2019
Annual Report
Dear Fellow Shareholders
As we move into 2020, we are dealing with the unprecedented challenges of the
COVID-19 pandemic. We are continuing to optimize our operations and conserve
cash to be deployed in opportunistic transactions and core operations. Our efforts
are focused on delivering sustainable financial results despite the effects of the
pandemic. On behalf of everyone at Spark Energy, I want to extend my thanks to our
customers, suppliers, and investors for their continued commitment to Spark Energy.
We appreciate you, and we thank you for your partnership.
Sincerely,
W. Keith Maxwell
Chairman of the Board
Interim President and CEO
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the fiscal year ended December 31, 2019.
OR
For the transition period from to
Commission File Number: 001-36559
Spark Energy, Inc.
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of
incorporation or organization)
12140 Wickchester Ln, Suite 100
Houston, Texas 77079
(Address and zip code of principal
executive offices)
46-5453215
(I.R.S. Employer
Identification No.)
(713) 600-2600
(Registrant’s telephone number, including
area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Trading Symbols
Name of exchange on which
registered
Class A common stock, par value
$0.01 per share
8.75% Series A Fixed-to-Floating Rate
Cumulative Redeemable Perpetual
Preferred Stock, par value $0.01 per share
SPKE
The NASDAQ Global Select Market
SPKEP
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
No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.
Yes
No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such
reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes
No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted
pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that
the registrant was required to submit such files).
Yes
No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller
reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller
reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer
Non-accelerated filer
Smaller reporting company
Emerging Growth Company
Accelerated filer
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.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
Yes
No
The aggregate market value of common stock held by non-affiliates of the registrant on June 28, 2019, the last business day
of the registrant's most recently completed second fiscal quarter, based on the closing price on that date of $11.19, was approximately
$128 million. The registrant, solely for the purpose of this required presentation, deemed its Board of Directors and Executive
Officers to be affiliates, and deducted their stockholdings in determining the aggregate market value.
There were 14,379,553 shares of Class A common stock, 20,800,000 shares of Class B common stock and 3,670,144 shares
of Series A Preferred Stock outstanding as of March 3, 2020.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant's definitive Proxy Statement in connection with the 2020 Annual Meeting of Stockholders are incorporated
by reference into Part III of this Form 10-K.
Table of Contents
Items 1 & 2.
Item 1A.
Item 1B.
Item 3.
Item 4.
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
Item 15.
Item 16.
Business and Properties
Risk Factors
Unresolved Staff Comments
Legal Proceedings
Mine Safety Disclosures
PART I
PART II
Market for Registrant’s Common Equity, Related Stockholder
Matters and Issuer Purchases of Equity Securities
Stock Performance Graph
Selected Financial Data
Management’s Discussion and Analysis of Financial Condition and
Results of Operations
Overview
Drivers of Our Business
Non-GAAP Performance Measures
Consolidated Results of Operations
Operating Segment Results
Liquidity and Capital Resources
Cash Flows
Summary of Contractual Obligations
Off-Balance Sheet Arrangements
Related Party Transactions
Critical Accounting Policies and Estimates
Contingencies
Quantitative and Qualitative Disclosures About Market Risk
Financial Statements and Supplementary Data
Index to Consolidated Financial Statements
Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
Controls and Procedures
Other Information
PART III
Directors, Executive Officers and Corporate Governance
Executive Compensation
Security Ownership of Certain Beneficial Owners and Management
and Related Stockholder Matters
Certain Relationships and Related Transactions, and Director
Independence
Principal Accounting Fees and Services
PART IV
Exhibits, Financial Statement Schedules
Form 10-K Summary
SIGNATURES
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Cautionary Note Regarding Forward Looking Statements
This Annual Report on Form 10-K (this “Annual Report”) contains forward-looking statements that are subject to a
number of risks and uncertainties, many of which are beyond our control. These forward-looking statements within
the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”) and Section 21E of the
Securities Exchange Act of 1934, as amended (the “Exchange Act”) can be identified by the use of forward-looking
terminology including “may,” “should,” “likely,” “will,” “believe,” “expect,” “anticipate,” “estimate,” “continue,”
“plan,” “intend,” “project,” or other similar words. All statements, other than statements of historical fact included
in this Annual Report, regarding strategy, future operations, financial position, estimated revenues and losses,
projected costs, prospects, plans, objectives and beliefs of management are forward-looking statements. Forward-
looking statements appear in a number of places in this Annual Report and may include statements about business
strategy and prospects for growth, customer acquisition costs, legal proceedings, ability to pay cash dividends, cash
flow generation and liquidity, availability of terms of capital, competition and government regulation and general
economic conditions. Although we believe that the expectations reflected in such forward-looking statements are
reasonable, we cannot give any assurance that such expectations will prove correct.
