCo for the amount of the damages (less the amount of any Penalty Payments also due). The Master Service Agreement provides that in no event may the Penalty Payments and Damage Payments exceed $2.5 million in any twelve-month period.

In connection with the Master Service Agreement, certain of Spark HoldCo’s employees who previously provided services similar to those to be provided under the Master Service Agreement became employees of Retailco Services, and certain contracts, assets, and intellectual property were assigned to Retailco Services. In addition, in order to facilitate the Services, Spark HoldCo granted Retailco Services a non-transferable, non-exclusive, royalty-free, revocable and non-sub-licensable license to use certain of its intellectual property.

Either Spark HoldCo or Retailco Services is permitted to terminate the Master Service Agreement: (a) upon 30 days prior written notice for convenience and without cause; (b) upon a material breach and written notice to the breaching party when the breach has not been cured 30 days after such notice; (c) upon written notice if Retailco Services is unable for any reason to resume performance of the services within 60 days following the occurrence of an event of force majeure; and (d) upon certain events of insolvency, assignment for the benefit of creditors, cessation of business, or filings of petitions for bankruptcy or insolvency proceedings by the other party. In the event the Master Service Agreement is terminated for any reason, Retailco Services will provide certain transition services to Spark HoldCo following the termination, not to exceed six months at the then-current fees.     


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Retailco Services and Spark HoldCo have agreed to indemnify each other from: (a) willful misconduct or negligence of the other; (b) bodily injury or death of any person or damage to real and/or tangible personal property caused by the acts or omission of the other; (c) any breach of any representation, warranty, covenant or other obligation of the other party under the Master Service Agreement, and (d) other standard matters. Subject to certain exceptions (including indemnification obligations, the obligations to pay fees and the Damage Payments and Penalty Payments), each parties’ liability is limited to $2.5 million of direct damages. NuDevco Retail has entered into the Master Service Agreement for the limited purpose of guarantying payments that Retailco Services may be required to make under the Master Service Agreement up to a maximum of $2.0 million.

During the year ended December 31, 2017 and 2016, the Company recorded general and administrative expenses of $22.0 million and $14.7 million, respectively, in connection with the Master Service Agreement. For the years ended December 31, 2017 and 2016, Penalty Payments totaled $0.1 million, and Damage Payments totaled zero and $1.4 million, respectively. Additionally, under the Master Service Agreement, we capitalized $0.7 million and $1.3 million, respectively, during the years ended December 31, 2017 and 2016 of property and equipment for software and consultant time used in the application, development and implementation of various systems including customer billing and resource management systems.

On March 7, 2018, we, Retailco Services and NuDevco Retail mutually agreed to terminate the Master Services Agreement, effective April 1, 2018. Please see “Management’s Discussion of Analysis of Financial Condition and Results of Operations—Recent Developments—Termination of Master Service Agreement” and “Risk Factors—The termination of the Master Service Agreement subjects us to a variety of risks.”

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 Direct Energy, Inc., FirstEnergy Solutions, Inc., Just Energy Group, Inc. and NRG Energy, Inc. 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. With respect to natural gas, 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.

The competitive landscape differs in each utility service area and within each targeted customer segment. Over the last several years, a number of utilities have spun off their retail marketing arms as part of the opening of retail competition in these markets. Markets that offer POR programs are generally more competitive than those markets in which retail energy providers bear customer credit risk. Market participants are significantly shielded from bad debt expense, thereby allowing easier entry into the POR markets. In these markets, we face additional competition as barriers to entry are less onerous.

Our ability to compete by increasing our market share 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, long 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 could affect our cash flows, especially during peak cycles in the winter and summer months.

Natural gas accounted for approximately 18% of our retail revenues for the year ended December 31, 2017, 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. We must comply with the legislation and regulations in these jurisdictions in order to maintain our licensed status and to continue our operations, and 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 level, and failure to comply with requirements imposed by federal and state regulatory authorities could impact our licensing in a particular market.

As of October 2015, the state of Connecticut no longer allows retail energy providers to offer variable rate plans even after the customer rolls off of a fixed rate plan. As a result of this change, we now offer customers who end their fixed terms with another fixed term of no less than four billing cycles. This regulatory change did not have a significant impact on our results of operations, and we expect that we can continue to manage the renewals in these markets to maintain profitability. Other states are currently examining the effectiveness of implementing such a restriction.

On February 23, 2016, the New York State Public Service Commission ("NYPSC") issued an order ("the Resetting 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 Resetting 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. On July 22, 2016, most of the Resetting Order, including the provisions previously noted, was vacated by a New York state court.

On July 27, 2017, the New York State Supreme Court, Appellate Division, Third Department ruled to uphold the lower court’s ruling overturning portions of the Resetting Order because the NYPSC did not follow the proper

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process in issuing the Resetting 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 will be going forward, which concluded in late 2017. Briefing on these hearings is due by April 30, 2018. We believe that the administrative law judges overseeing the proceeding will provide for settlement discussions before adjudication of the matter. There can be no assurance that settlement discussions between the NYPSC and ESCOs will occur, or if such discussions occur, that they 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."

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 longer term gift-term or guaranteed savings arrangements (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 are dropping low-income customers to the applicable utilities in the next twelve months as they roll off of their contracts. These customers represent approximately less than 1% of our total customer count as of December 31, 2017.

We are evaluating the potential impact of the NYPSC's Resetting Order 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.

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 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, the Company is experimenting with new technologies such as ringless messaging and door-to-door sales using tablets, both of which expand 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, including regulation

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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.

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.

On December 26, 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, 2017. This number does not include employees of Retailco Services who provide services to us under the Master Service Agreement as described under “Relationship with Our Founder and Majority Shareholder—Master Service Agreement.”

We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We consider our relations with our employees to be satisfactory. We also utilize the services of independent contractors and vendors to perform various services.

Facilities

Our corporate headquarters is located in Houston, Texas. We believe that our facilities are adequate for our current operations. We share our corporate headquarters with certain of our affiliates. NuDevco Midstream Development, LLC, an indirect subsidiary of TxEx Energy Investments, LLC, is the lessee under the lease agreement covering these facilities. NuDevco Midstream Development, LLC pays the entire lease payment on behalf of the affiliates of TxEx Energy Investments, LLC, and we reimburse NuDevco Midstream Development, LLC 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”), 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 that we have filed with the SEC may be read and copied at the SEC’s Public Reference Room at 100 F Street, NE, Washington D.C. 20549, or accessed by calling the SEC at 1-800-SEC-0330 or visiting 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. 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 due to any of these risks.
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 the following:
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.
Changes to the prices we pay to acquire commodities and that we are not able to pass along to our customers could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
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. Our failure to accurately anticipate demand due to fluctuations in weather or to effectively manage our supply in response to a fluctuating commodity price environment could

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materially and adversely affect our business, financial condition, cash flows and results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
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 recall.
If we are unable to effectively manage our risk management policies and hedging procedures, it could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
We face risks due to increasing regulation of the retail energy industry at the state level.


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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 New York Public Service Commission (the “NYPSC”) began an aggressive campaign in 2016 to limit the types of competitive products that ESCOs, such as us, can offer in New York. The NYPSC attempted to implement a market resetting 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 resetting order was vacated by a New York state court on July 22, 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 another similar resetting order. In the event that all or significant components of the original resetting order are re-implemented, ESCOs, including us, could be obligated to drop customers to the utility or seek affirmative consent from their fixed and variable rate customers upon renewal, which may be very difficult to obtain. As of December 31, 2017, approximately 16% of our customers on an RCE basis were located in New York.

The NYPSC has also successfully 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 guaranteed savings arrangements (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 are being required to drop low-income customers to the applicable utilities in the next twelve months, representing approximately less than 1% of our total customer count as of December 31, 2017.

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. Any such regulations could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.

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. Accordingly, changing or additional regulations or restrictions could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.

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.

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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. If any violation of the TCPA were to occur, it could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.

We are subject to risks of significant liability resulting from class action lawsuits.

In recent years, retail energy providers have been named as defendants in class action lawsuits relating to pricing and sales practices, among other matters. A number of these lawsuits have resulted in substantial jury awards or settlements. We are currently a defendant in several class action lawsuits involving sales practices or TCPA claims. A negative outcome could result in significant damages depending on whether a class is certified, and if so, the size of a such class. Future litigation relating to our pricing and sales practices may negatively impact us by requiring us to pay substantial awards or settlements, increasing our legal costs, diverting management attention from other business issues or harming our reputation with customers, which could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
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. If we have a license revoked or are not granted renewal of a license, or if our license is adversely conditioned or modified (e.g., by increased bond posting obligations), it could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.