The forward-looking statements in this Annual Report are subject to risks and uncertainties. Important factors that
could cause actual results to materially differ from those projected in the forward-looking statements include, but
are not limited to:
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•
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changes in commodity prices;
the sufficiency of risk management and hedging policies and practices;
the impact of extreme and unpredictable weather conditions, including hurricanes and other natural
disasters;
federal, state and local regulations, including the industry's ability to address or adapt to potentially
restrictive new regulations that may be enacted by public utility commissions;
our ability to borrow funds and access credit markets;
restrictions in our debt agreements and collateral requirements;
credit risk with respect to suppliers and customers;
changes in costs to acquire customers as well as actual attrition rates;
accuracy of billing systems;
our ability to successfully identify, complete, and efficiently integrate acquisitions into our operations;
significant changes in, or new changes by, the independent system operators (“ISOs”) in the regions we
operate;
competition; and
the “Risk Factors” in this Annual Report, and in our quarterly reports, other public filings and press
releases.
You should review the Risk Factors in Item 1A of Part I and other factors noted throughout or incorporated by
reference in this Annual Report that could cause our actual results to differ materially from those contained in any
forward-looking statement. All forward-looking statements speak only as of the date of this Annual Report. Unless
required by law, we disclaim any obligation to publicly update or revise these statements whether as a result of new
information, future events or otherwise. It is not possible for us to predict all risks, nor can we assess the impact of
all factors on the business or the extent to which any factor, or combination of factors, may cause actual results to
differ materially from those contained in any forward-looking statements.
4
PART I.
Items 1 & 2. Business and Properties
General
We are an independent retail energy services company founded in 1999 and are organized as a Delaware
corporation that provides residential and commercial customers in competitive markets across the United States
with an alternative choice for their natural gas and electricity. We purchase our electricity and natural gas supply
from a variety of wholesale providers and bill our customers monthly for the delivery of electricity and natural gas
based on their consumption at either a fixed or variable price. Electricity and natural gas are then distributed to our
customers by local regulated utility companies through their existing infrastructure.
Our business consists of two operating segments:
• Retail Electricity Segment. In this segment, we purchase electricity supply through physical and financial
transactions with market counterparties and ISOs and supply electricity to residential and commercial
consumers pursuant to fixed-price and variable-price contracts.
• Retail Natural Gas Segment. In this segment, we purchase natural gas supply through physical and financial
transactions with market counterparties and supply natural gas to residential and commercial consumers
pursuant to fixed-price and variable-price contracts.
Our Operations
As of December 31, 2019, we operated in 94 utility service territories across 19 states and the District of Columbia
and had approximately 672,000 residential customer equivalents (“RCEs”). An RCE is an industry standard
measure of natural gas or electricity usage with each RCE representing annual consumption of 100 MMBtu of
natural gas or 10 MWh of electricity. We serve natural gas customers in fifteen states (Arizona, California,
Colorado, Connecticut, Florida, Illinois, Indiana, Maryland, Massachusetts, Michigan, Nevada, New Jersey, New
York, Ohio and Pennsylvania) and electricity customers in twelve states (Connecticut, Delaware, Illinois, Maine,
Maryland, Massachusetts, New Hampshire, New Jersey, New York, Ohio, Pennsylvania and Texas) and the District
of Columbia using seven brands (Electricity Maine, Electricity N.H., Major Energy, Provider Power Mass, Respond
Power, Spark Energy, 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
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 or may
not provide for a monthly service fee and/or a termination fee, depending on the market and customer type. Our
variable-price service options carry a month-to-month term and are priced based on our forecasts of underlying
commodity prices and other market factors, including the competitive landscape in the market and the regulatory
environment, and may also include a monthly service fee depending on the market and customer type. 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.
5
The fixed/variable splits of our RCEs were as follows as of December 31, 2019:
Green products and renewable energy credits
We offer renewable and carbon neutral (“green”) products in certain markets. Green energy products are a growing
market opportunity and typically provide increased unit margins as a result of improved customer satisfaction and
less competition. Renewable electricity products allow customers to choose electricity sourced from wind, solar,
hydroelectric and biofuel sources, through the purchase of renewable energy credits (“RECs”). Carbon neutral
natural gas products give customers the option to reduce or eliminate the carbon footprint associated with their
energy usage through the purchase of carbon offset credits. These products typically provide for fixed or variable
prices and generally follow the terms of our other products with the added benefit of carbon reduction and reduced
environmental impact. We currently offer renewable electricity in all of our electricity markets and carbon neutral
natural gas in several of our gas markets. As of December 31, 2019, approximately 37% of our customers utilized
green products.
In addition to the RECs we purchase to satisfy our voluntary requirements under the terms of our green contracts
with our customers, we must also purchase a specified number of RECs based on the amount of electricity we sell
in a state in a year pursuant to individual state renewable portfolio standards. We forecast the price for the required
RECs at the end of each month and incorporate this cost component into our customer pricing models.
Customer Acquisition and Retention
Our customer acquisition strategy consists of customer growth obtained through traditional sales channels
complemented by customer portfolio and business acquisitions. We make decisions on how best to deploy capital
based on a variety of factors, including cost to acquire customers, availability of opportunities and our view of
attractive commodity pricing in particular regions.
Organic Growth
We use organic sales strategies to both maintain and grow our customer base by offering competitive pricing, price
certainty, and/or green product offerings. We manage growth on a market-by-market basis by developing price
curves in each of the markets we serve and comparing the market prices to the price offered by the local regulated
utility. We then determine if there is an opportunity in a particular market based on our ability to create a
competitive product on economic terms that provides customer value and satisfies our profitability objectives. The
attractiveness of a product from a consumer’s standpoint is based on a variety of factors, including overall pricing,
price stability, contract term, sources of generation and environmental impact and whether or not the contract
6
provides for termination and other fees. Product pricing is also based on several other factors, including the cost to
acquire customers in the market, the competitive landscape and supply issues that may affect pricing.
Once a product has been created for a particular market, we then develop a marketing campaign using a
combination of sales channels. We identify and acquire customers through a variety of sales channels, including our
inbound customer care call center, outbound calling, online marketing, opt-in web-based leads, email, direct mail,
door-to-door sales, affinity programs, direct sales, brokers and consultants. For residential customers, we primarily
use indirect sales brokers, web based solicitation, door-to-door sales, outbound calling, and other methods. For
2019, the largest channels were outbound telemarketing, door-to-door sales, and web-based sales. For C&I
customers, which are typically larger and have greater natural gas and electricity requirements, we typically use
brokers or direct marketing to obtain these customers. At December 31, 2019, our customer base was 61%
residential and 39% C&I customers. In our sales practices, we typically employ multiple vendors under short-term
contracts and have not entered into any exclusive marketing arrangements with sales vendors. Our marketing team
continuously evaluates the effectiveness of each customer acquisition channel and makes adjustments in order to
achieve targeted growth and manage customer acquisition costs. We strive to maintain a disciplined approach to
recovery of our customer acquisition costs within defined periods.