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 intend to grow our business in part through strategic acquisition opportunities from third parties and potentially from affiliates of our majority shareholder. Achieving the anticipated benefits of these transactions will depend in part upon our ability to identify accretive acquisition targets, accurately assess the benefits and risks of the acquisition prior to undertaking it, and our ability to integrate the acquired businesses in an efficient and effective manner.

We intend to make acquisitions that are accretive to Adjusted EBITDA. We may be unable to identify attractive acquisition candidates or negotiate commercially acceptable terms for such acquisitions. Even if we identify a target, the successful acquisition of a business requires assessing several factors, including anticipated cash flow and accretive value, regulatory challenges, our ability to retain customers and assumed liabilities. The accuracy of these assessments is inherently uncertain and our assessments may turn out incorrect.

Furthermore, even if we make an acquisition, we may not be able to accomplish the integration process smoothly or successfully. The difficulties of integrating our acquisitions potentially will 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 acquisitions, 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;

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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 counter party 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 counter-party may fail to perform its indemnification obligations, which could result in the losses being incurred by us.
If any of the risks above were to occur, it could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
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. If these sources are not available, our ability to grow and maintain our business may be limited, which could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.

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 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. If we are unable to manage our growth and development successfully, it could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.

The termination of our Master Service Agreement subjects us to a variety of risks.

A significant portion of our operations, including enrollment and renewal transaction services, customer billing and transaction services, electronic payment processing services, customer services and information technology infrastructure and application support services, is currently provided to us by our affiliate, Retailco Services, LLC, for a fixed fee under the Master Service Agreement. The Master Service Agreement will terminate effective April 1, 2018, and we will be reintegrating the services previously provided to us by Retailco Services, LLC under the Master Service Agreement back into our operations. We may experience costs integrating these services back into our operations. Additionally, following the integration of those services back into our operations, we may

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experience fluctuations in general and administrative costs that we did not experience under the fixed-fee arrangement of the Master Service Agreement. If any of the risks above were to occur, it could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.

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.
Accordingly, we may experience seasonal, quarterly and annual fluctuations, which could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
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

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who terminates their contract early, we may not be able to collect the termination fees in full or at all. Our variable-price contracts can typically be terminated by our customers at any time without penalty.
If we are unable to obtain new customers or maintain our existing customers, due to competition or otherwise, it could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
Increased collateral requirements in connection with our supply activities may restrict our liquidity, which could limit our ability to grow our business or pay dividends.
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. If any of these risks were to occur, it could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
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 our 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, 2017, 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.
The failure of our customers to pay their bills or our failure to maintain adequate billing and collection procedures could adversely affect our financial results and our ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
Our indebtedness could adversely affect our ability to raise additional capital to fund our operations or pay dividends. It could also expose us to the risk of increased interest rates and limit our ability to react to changes in the economy or our industry as well as impact our cash available for distribution.

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We have $125.3 million of indebtedness outstanding and $47.2 million in issued letters of credit under our Senior Credit Facility, and no indebtedness outstanding under our Subordinated Facility as of December 31, 2017. 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 our ability to pay dividends to holders of our Class A common stock and Series A Preferred Stock, or to use our cash flow to fund our operations, capital expenditures and future business opportunities;
limiting our ability to fund future acquisitions or engage in other activities that we view as in our long-term best interest;
restricting our ability to make certain distributions with respect to our capital stock and the ability of our subsidiaries to make certain distributions to us, in light of restricted payment and other financial covenants, including requirements to maintain certain financial ratios, in our credit facilities and other financing agreements;
exposing us to the risk of increased interest rates because borrowings under our Senior Credit Facility 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 on May 19, 2019, and we cannot assure that we will be able to negotiate a new credit arrangement on commercially reasonable terms. The occurrence of any of the events above could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
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

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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. We do not maintain cyber-liability insurance that covers certain damage caused by cyber events.
Inaccurate data and disruptions of our information management systems to perform as anticipated for any reason could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
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. If our key executives do not continue in their present roles and are not adequately replaced, it could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.

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. Failure of our vendor to operate in accordance with the terms of the outsourcing agreement or the vendor’s bankruptcy or other event that prevents it from performing under our outsourcing agreement could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
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, 2017, approximately 60% of our RCEs were located in five states. Specifically, 16%, 12%, 12%, 11% and 9% of our customers on an RCE basis were located in NY, PA, CT, MA, and NH, 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. In addition, if any of the states that contain a large percentage of our customers were to reverse regulatory restructuring or change the regulatory environment in a manner that causes us to be unable to economically operate in that state, it could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
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 renewable energy credits, or 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

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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. Accordingly, such decrease may result in reduced revenue and could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
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. If any of these risks were to occur, it could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
Our vendors may expose us to risks.
We are subject to reputational risks that may arise from the actions of our vendors and their independent contractors that are wholly or partially beyond our control, such as violations of our marketing policies and procedures as well as any failure to comply with applicable laws and regulations. If our vendors engage in marketing practices that are not in compliance with local laws and regulations, we may be in breach of applicable laws and regulations that may result in regulatory proceedings, disadvantageous conditioning of our energy retailer license, or the revocation of our energy retailer license. Unauthorized activities in connection with sales efforts by agents of our vendors, including calling consumers in violation of the TCPA and predatory door-to-door sales tactics and fraudulent misrepresentation could subject us to class action lawsuits against which we will be required to defend. Such defense efforts will be costly and time consuming. In addition, the independent contractors of our vendors may consider us to be their employer and seek compensation.
If any of these risks were to occur, it could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
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;

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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.
Due to the seasonality of our retail natural gas business, we generate the substantial majority of our cash available for distribution in the first and fourth quarters of each year. As a result of seasonality and our customer acquisition costs, we may not have sufficient cash available for distribution to cover quarterly dividends for certain quarters. 
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 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.

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We are a holding company. Our sole material asset is our equity interest in 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. To the extent that we need funds and Spark HoldCo or its subsidiaries are restricted from making distributions to us under applicable law or regulation or under the terms of their financing arrangements, or are otherwise unable to provide such funds, it could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
The Class A common stock and Series A Preferred Stock are subordinated to our existing and future debt obligations.
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;
— 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. An increase in market interest rates, which are currently 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.

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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 will depend 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 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 our certificate of incorporation and bylaws. Our Founder controls 67.0% of the combined voting power of the Class A common stock and Class B common stock as of December 31, 2017 through his direct and indirect ownership, including Retailco, LLC, which is the holder of approximately 63.3% of the combined voting power of the Class A common stock and Class B common stock.
Retailco, LLC is entitled to act separately in its own interest with respect to its investment in us. Retailco, LLC has the ability to elect all of the members of our board of directors, and thereby to control our management and affairs. In addition, Retailco, LLC is 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 Retailco, LLC continues to control a significant amount of our common stock, it 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 Retailco, LLC may differ or conflict with the interests of our other stockholders. Moreover, this concentration of stock ownership may also adversely affect the trading price of our Class A common stock or Series A Preferred Stock to the extent investors perceive a disadvantage in owning stock of a company with a controlling shareholder.
As a holder of Series A Preferred Stock, you have extremely limited voting rights.
Your voting rights as a holder 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.

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

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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 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

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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 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 the Tax Receivable Agreement for certain tax benefits we may claim, and the amounts of such payments could be significant.
We are party to a Tax Receivable Agreement with Spark HoldCo, NuDevco Retail Holdings and NuDevco Retail. This agreement generally provides for the payment by us to Retailco, LLC (as successor to NuDevco Retail Holdings) and NuDevco Retail 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 SparkHoldCo units from NuDevco Retail Holdings, (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. In addition, payments we make

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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 12 "Income Taxes" for further discussion.
Spark Energy, Inc. 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, Spark Energy, Inc. 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.
The payment obligations under the Tax Receivable Agreement are our obligations 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.
We did not meet the threshold coverage ratio required to fund the first payment to NuDevco Retail Holdings under the Tax Receivable Agreement during the four-quarter period ending September 30, 2015. As such, the initial payment under the Tax Receivable Agreement due in late 2015 was deferred pursuant to the terms thereof.
We met the threshold coverage ratio required to fund the second TRA Payment to Retailco and NuDevco Retail under the Tax Receivable Agreement during the four-quarter period ending September 30, 2016, resulting in an initial TRA Payment of $1.4 million becoming due in December 2016. On November 6, 2016, Retailco and NuDevco Retail granted us the right to defer the TRA Payment until May 2018. During the period of time when we have elected to defer the TRA Payment, the outstanding payment amount will accrue interest at a rate calculated in the manner provided for under the Tax Receivable Agreement.

We met the threshold coverage ratio required to fund the third TRA Payment to Retailco and NuDevco Retail under the Tax Receivable Agreement during the four-quarter period ended September 30, 2017. As such, the third payment under the Tax Receivable Agreement due in April 2018 has been classified as current in our consolidated balance sheet at December 31, 2017.
We expect to meet the threshold coverage ratio required to fund the fourth payment to Retailco and NuDevco Retail under the Tax Receivable Agreement during the four-quarter period ending September 30, 2018. The fourth payment under the Tax Receivable Agreement would be due in late 2018.
See also Note 14 "Transactions with Affiliates."

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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 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, 2017, the estimated contractual termination payment would be approximately $52.4 million (calculated using a discount rate equal to the one-year 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 respecting dividends and distributions, as our board of directors may determine. During the year ended December 31, 2017, we designated a class of preferred stock as Series A Preferred Stock and issued an aggregate of 94,339 shares of Series A Preferred Stock.
The terms of one or more classes or series of 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

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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, or until the earliest of (i) the last day of the fiscal year in which we have $1.07 billion or more in annual revenues; (ii) the date on which we become a "large accelerated filer" (the fiscal year-end on which the total market value of our common equity securities held by non-affiliates is $700 million or more as of June 30); (iii) the date on which we issue more than $1.0 billion of non-convertible debt over a three-year period.
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.
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 become redeemable by us or on any particular date afterwards.
The Series A Preferred Stock represent perpetual equity interests in us, and they 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 have not been 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

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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.
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 and 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 that 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

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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 below. See Note 13 "Commitment and Contingencies" to the audited consolidated financial statements, which are incorporated herein by reference to Part II, Item 8 “Financial Statements and Supplementary Data” of this Form 10-K.

The Company is the subject of the following lawsuits:
John Melville et al v. Spark Energy Inc. and Spark Energy Gas, LLC is a purported class action filed on December 17, 2015 in the United States District Court for the District of New Jersey alleging, among other things, that (i) sales representatives engaged as independent contractors for Spark Energy Gas, LLC engaged in deceptive acts in violation of the New Jersey Consumer Fraud Act, and (ii) Spark Energy Gas, LLC breached its contract with plaintiff, including a breach of the covenant of good faith and fair dealing. On September 5, 2017, the parties reached a confidential settlement in this matter, which the Company expensed and paid in the fourth quarter of 2017.
Halifax-American Energy Company, LLC et al v. Provider Power, LLC, Electricity N.H., LLC, Electricity Maine, LLC, Emile Clavet and Kevin Dean is a lawsuit initially filed on June 12, 2014, in the Rockingham County Superior Court, State of New Hampshire, alleging various claims related to the Provider Companies’ employment of a sales contractor formerly employed with one or more of the plaintiffs, including misappropriation of trade secrets and tortious interference with a contractual relationship. The relief sought included compensatory and punitive damages and attorney's fees. The dispute occurred prior to the Company's acquisition of the Provider Companies. Portions of the original claim proceeded to trial and on January 19, 2016, a jury found in favor of the plaintiffs. Damages totaling approximately $0.6 million and attorneys' fees totaling approximately $0.3 million were awarded to the plaintiffs. On May 4, 2016, following post-verdict motions, the defendants filed an appeal in the State of New Hampshire Supreme Court, appealing, among other things the failure of the trial court to direct a verdict for the defendants, to set aside the verdict, or grant judgment for the defendants, and the trial court's award of certain attorneys' fees. The appellate hearing was held on June 1, 2017. The New Hampshire Supreme Court decided the appeal on February 9, 2018, upholding the jury's verdict and the trial court's rulings in all respects. As of December 31, 2017, the Company has accrued approximately$1.0 million in contingent liabilities related to this litigation. Initial damages and attorneys' fees have been factored into the purchase price for the Provider Companies, and the Company believes it has full indemnity coverage for any actual exposure in this appeal.
Katherine Veilleux and Jennifer Chon, individually and on behalf of all other similarly situated 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, an entity acquired by Spark HoldCo, LLC in mid-2016, enrolled and re-enrolled customers through fraudulent and misleading advertising, promotions, and other communications prior to the acquisition. Plaintiffs further allege that some improper enrollment and re-enrollment practices have continued to the present date. Plaintiffs allege the following claims against all defendants: violation of the Maine Unfair Trade Practices Act, violation of RICO, negligence, negligent misrepresentation, fraudulent misrepresentation, unjust enrichment and breach of contract. Plaintiffs seek unspecified damages for themselves and the purported class, rescission of contracts with Electricity Maine, injunctive relief, restitution, and attorney’s fees. By order dated November 15, 2017, the Court, pursuant to Rule 12(b)(6), dismissed all claims against Spark HoldCo except the claims for violation of the Maine Unfair Trade Practices Act and for unjust enrichment.  Discovery limited to issues relevant to class certification under Rule 23 of the Federal Rules of Civil Procedure has just begun. Spark HoldCo intends to vigorously defend this matter and the allegations asserted therein, including the request to certify a class. Given the early stages of this matter, we cannot predict the outcome or consequences of this case at this time. The Company believes it is fully indemnified for this litigation matter, subject to certain limitations.

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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. On June 23, 2014, the case was 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. The plaintiffs also allege that Respond Power, LLC (i) breached its variable rate contract with Pennsylvania consumers, and the covenant of good faith and fair dealing therein, by charging rates in excess of the monthly rate charged by the consumers’ local utility company; (ii) engaged in deceptive conduct in violation of the Pennsylvania Unfair Trade Practices and Consumer Protection Law; and (iii) engaged in negligent misrepresentation and fraudulent concealment in connection with purported promises of savings. 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. The United States Court of Appeals for the Third Circuit vacated the district court’s denial of class certification and remanded the matter to the district court for further proceedings. The district court ordered briefing on defendant’s motion to dismiss. Respond Power LLC filed a motion to dismiss the plaintiffs’ declaratory judgment and breach of contract claims (the class claims) on June 30, 2017. The motion is fully briefed and submitted, and the parties are awaiting a decision from the Court. The Company currently cannot predict the outcome or consequences of this case at this time. The Company believes it is fully indemnified for this litigation matter, subject to certain limitations.
Jurich v. Verde Energy USA, Inc., is a purported 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 and (ii) breach of the covenant of good faith and fair dealing. Plaintiffs are seeking unspecified actual and punitive damages for the purported class and injunctive relief. The parties have exchanged initial discovery. Plaintiffs’ motion for class certification was briefed and the Verde Companies filed its opposition to plaintiffs’ motion for class certification on October 17, 2017. On December 6, 2017, the Court granted the plaintiffs’ class certification motion.  However, the Court opted not to send out class notices, and instead directed the parties to submit briefing on legal issues that could result in a modification or decertification of the class. The parties have proposed to the Court that initial briefing on such motions would be due March 16, 2018. 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. Given the early stage of this matter, we cannot predict the outcome or consequences of this case at this time. The Company believes it is fully indemnified for this litigation matter by the original owners of the Verde Companies, subject to certain limitations.
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 by placing marketing calls using an automatic telephone dialing system 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 statutory damages for the purported class and injunctive relief prohibiting Verde Companies' alleged conduct. Discovery on the claims of the named plaintiffs closed on November 10, 2017, and dispositive motions on the named plaintiffs’ claims was filed on November 24, 2017. Plaintiffs’ response to dispositive motions’ pleadings was filed on December 22, 2017 and Verde Companies’ reply briefs were filed on January 5, 2018. To date, no hearing has been set on these motions. As part of an agreement in connection with the acquisition of the Verde Companies, the original owners of the Verde Companies is handling this matter. Given the early stages of this matter, we cannot predict the outcome or consequences of this case at this time. The Company believes it is fully indemnified for this litigation matter by the original owners of the Verde Companies, subject to certain limitations.
Coleman v. Verde Energy USA Illinois, LLC is a purported class action filed on January 23, 2017 in the United States District Court for the Southern District of Illinois alleging that the Verde Companies violated the Telephone Consumer Protection Act by placing marketing calls using an automatic telephone dialing system or a prerecorded

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voice to the purported class members’ cellular phones without prior express consent. The parties have reached a confidential settlement in this matter that was paid in the fourth quarter of 2017.
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. (Spark), has filed a lawsuit asserting claims of fraudulent inducement against NG&E, breach of contract against NG&E and the Company, and tortious interference with contract against the Company 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. The lawsuit was filed on October 10, 2017 in the United States District Court for the Southern District of New York, and after the Company and NG&E filed a motion to dismiss, Horowitz filed an Amended Complaint, asserting the same four claims. The Company and NG&E filed a motion to dismiss the fraud and tortious interference claims on January 15, 2018. Briefing on the motion to dismiss concluded on March 1, 2018, and the Court's decision to rule or schedule oral argument is pending as of the date these financial statements are issued. 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.