Acquisitions
We actively monitor acquisition opportunities that may arise in the domestic acquisition market, and seek to acquire
both portfolios of customers as well as retail energy companies utilizing some combination of cash and borrowings
under our Senior Credit Facility, the issuance of common or preferred stock, or other financing arrangements.
Historically, our customer acquisition strategy has been executed using both third parties and through affiliated
relationships. See “—Relationship with our Founder and Majority Shareholder” for a discussion of affiliate
relationships.
The following table provides a summary of our acquisitions over the past five years:
Company / Portfolio
Date Completed
RCEs
Segment
Customer Portfolio
CenStar Energy Corp.
Oasis Power Holdings, LLC
Customer Portfolio
Provider Companies (1)
Major Energy Companies (2)
Perigee Energy, LLC
Verde Companies (3)
Customer Portfolio
HIKO Energy, LLC
Customer Portfolio
Customer Portfolio
February 2015
July 2015
July 2015
September 2015
August 2016
August 2016
April 2017
July 2017
October 2017
March 2018
12,500
65,000
40,000
9,500
121,000
220,000
17,000
145,000
44,000
29,000
December 2018
35,000
May 2019
60,000
Electricity
Natural Gas
Electricity
Natural Gas
Electricity
Natural Gas
Electricity
Natural Gas
Electricity
Natural Gas
Electricity
Electricity
Electricity
Natural Gas
Electricity
Natural Gas
Electricity
Natural Gas
Electricity
Acquisition Source
Third Party
Third Party
Affiliate
Third Party
Third Party
Affiliate
Affiliate
Third Party
Third Party
Third Party
Affiliate
Third Party
Included Electricity Maine, LLC, Electricity N.H., LLC, Provider Power Mass, LLC (collectively, the “Provider Companies”).
(1)
(2) Included Major Energy Services, LLC, Major Energy Electric Services, LLC, and Respond Power, LLC (collectively, the “Major Energy Companies”).
Included Verde Energy USA, Inc.; Verde Energy USA Commodities, LLC; Verde Energy USA Connecticut, LLC; Verde Energy USA DC, LLC; Verde
(3)
Energy USA Illinois, LLC; Verde Energy USA Maryland, LLC; Verde Energy USA Massachusetts, LLC; Verde Energy USA New Jersey, LLC; Verde
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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”).
Please see Item 9B. “Other Information” and Note 4 "Acquisitions" in the notes to our consolidated financial
statements for a more detailed description of these acquisitions, including the purchase price, the source of funds
and financing arrangements with our Founder and/or NG&E. Please see “Risk Factors" for a discussion of risks
related to our acquisition strategy and ability to finance such transactions.
Retaining customers and maximizing customer lifetime value
Following the acquisition of a customer, we devote significant attention to customer retention. We have developed a
disciplined renewal communication process, which is designed to effectively reach our customers prior to the end of
the contract term, and employ a team dedicated to managing this renewal communications process. Customers are
contacted in each utility prior to the expiration of the customer's contract. We may contact the customer through
additional channels such as outbound calls or email. We also apply a proprietary evaluation and segmentation
process to optimize value to both us and the customer. We analyze historical usage, attrition rates and consumer
behaviors to specifically tailor competitive products that aim to maximize the total expected return from energy
sales to a specific customer, which we refer to as customer lifetime value.
We actively monitor unit margins from energy sales. We use this information to assess the results of products and to
guide business decisions, including whether to engage in pro-active non-renewal of lower margin customers is in
the interest of the Company.