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 March 7, 2018, the closing price of our stock was $8.85, and 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.” The following table presents the high and low sales prices as reported on the NASDAQ for the periods presented.
 
2017
2016
Quarter Ended
Low
High
Low
High
March 31
$12.25
$16.83
$8.85
$13.81
June 30
$14.18
$23.65
$8.91
$17.82
September 30
$14.50
$21.40
$11.29
$17.35
December 31
$10.70
$15.30
$11.53
$16.23

Dividends

We intend to 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. Below is a summary of dividends paid on our Class A common stock for 2017 and 2016.
 
2017
 
Per Share Amount
Record Date
Payment Date
First Quarter
$0.18125
3/1/2017
3/16/2017
Second Quarter
$0.18125
5/30/2017
6/14/2017
Third Quarter
$0.18125
8/29/2017
9/14/2017
Fourth Quarter
$0.18125
11/29/2017
12/14/2017

 
2016
 
Per Share Amount
Record Date
Payment Date
First Quarter
$0.18125
2/29/2016
3/14/2016
Second Quarter
$0.18125
5/31/2016
6/14/2016
Third Quarter
$0.18125
8/29/2016
9/13/2016
Fourth Quarter
$0.18125
12/1/2016
12/14/2016
 
Please see "Management's Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources —Sources of Liquidity —Senior Credit Facility" for a description of certain terms of our Senior Credit Facility that may impact our ability to pay dividends.

Issuer Purchases of Equity Securities

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Period
Total Number of Class A Common Stock Purchased
Average Price Paid Per Share of Class A Common Stock
Total Number of Shares of Class A Common Stock Purchased as Part of Publicly Announced Program (1)
Approximate Dollar Value of Class A Common Stock That May Yet Be Purchased Under the Program (in thousands) (1)
October 1, 2017 through October 31, 2017
 
 
 
$
48,112

November 1, 2017 through November 30, 2017
 
 
 
$
48,112

December 1, 2017 through December 31, 2017 (2)
10,000

$
12.28

10,000

$
47,989

Total
10,000

$
12.28

10,000

$
47,989


(1) On May 24, 2017, the Company announced that the Board of Directors authorized a share repurchase program of up to $50.0 million of Class A common stock through December 31, 2017. The share repurchase program expired on December 31, 2017.
(2) During December 2017, the Company acquired 10,000 shares of Class A common stock at a weighted-average price of $12.28 for a total purchase price of $0.1 million (including fees, commissions and expenses). The number of shares of Class A common stock purchased reflects trades that were settled in December 2017.

Recent Sales of Unregistered Equity Securities

We have not sold any unregistered equity securities since our IPO 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.

http://api.tenkwizard.com/cgi/image?quest=1&rid=23&ipage=12118593&doc=16


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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, 2017.

This information is derived from our consolidated financial statements and should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Financial Statements and Supplementary Data."

(in thousands, except per share and volumetric data)

Year Ended December 31,

2017

2016

2015
2014
2013
Statement of Operations Data:






 
 
Total Revenues

$
798,055


$
546,697


$
358,153

$
322,876

$
317,090

Operating income

102,420


84,001


29,905

(3,841
)
32,829

Net income

76,281


65,673


25,975

(4,265
)
31,412

Net Income (Loss) Attributable to Non-Controlling Interests

57,427


51,229


22,110

(4,211
)

Net income attributable to Spark Energy, Inc. stockholders

18,854


14,444


3,865

(54
)
31,412

Net income attributable to stockholders of Class A common stock
 
15,816

 
14,444

 
3,865

(54
)
31,412

 
 
 
 
 
 
 
 
 







 
 
Net income (loss) attributable to Spark Energy, Inc. per share of Class A common stock

 




 
 
       Basic

$
1.20


$
1.27


$
0.63

$
(0.01
)
N/A (1)

       Diluted

$
1.19


$
1.11


$
0.53

$
(0.01
)
N/A (1)

 







 
 
Weighted average common shares outstanding








 


       Basic

13,143


11,402


6,129

6,000

N/A (1)

       Diluted

13,346


12,690


6,655

6,000

N/A (1)








 
 
Balance Sheet Data:






 
 
Current assets

$
296,738


$
197,983


$
102,680

$
105,989

$
101,291

Current liabilities

$
151,027


$
184,056


$
84,188

$
92,816

$
73,142

Total assets

$
505,949


$
375,230


$
162,234

$
138,397

$
109,073

Long-term liabilities

$
152,446


$
67,438


$
44,727

$
21,463

$
18

 
 
 
 
 
 
 
 
 
Cash Flow Data:






 
 
Cash flows from operating activities

$
63,912


$
67,793


$
45,931

$
5,874

$
44,480

Cash flows used in investing activities

$
(97,757
)

$
(36,344
)

$
(41,943
)
$
(3,040
)
$
(1,481
)
Cash flows provided by (used in) financing activities

$
44,304


$
(16,963
)

$
(3,873
)
$
(5,664
)
$
(42,369
)







 
 
Other Financial Data:






 
 
Adjusted EBITDA (2)

$
102,884


$
81,892


$
36,869

$
11,324

$
33,533

Retail gross margin (2)

$
224,509


$
182,369


$
113,615

$
76,944

$
81,668

Distributions paid to Class B non-controlling unit holders and dividends paid to Class A common shareholders

$
(43,319
)

$
(43,297
)

$
(20,043
)
$
(3,305
)
$

 
 
 
 
 
 
 
 
 
Other Operating Data:





 
 
 
RCEs (thousands)

1,042


774


415

326

310

Electricity volumes (MWh)

6,755,663


4,170,593


2,075,479

1,526,652

1,829,657

Natural gas volumes (MMBtu)

18,203,684


16,819,713


14,786,681

15,724,708

16,598,751

 
 
 
 
 
 
 
 
 

(1) EPS and other per share data is not meaningful prior to the Company's IPO, effective August 1, 2014, as the Company operated under a sole-member ownership structure.
(2) 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—How We Evaluate Our Operations."


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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 a growing 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, 2017, 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. 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, 2017, 2016 and 2015, approximately 82%, 76% and 64%, respectively, of our retail revenues were derived from the sale of electricity. 

Retail Natural Gas Segment. We purchase natural gas supply through physical and financial transactions with market counterparts and supply natural gas to residential and commercial consumers pursuant to fixed-price and variable-price contracts. For the years ended December 31, 2017, 2016 and 2015, approximately 18%, 24% and 36%, respectively, of our retail revenues were derived from the sale of natural gas. We also identify wholesale natural gas arbitrage opportunities in conjunction with our retail procurement and hedging activities, which we refer to as asset optimization.

Recent Developments

Acquisition of HIKO

On March 1, 2018, we entered into a Membership Interest Purchase Agreement pursuant to which we acquired all of the issued and outstanding membership interests of HIKO Energy, LLC, a New York limited liability company, for a total purchase price of $6.0 million in cash, plus working capital. HIKO Energy, LLC has a total of approximately 29,000 RCEs located in 42 markets in 7 states.

Acquisition of Customers from NG&E

On March 7, 2018, we entered into an asset purchase agreement with NG&E pursuant to which we will acquire approximately 50,000 RCEs from NG&E for a cash purchase price of $250 for each RCE, or approximately $12.5 million in the aggregate. These customers are expected to begin transferring after April 1, 2018 and are located in 24 markets in 8 states. Please see “Item 9B—Other Information—Acquisition of Customers from NG&E” for a more detailed description.

Termination of Master Service Agreement


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On March 7, 2018, we, Retailco Services and NuDevco Retail mutually agreed to terminate the Master Services Agreement, effective April 1, 2018. We believe that Retailco Services was able to recognize cost savings and stabilize operating costs related to the operational support services in 2016 and 2017. Under the terms of the termination agreement, operational support services will be transferred back to the Company, which may allow us to extract further savings by eliminating overhead attributable to managing and accounting for Retailco Services as a stand-alone business. Please see “Item 9B—Other Information—Termination of Master Service Agreement” for a more detailed description.

Series A Preferred Stock Offering

On January 26, 2018, we issued 2,000,000 shares of Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Stock ("Series A Preferred Stock") and received net proceeds from the offering of approximately $48.9 million (net of underwriting discounts, commissions and a structuring fee).

Termination of Verde Earnout

On January 12, 2018, we entered into an Agreement to Terminate Earnout Payments (the “Earnout Termination Agreement”) that terminated our obligation to make any required earnout payments under the agreement for our acquisition of the Verde Companies. Under the Earnout Termination Agreement, we issued a new promissory note to the prior owner of the Verde Companies in the amount of $5.9 million and amended the promissory note entered into at the closing of our acquisition of the Verde Companies to increase the interest rate. Please see “—Liquidity and Capital Resources—Verde Earnout Termination Notes.”

Expansion of Credit Facility

On January 11, 2018 and January 23, 2018, we exercised the accordion feature in the Senior Credit Facility, which when combined with prior exercises in 2017, increased the total commitments under the Senior Credit Facility from $150.0 million to $200.0 million. Please see “—Liquidity and Capital Resources—Senior Credit Facility.”

Residential Customer Equivalents

The following table shows our residential customer equivalents ("RCEs") as of December 31, 2017, 2016 and 2015:

RCEs:
 
 
 
 
 
 
 
December 31,
 
December 31,
 
(In thousands)
2017
2016
% Increase (Decrease)
2016
2015
% Increase (Decrease)
Retail Electricity
868
571
52%
571
257
122%
Retail Natural Gas
174
203
(14)%
203
158
28%
Total Retail
1,042
774
35%
774
415
87%

The following table details our count of RCEs by geographical location as of December 31, 2017:
RCEs by Geographic Location:
 
 
 
 
 
 
(In thousands)
Electricity
 % of Total
Natural Gas
 % of Total
Total
 % of Total
New England
394
46%
32
18%
426
41%
Mid-Atlantic
324
37%
72
42%
396
38%
Midwest
70
8%
45
26%
115
11%
Southwest
80
9%
25
14%
105
10%
Total
868
100%
174
100%
1,042
100%


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The geographical regions noted above include the following states:

New England - Connecticut, Maine, Massachusetts, 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, Nevada, Texas and Florida.

Drivers of Our Business

Customer Growth

Customer growth is a key driver of our operations. Our customer growth strategy includes acquiring customers through acquisitions as well as organically.

Organic Growth

Our organic sales strategies are used 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 the local regulated utility is offering. 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 satisfies our profitability objectives and provides customer value. We develop marketing campaigns using a combination of sales channels, with an emphasis on door-to-door marketing and outbound telemarketing given their flexibility and historical effectiveness. We identify and acquire customers through a variety of additional sales channels, including our inbound customer care call center, online marketing, email, direct mail, affinity programs, direct sales, brokers and consultants. Our marketing team continuously evaluates the effectiveness of each customer acquisition channel and makes adjustments in order to achieve desired growth and profitability targets.

In 2017, we emphasized growing our commercial and industrial (“C&I”) customer base. After significant growth in our C&I customer count in 2017, management is rebalancing our mix of customers in the first part of 2018 to focus on higher margin residential customers.

We believe we can continue to grow organically, however achieving significant organic growth rates has become increasingly more difficult given our size, much of which is attributable to recent acquisitions. Additionally, increasing regulatory pressure on marketing channels such as door-to-door and outbound telemarketing and the ability to manage customer acquisition costs are significant factors in our ability to grow organically.

Acquisitions

We independently acquire companies and portfolios of companies through some combination of cash, borrowings under the Senior Credit Facility, the issuance of common or preferred stock or other financing arrangements with our Founder and his affiliates. Additionally, our Founder formed National Gas & Electric, LLC, an affiliate of the Company ("NG&E"), in 2015 for the purpose of purchasing retail energy companies and retail customer books that could ultimately be resold to us. We currently expect that we would fund any future transaction with NG&E using some combination of cash, subordinated debt, or the issuance of Class A common stock or Class B common stock (and corresponding Spark HoldCo units) to NG&E. However, actual consideration will depend, among other things, on our capital structure and liquidity at the time of any transaction. There is no guarantee that NG&E will continue to offer us acquisition opportunities. Additionally, as we grow and our access to capital and opportunities improves, we may rely less upon NG&E as a source of acquisitions and seek to enter into more transactions directly with third parties. See “Business and Properties—Relationship with our Founder and Majority Shareholder” for further discussion.


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Please see “—Recent Developments—Acquisition of HIKO” and “—Recent Developments—Acquisition of Customers from NG&E” for a description of our recent acquisitions of HIKO Energy, LLC and additional customers from NG&E. For a summary of other historical acquisitions, including those with our Founder and NG&E, please see “Business and Properties—Customer Acquisition and Retention—Acquisitions.”

We are actively monitoring acquisition opportunities that may arise in the domestic acquisition market as smaller retailers face difficulties in managing risk and liquidity issues caused by the recent extreme weather patterns.
Our ability to grow at historic levels 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.

Integration of Acquisitions

Effective integration of our acquisitions is a key driver of our business. We integrated both CenStar and Oasis and began recognizing synergies in 2015. We were able to integrate the Provider Companies and begin recognizing synergies in 2016. The integration of the Perigee acquisition is progressing well and synergies are being recognized as of December 31, 2017. As the Major Energy Companies Earnout extends over multiple years, the Company is not able to achieve full synergies at this time. We were able to terminate the earnout related to our acquisition of the Verde Companies, allowing us to begin integrating the Verde Companies in early 2018. See “—Recent Developments” above. For a summary of historical acquisitions, please see “Business and Properties—Customer Acquisition and Retention—Acquisitions.”

RCE Activity

The following table shows our RCE activity during the years ended December 31, 2017, 2016 and 2015.
(In thousands)
Retail Electricity
Retail Natural Gas
Total
% Annual Increase (Decrease)
December 31, 2014
157
169
326

   Additions (1)
208
100
308
 
   Attrition
(108)
(111)
(219)
 
December 31, 2015
257
158
415
27%
   Additions (2)
550
131
681
 
   Attrition
(236)
(86)
(322)
 
December 31, 2016
571
203
774
87%
   Additions (3)
659
61
720
 
   Attrition
(362)
(90)
(452)
 
December 31, 2017
868
174
1,042
35%

(1) Includes 40,000 RCEs from the acquisition of Oasis and 65,000 RCEs from the acquisition of CenStar.
(2) Includes 121,000 RCEs from the acquisition of Provider Companies and 220,000 RCEs from the acquisition of Major Energy Companies.
(3) Includes approximately 17,000 RCEs from the acquisition of Perigee and 145,000 RCEs from the acquisition of the Verde Companies.

Our 35% net RCE growth in 2017 reflects our acquisition of Verde Companies and Perigee, which added approximately 162,000 RCEs, or 21% net growth. The remaining 14% net RCE growth in 2017 was the result of organic additions and customer portfolio acquisitions.

Our 87% net RCE growth in 2016 reflects our acquisitions of Major and Provider, which added approximately 341,000 RCEs, or 82% net growth. The remaining 5% net RCE growth in 2016 was the result of organic additions.


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Our 27% net RCE growth in 2015 reflects our acquisitions of CenStar and Oasis, which resulted in an increase in the overall size of individual customers. This growth was partially offset by the slowing of organic additions as we shifted our focus to acquisitions and renegotiated our mass market vendor commission structure in the third quarter of 2015, which correlated commission payments with customer value. These efforts had the effect of resetting our vendor relationships, which in turn slowed organic growth as vendors adapted to the new structure.

Customer Acquisition Costs Incurred
 

(In thousands)
2017
2016
2015
Customer Acquisition Costs Incurred
$
25,874

$
24,934

$
19,869


Management of customer acquisition costs is a key component to our profitability. Customer acquisition costs are spending for organic customer acquisitions and does not include customer acquisitions through acquisitions of businesses or portfolios of customer contracts, which are recorded as customer relationships.

We attempt to maintain a disciplined approach to recovery of our customer acquisition costs within defined periods. We capitalize and amortize our customer acquisition costs over a two year period, which is based on 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 spending.

Customer acquisition costs incurred for the year ended December 31, 2017 was approximately $25.9 million, inclusive of costs attributable to Perigee and the Verde Companies incurred subsequent to their respective acquisition dates.

Customer acquisition costs incurred for the year ended December 31, 2016 was approximately $24.9 million, inclusive of costs attributable to the Provider Companies and Major Energy Companies incurred subsequent to their respective acquisition dates. During the first half of 2016, we reduced the amount we spent on organic customer acquisition costs in order to maintain, rather than grow, our current level of RCEs, and shifted our resources to acquiring companies and entire books of customers. During the second half of 2016, we increased our spending on organic customer acquisitions as we refocused on organic growth.

Our customer acquisition spending in the second half of 2015 slowed, resulting in customer acquisition costs of $19.9 million in 2015 as we shifted our focus to acquisitions and due to changes to our residential vendor commission payment structure to better align them with lifetime customer value.

Our Ability to Manage Customer Attrition
 

Attrition on RCE basis
 
Year Ended
Quarter Ended
 
December 31
December 31
September 30
June 30
March 31
2015
5.1%
4.5%
5.0%
5.2%
5.7%
2016
4.3%
4.8%
3.8%
4.1%
4.4%
2017
4.3%
4.9%
4.2%
4.1%
3.8%

Customer attrition is primarily due to: (i) customer initiated switches; (ii) residential moves and (iii) disconnection for customer payment defaults.

Customer attrition during the year ended December 31, 2017 was in line with the previous year as we continued our focus on the acquisition of higher lifetime value customers. We also continued our customer win-back efforts, and

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more aggressively pursued proactive renewals and other customer relationship strategies to maintain a low level of customer attrition.

Customer Credit Risk
 
Year Ended December 31
 
2017
2016
2015
Total Non-POR Bad Debt as Percent of Revenue
2.5
%
0.6
%
5.0
%

During the year ended December 31, 2017, we experienced increased bad debt expense due to Hurricane Harvey.

An increased focus on collection efforts and timely billing along with tighter credit requirements for new enrollments in non-POR markets have led to a reduction in the bad debt expense in 2016 as compared to 2015. We have also been able to collect on debt that we had previously written off, which further reduced our bad debt expense during 2016.

Bad debt expense as a percentage of non-POR market retail revenues remained high in 2015 due to the negative impact of higher attrition in the Midwest natural gas markets and continued disconnections for non-payment from our Southern California portfolio, where we stopped selling in January 2015. In early 2016, we introduced upfront credit screening to many of our natural gas sales campaigns in order to proactively identify potential at-risk customers.

For the years ended December 31, 2017, 2016 and 2015, approximately 66%, 67% and 56%, respectively, of our retail revenues were derived from territories in which substantially all of our credit risk was directly linked to local regulated utility companies. As of December 31, 2017, 2016 and 2015, respectively, all of these local regulated utility companies had investment grade ratings. During the same periods, we paid these local regulated utilities a weighted average discount of approximately 1.1%, 1.3% and 1.4%, respectively, of total revenues for customer credit risk protection, respectively.

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 because of our current substantial concentration and focus on growth in the residential customer segment in which energy usage is highly sensitive to weather conditions that impact heating and cooling demand. In the first three quarters of 2017, we experienced milder than anticipated weather conditions, which negatively impacted overall customer usage, but allowed us to optimize our costs of revenues as commodity prices fell. In the third quarter of 2017, Hurricane Harvey caused historic flooding, extensive damage and widespread power outages across the Gulf Coast of Texas. Although we did not suffer physical damage to our Houston offices, the hurricane negatively impacted our ability to serve our customers and deliver electricity in this region during the hurricane and for the following weeks. We recorded losses of approximately $0.7 million for the year ended December 31, 2017, directly attributable to Hurricane Harvey, primarily related to bad debt expense.

In late 2017 and early 2018, the Northeastern and Great Lake regions experienced extreme weather patterns. We expect excessive customer usage from this cold weather may negatively impact our results of operations.

In the first half of 2016, we experienced milder than anticipated weather conditions, which negatively impacted overall customer usage, but allowed us to optimize our costs of revenues as commodity prices fell. In the second half of 2016, we experienced marginally warmer than normal weather conditions.


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In the early part of 2015, colder than anticipated weather increased volumes and thus positively impacted our first quarter earnings. Warmer than normal weather in the fourth quarter of 2015 in the Northeast negatively impacted natural gas volumes, while we also optimized our costs of revenues as commodity prices fell.

Asset Optimization

Our natural gas business includes opportunistic transactions in the natural gas wholesale marketplace in conjunction with our retail procurement and hedging activities. Asset optimization opportunities primarily arise during the winter heating season when demand for natural gas is the highest.  As such, the majority of our asset optimization profits are made in the winter. Given the opportunistic nature of these activities we experience variability in our earnings from our asset optimization activities from year to year. As these activities are accounted for using mark-to-market accounting, the timing of our revenue recognition often differs from the actual cash settlement.

During each of the years ended December 31, 2017 and 2016, we were obligated to pay demand charges of approximately $2.6 million under certain long-term legacy transportation assets that our predecessor entity acquired prior to 2013. Although these demand payments will decrease over time, a portion of the related capacity agreements extend through 2028. Net asset optimization results were a loss of $0.7 million, a loss of $0.6 million and a gain of $1.5 million for the year ended December 31, 2017, 2016 and 2015, respectively.


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Factors Affecting Comparability of Historical Financial Results

Tax Receivable Agreement. We entered into the Tax Receivable Agreement between us and Spark Holdco, NuDevco Retail Holdings and NuDevco Retail concurrently with the IPO, which provides for the payment by us to Retailco, LLC (as successor to NuDevco Retail Holdings) and NuDevco Retail 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 certain events. On December 22, 2017, the President signed the Tax Cuts and Jobs Act (“U.S. Tax Reform”), which enacts a wide range of changes to the U.S. Corporate income tax system, including a reduction in the U.S. corporate tax rate to 21% effective in 2018. The revised corporate income tax rate reduces the amount of net cash savings to be realized in future periods. Therefore, we have reduced the Tax Receivable Agreement liability ("TRA liability") as of December 31, 2017 by $22.3 million to reflect the effect of the U.S. Tax Reform and recorded this adjustment through Other Income. In addition, payments we make under the Tax Receivable Agreement are increased by any interest accrued from the due date (without extensions) of the corresponding tax return. We have recorded 85% of the estimated tax benefit as an increase to amounts payable under the Tax Receivable Agreement as a liability. We retain the benefit of the remaining 15% of these tax savings. As a result of new federal tax laws going into effect in 2018, the Company has re-valued its deferred tax asset and deferred tax liability relating to the Tax Receivable Agreement on its balance sheet as of December 31, 2017. The effect of these downward adjustments is a net increase in income tax expense for the year ended December 31, 2017. See Note 12 "Income Taxes" for further discussion.

Executive Compensation Programs. Periodically the Company grants restricted stock units to our officers, employees, non-employee directors and certain employees of our affiliates who perform services for the Company. The restricted stock unit awards vest over approximately one year for non-employee directors and ratably over approximately three or four years for officers, employees and employees of affiliates, with the initial vesting date occurring in May of the subsequent year, and include tandem dividend equivalent rights that will vest upon the same schedule as the underlying restricted stock unit.

Financing. We are party to the Senior Credit Facility. Historical borrowings under the Senior Credit Facility may not provide an accurate indication of what we need to operate our natural gas and electricity business. For a description of our current Senior Credit Facility, please see "—Liquidity and Capital Resources—Sources of Liquidity."

How We Evaluate Our Operations
 
Year Ended December 31,
(in thousands)
2017
 
2016
 
2015
Adjusted EBITDA
$
102,884

 
$
81,892

 
$
36,869

Retail Gross Margin
$
224,509

 
$
182,369

 
$
113,615


Adjusted EBITDA. We define “Adjusted EBITDA” as EBITDA less (i) customer acquisition costs incurred in the current period, (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 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 year in which they are incurred, even though we capitalize such costs and amortize them over two years in accordance with our accounting policies. The deduction of current period customer acquisition costs is consistent with how we manage our business, but the comparability of Adjusted EBITDA between periods may be affected by varying levels of customer acquisition costs. For example, our Adjusted EBITDA is lower in periods of organic customer growth reflecting larger customer acquisition spending.


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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 derivative instruments. We also deduct non-cash compensation expense as a result of restricted stock units that are issued under our long-term incentive plan.

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.

Retail Gross Margin. We define retail gross margin as operating income 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-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 business by removing the impacts of our asset optimization activities and net non-cash income (loss) impact of our economic hedging activities. 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, 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 measures most directly comparable to Adjusted EBITDA are net income and net cash provided by operating activities. The GAAP measure most directly comparable to Retail Gross Margin is operating income (loss). Our non-GAAP financial measures of Adjusted EBITDA and Retail Gross Margin should not be considered as alternatives to net income (loss), net cash provided by operating activities, or operating income (loss). Adjusted EBITDA and Retail Gross Margin are not presentations made in accordance with GAAP and have important 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 income (loss), net cash provided by operating activities, and operating income (loss), 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.

The following table presents a reconciliation of Adjusted EBITDA to net income for each of the periods indicated.

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Table of Contents

  
Year Ended December 31,
(in thousands)
2017
 
2016
 
2015
Reconciliation of Adjusted EBITDA to Net Income:
 
 
 
 
 
Net income
$
76,281


$
65,673

 
$
25,975

Depreciation and amortization
42,341


32,788

 
25,378

Interest expense
11,134


8,859

 
2,280

Income tax expense
37,528


10,426

 
1,974

EBITDA (1) 
167,284


117,746

 
55,607

Less:



 

Net, Gains (losses) on derivative instruments
5,008


22,407

 
(18,497
)
Net, Cash settlements on derivative instruments
16,309


(2,146
)
 
20,547

Customer acquisition costs
25,874


24,934

 
19,869

       Plus:





 


       Non-cash compensation expense
5,058


5,242

 
3,181

       Contract termination charge related to Major Energy
Companies change of control


4,099

 

      Change in Tax Receivable Agreement liability (1)
(22,267
)


 

Adjusted EBITDA (2)
$
102,884


$
81,892

 
$
36,869


(1) Represents the change in the value of the Tax Receivable Agreement liability due to U.S. Tax Reform. See discussion in Note 12 "Income Taxes."
(2) Includes $9.6 million and $1.1 million related to the change in fair value as the result of the revaluation of the Major Earnout liability at December 31, 2017 and 2016. Refer to Note 9 "Fair Value Measurements" for further discussion of the revaluation of the Major Earnout.


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The following table presents a reconciliation of Adjusted EBITDA to net cash provided by (used in) operating activities for each of the periods indicated.
  
Year Ended December 31,
(in thousands)
2017
 
2016
 
2015
Reconciliation of Adjusted EBITDA to net cash provided by operating activities:
 
 
 
 
 
Net cash provided by operating activities
$
63,912


$
67,793

 
$
45,931

Amortization of deferred financing costs
(1,035
)

(668
)
 
(412
)
Allowance for doubtful accounts and bad debt expense
(6,550
)

(1,261
)
 
(7,908
)
Interest expense
11,134


8,859

 
2,280

Income tax expense
37,528


10,426

 
1,974

Change in Tax Receivable Agreement liability (1)
(22,267
)


 

Changes in operating working capital



 

Accounts receivable, prepaids, current assets
31,905


12,135

 
(18,820
)
Inventory
718


542

 
4,544

Accounts payable and accrued liabilities
(13,672
)

(17,653
)
 
13,008

Other
1,211


1,719

 
(3,728
)
Adjusted EBITDA
$
102,884


$
81,892

 
$
36,869

Cash Flow Data:
 
 
 
 
 
Cash flows provided by operating activity
$
63,912


$
67,793

 
$
45,931

Cash flows used in investing activity
$
(97,757
)

$
(36,344
)
 
$
(41,943
)
Cash flows provided by (used in) financing activity
$
44,304


$
(16,963
)
 
$
(3,873
)

(1) Represents the change in the value of the Tax Receivable Agreement liability due to U.S. Tax Reform. See discussion in Note 12 "Income Taxes."

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)
2017
 
2016
 
2015
Reconciliation of Retail Gross Margin to Operating Income (Loss):
 
 
 
 
 
Operating income
$
102,420


$
84,001

 
$
29,905

Depreciation and amortization
42,341


32,788

 
25,378

General and administrative
101,127


84,964

 
61,682

Less:



 

Net asset optimization (expenses) revenues
(717
)

(586
)
 
1,494

Net, Gains (losses) on non-trading derivative instruments
5,588


22,254

 
(18,423
)
Net, Cash settlements on non-trading derivative instruments
16,508


(2,284
)
 
20,279

Retail Gross Margin
$
224,509


$
182,369

 
$
113,615

Retail Gross Margin - Retail Electricity Segment
$
158,468


$
118,136

 
$
60,255

Retail Gross Margin - Retail Natural Gas Segment
$
66,041


$
64,233

 
$
53,360


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Consolidated Results of Operations

Year Ended December 31, 2017 Compared to Year Ended December 31, 2016
In Thousands
Year Ended December 31,
 


2017
 
2016
 
Change
Revenues:


 

 

Retail revenues
$
798,772

 
$
547,283

 
$
251,489

Net asset optimization revenues
(717
)
 
(586
)
 
(131
)
Total Revenues
798,055

 
546,697

 
251,358

Operating Expenses:


 


 


Retail cost of revenues
552,167

 
344,944

 
207,223

General and administrative
101,127

 
84,964

 
16,163

Depreciation and amortization
42,341

 
32,788

 
9,553

Total Operating Expenses
695,635

 
462,696

 
232,939

Operating income
102,420

 
84,001

 
18,419

Other (expense)/income:


 


 


Interest expense
(11,134
)
 
(8,859
)
 
(2,275
)
Change in Tax Receivable Agreement liability (1)
22,267



 
22,267

Interest and other income
256

 
957

 
(701
)
Total other (expenses)/income
11,389

 
(7,902
)
 
19,291

Income before income tax expense
113,809

 
76,099

 
37,710

Income tax expense
37,528

 
10,426

 
27,102

Net income
$
76,281

 
$
65,673

 
$
10,608

Adjusted EBITDA (2)
$
102,884

 
$
81,892

 
$
20,992

Retail Gross Margin (2)
224,509

 
182,369

 
42,140

Customer Acquisition Costs
25,874

 
24,934

 
940

RCE Attrition
4.3
%
 
4.3
%
 

Distributions paid to Class B non-controlling unit holders and dividends paid to Class A common shareholders
$
(43,319
)
 
$
(43,297
)
 
$
(22
)

(1) Represents the change in the value of the Tax Receivable Agreement liability due to U.S. Tax Reform. See discussion in Note 12 "Income Taxes."
(2) Adjusted EBITDA and Retail Gross Margin are non-GAAP financial measures. See “How We Evaluate Our Operations” 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, 2017 were approximately $798.1 million, an increase of 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, and the acquisition of the Verde Companies, partially offset by decreased electricity pricing.
Change in electricity volumes sold
$
258.6

Change in natural gas volumes sold
10.7

Change in electricity unit revenue per MWh
(18.2
)
Change in natural gas unit revenue per MMBtu
0.4

Change in net asset optimization revenue (expense)
(0.1
)
Change in total revenues
$
251.4



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Retail Cost of Revenues. Total retail cost of revenues for the year ended December 31, 2017 was approximately $552.2 million, an increase of 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.
Change in electricity volumes sold
$
185.4

Change in natural gas volumes sold
5.4

Change in electricity unit cost per MWh
14.6

Change in natural gas unit cost per MMBtu
4.0

Change in value of retail derivative portfolio
(2.1
)
Change in retail cost of revenues
$
207.3


General and Administrative Expense. General and administrative expense for the year ended December 31, 2017 was approximately $101.1 million, an increase of 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 cannot 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, 2017 was approximately $42.3 million, an increase of 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, 2017 was approximately $25.9 million, an increase of 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 of the Verde Companies.

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Year Ended December 31, 2016 Compared to Year Ended December 31, 2015
In Thousands
Year Ended December 31,
 
 
 
2016
 
2015
 
Change
Revenues:
 
 
 
 
 
Retail revenues
$
547,283

 
$
356,659

 
$
190,624

Net asset optimization revenues
(586
)
 
1,494

 
(2,080
)
Total Revenues
546,697

 
358,153

 
188,544

Operating Expenses:


 
 
 
 
Retail cost of revenues
344,944

 
241,188

 
103,756

General and administrative
84,964

 
61,682

 
23,282

Depreciation and amortization
32,788

 
25,378

 
7,410

Total Operating Expenses
462,696

 
328,248

 
134,448

Operating income
84,001

 
29,905

 
54,096

Other (expense)/income:


 
 
 
 
Interest expense
(8,859
)
 
(2,280
)
 
(6,579
)
Interest and other income
957

 
324

 
633

Total other (expenses)/income
(7,902
)
 
(1,956
)
 
(5,946
)
Income before income tax expense
76,099

 
27,949

 
48,150

Income tax expense
10,426

 
1,974

 
8,452

Net income
$
65,673

 
$
25,975

 
$
39,698

Adjusted EBITDA (1)
$
81,892

 
$
36,869

 
$
45,023

Retail Gross Margin (1)
$
182,369

 
$
113,615

 
$
68,754

Customer Acquisition Costs
$
24,934

 
$
19,869

 
$
5,065

RCE Attrition
4.3
%
 
5.1
%
 
(0.8
)%
Distributions paid to Class B non-controlling unit holders and dividends paid to Class A common shareholders
$
(43,297
)
 
$
(20,043
)
 
$
(23,254
)
(1) Adjusted EBITDA and Retail Gross Margin are non-GAAP financial measures. See “How We Evaluate Our Operations” 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, 2016 were approximately $546.7 million, an increase of approximately $188.5 million, or 53%, from approximately $358.2 million for the year ended December 31, 2015. This increase was primarily due to an increase in electricity and natural gas volumes driven by acquisitions of the Provider Companies and Major Energy Companies, partially offset by decreased electricity pricing and natural gas pricing.
Change in electricity volumes sold
$
231.7

Change in natural gas volumes sold
17.5

Change in electricity unit revenue per MWh
(44
)
Change in natural gas unit revenue per MMBtu
(14.6
)
Change in net asset optimization revenue (expense)
(2.1
)
Change in total revenues
$
188.5


Retail Cost of Revenues. Total retail cost of revenues for the year ended December 31, 2016 was approximately $344.9 million, an increase of approximately $103.7 million, or 43%, from approximately $241.2 million for the year ended December 31, 2015. This increase was primarily due to additional volumes driven by the acquisitions of the Provider Companies and Major Energy Companies, partially offset by lower electricity and natural gas supply costs and decrease in the value of our retail derivative portfolio.

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Change in electricity volumes sold
$
170.8

Change in natural gas volumes sold
10.1

Change in electricity unit cost per MWh
(41.0
)
Change in natural gas unit cost per MMBtu
(18.1
)
Change in value of retail derivative portfolio
(18.1
)
Change in retail cost of revenues
$
103.7


General and Administrative Expense. General and administrative expense for the year ended December 31, 2016 was approximately $85.0 million, an increase of approximately $23.3 million or 38%, as compared to $61.7 million for the year ended December 31, 2015. This increase was primarily due to increased billing and other variable costs associated with increased RCEs, including those added as a result of the acquisitions of Provider Companies and Major Energy Companies, increased stock-based compensation associated with higher stock prices and additional equity awards, and additional litigation expense. This increase was partially offset by cost reductions from the Master Service Agreement with Retailco Services and lower bad debt expense as we had better than anticipated collections as a result of new collection initiatives, and as the impact of attrition in the Southern California market was limited to 2015.

Depreciation and Amortization Expense. Depreciation and amortization expense for the year ended December 31, 2016 was approximately $32.8 million, an increase of approximately $7.4 million, or 29%, from approximately $25.4 million for the year ended December 31, 2015. This increase was primarily due to the increased amortization expense associated with customer intangibles from the acquisitions of Provider Companies and Major Energy Companies.

Customer Acquisition Cost. Customer acquisition cost for the year ended December 31, 2016 was approximately $24.9 million, an increase of approximately $5.0 million, or 25% from approximately $19.9 million for the year ended December 31, 2015. This increase was primarily due to customer acquisition costs of the Major Energy Companies of $7.0 million. The increase was partially offset by decreased organic sales in the first half of 2016 as we shifted our focus to growth through acquisitions.


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Table of Contents

Operating Segment Results 
 
Year Ended December 31,
  
2017

2016
 
2015
 
(in thousands, except volume and per unit operating data)
Retail Electricity Segment
 


 
 
Total Revenues
$
657,561


$
417,229

 
$
229,490

Retail Cost of Revenues
477,012


286,795

 
170,684

Less: Net Asset Optimization Revenues
(5
)


 

Less: Net Gains (Losses) on non-trading derivatives, net of cash settlements
22,086


12,298

 
(1,449
)
Retail Gross Margin (1) —Electricity
$
158,468


$
118,136

 
$
60,255

Volumes—Electricity (MWhs)
6,755,663


4,170,593

 
2,075,479

Retail Gross Margin (2) —Electricity per MWh
$
23.46


$
28.33

 
$
29.03

 
 
 
 
 
 
Retail Natural Gas Segment



 
 
Total Revenues
$
140,494


$
129,468

 
$
128,663

Retail Cost of Revenues
75,155


58,149

 
70,504

Less: Net Asset Optimization Revenues
(712
)

(586
)
 
1,494

Less: Net Gains (Losses) on non-trading derivatives, net of cash settlements
10


7,672

 
3,305

Retail Gross Margin (1) —Gas
$
66,041


$
64,233

 
$
53,360

Volumes—Gas (MMBtus)
18,203,684


16,819,713

 
14,786,681

Retail Gross Margin (2) —Gas per MMBtu
$
3.63


$
3.82

 
$
3.61


(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 “—How We Evaluate Our Operations” for a reconciliation of Adjusted EBITDA and Retail Gross Margin to their 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.

Year Ended December 31, 2017 Compared to the Year Ended December 31, 2016
Retail Electricity Segment
Total revenues for the Retail Electricity Segment for the year ended December 31, 2017 were approximately $657.6 million, an increase of 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, 2017 was approximately $477.0 million, an increase of 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.

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Retail gross margin for the Retail Electricity Segment for the year ended December 31, 2017 was approximately $158.5 million, an increase of approximately $40.4 million, or 34%, as compared to $118.1 million for the year ended December 31, 2016 as indicated in the table below (in millions).

Change in volumes sold
$
73.2

Change in unit margin per MWh
(32.8
)
Change in retail electricity segment retail gross margin
$
40.4

Unit margins were negatively impacted as a result of the higher volumes from our commercial customers.
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, 2017 were approximately $140.5 million, an increase of approximately $11.0 million, or 9%, from approximately $129.5 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, 2017 were approximately $75.2 million, an increase of 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.
Retail gross margin for the Retail Natural Gas Segment for the year ended December 31, 2017 was approximately $66.0 million, an increase of 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).

Change in volumes sold
$
5.3

Change in unit margin per MMBtu
(3.5
)
Change in retail natural gas segment retail gross margin
$
1.8

Unit margins were negatively impacted as a result of increase in higher volume commercial customers.
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.
Year Ended December 31, 2016 Compared to the Year Ended December 31, 2015
Retail Electricity Segment
Retail revenues for the Retail Electricity Segment for the year ended December 31, 2016 was approximately $417.2 million, an increase of approximately $187.7 million, or 82%, from approximately $229.5 million for the year ended December 31, 2015. This increase was primarily due to an increase in volume from the acquisitions of the Major Energy Companies and the Provider Companies and the addition of several higher volume commercial

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customers in the East, which resulted in an increase in revenues of $231.7 million. This increase was partially offset by a decrease in electricity pricing, driven by the lower commodity pricing environment from milder than anticipated weather, which resulted in a decrease of $44.0 million.
Retail cost of revenues for the Retail Electricity Segment for the year ended December 31, 2016 was approximately $286.8 million, an increase of approximately $116.1 million, or 68%, from approximately $170.7 million for the year ended December 31, 2015. This increase was primarily due to an increase in volume as a result of the acquisitions of the Major Energy Companies and the Provider Companies, as well as organic growth in the East, resulting in an increase of $170.8 million. This increase was partially offset by a decrease of $13.7 million due to a change in the value of our retail derivative portfolio used for hedging and decreased commodity prices, resulting in a decrease in retail cost of revenues of $41.0 million.
Retail gross margin for the Retail Electricity Segment for the year ended December 31, 2016 was approximately $118.1 million, an increase of approximately $57.8 million, or 96%, as compared to $60.3 million for the year ended December 31, 2015 as indicated in the table below (in millions).

Change in volumes sold
$
60.8

Change in unit margin per MWh
(3.0
)
Change in retail electricity segment retail gross margin
$
57.8

Gross margins were positively impacted by an increase in volume as a result of the acquisitions of the Major Energy Companies and the Provider Companies.
The volumes of electricity sold increased from 2,075,479 MWh for the year ended December 31, 2015 to 4,170,593 MWh for the year ended December 31, 2016. This increase was primarily due to addition of customers through the acquisitions of Major Energy Companies and Provider Companies and organic growth in the East.

Retail Natural Gas Segment
Total revenues for the Retail Natural Gas Segment for the year ended December 31, 2016 were approximately $129.5 million, an increase of approximately $0.8 million, or 1%, from approximately $128.7 million for the year ended December 31, 2015. This increase was primarily attributable to an increase in customer sales volumes resulting from the acquisition of Major Energy Companies, which increased total revenues by $17.5 million. This increase was largely offset by lower rates driven by the lower commodity pricing environment, which resulted in a decrease in total revenues of $14.6 million, and a decrease of $2.1 million in net optimization revenues.
Retail cost of revenues for the Retail Natural Gas Segment for the year ended December 31, 2016 were approximately $58.1 million, a decrease of approximately $12.4 million, or 18%, from approximately $70.5 million for the year ended December 31, 2015. This decrease was due to decreased supply costs, which resulted in a decrease of $18.1 million, and a decrease of $4.4 million in the value of our retail derivative portfolio used for hedging. These decreases were partially offset by an increase of $10.1 million related to increased volume resulting from the acquisition of the Major Energy Companies.
Retail gross margin for the Retail Natural Gas Segment for the year ended December 31, 2016 was approximately $64.2 million, an increase of approximately $10.8 million, or 20% from approximately $53.4 million for the year ended December 31, 2015, as indicated in the table below (in millions).

Change in volumes sold
$
7.3

Change in unit margin per MMBtu
3.5

Change in retail natural gas segment retail gross margin
$
10.8