Investment in ESM
In 2016, we and eREX Co., Ltd., a Japanese company, entered into a joint venture investment in eREX Spark
Marketing Co., Ltd ("ESM"). Operations for ESM began on April 1, 2016 in connection with the deregulation of the
Japanese power market. As part of the agreement, we made contributions of 156.4 million Japanese Yen, or $1.4
million, for a 20% ownership interest in ESM.
In November 2019, Spark HoldCo, LLC entered into a share purchase agreement with eREX Co., Ltd. In
accordance with the agreement, we sold our 20% ownership interest in ESM for $8.4 million. See Note 17 "Equity
Method Investment" for further discussion.
Commodity Supply
We hedge and procure our energy requirements from various wholesale energy markets, including both physical and
financial markets, through short- and long-term contracts. Our in-house energy supply team is responsible for
managing our commodity positions (including energy procurement, capacity, transmission, renewable energy, and
resource adequacy requirements) within our risk management policies. We procure our natural gas and electricity
requirements at various trading hubs, city-gates and load zones. When we procure commodities at trading hubs, we
are responsible for delivery to the applicable local regulated utility for distribution.
In most markets, we hedge our electricity exposure with financial products and then purchase the physical power
directly from the ISO for delivery. Alternatively, we may use physical products to hedge our electricity exposure
rather than buying physical electricity in the day-ahead market from the ISO. During the year ended December 31,
2019, we transacted physical and financial settlement of electricity with approximately 13 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
8
conditions. Many of the utilities we serve also allocate natural gas transportation and storage assets to us as a part of
their competitive choice program. We are required to fill our allocated storage capacity with natural gas, which
creates commodity supply and price risk. Sometimes we cannot hedge the volumes associated with these assets
because they are too small compared to the much larger bulk transaction volumes required for trades in the
wholesale market or it is not economically feasible to do so.
We periodically adjust our portfolio of purchase/sale contracts in the wholesale natural gas market based upon
continual analysis of our forecasted load requirements. Natural gas is then delivered to the local regulated utility
city-gate or other specified delivery point where the local regulated utility takes control of the natural gas and
delivers it to individual customer locations. Additionally, we hedge our natural gas price exposure with financial
products. During the year ended December 31, 2019, we transacted physical and financial settlements of natural gas
with approximately 70 wholesale counterparties.
We also enter into back-to-back wholesale transactions to optimize our credit lines with third-party energy
suppliers. With each of our third-party energy suppliers, we have certain contracted credit lines, within which we
are able to purchase energy supply from these counterparties. If we desire to purchase supply beyond these credit
limits, we are required to post collateral in the form of either cash or letters of credit. As we begin to approach the
limits of our credit line with one supplier, we may purchase energy supply from another supplier and sell that
supply to the original counterparty in order to reduce our net position with that counterparty and open up additional
credit to procure supply in the future. Our sales of gas pursuant to these activities also enable us to optimize our
credit lines with third-party energy suppliers by decreasing our net buy position with those suppliers.
Asset Optimization
Part of our business includes asset optimization activities in which we identify opportunities in the wholesale
natural gas markets in conjunction with our retail procurement and hedging activities. Many of the competitive
pipeline choice programs in which we participate require us and other retail energy suppliers to take assignment of
and manage natural gas transportation and storage assets upstream of their respective city-gate delivery points. In
our allocated storage assets, we are obligated to buy and inject gas in the summer season (April through October)
and sell and withdraw gas during the winter season (November through March). These injection and purchase
obligations require us to take a seasonal long position in natural gas. Our asset optimization group determines
whether market conditions justify hedging these long positions through additional derivative transactions. We also
contract with third parties for transportation and storage capacity in the wholesale market and are responsible for
reservation and demand charges attributable to both our allocated and third-party contracted transportation and
storage assets. Our asset optimization group utilizes these allocated and third-party transportation and storage assets
in a variety of ways to either improve profitability or optimize supply-side counterparty credit lines.
We frequently enter into spot market transactions in which we purchase and sell natural gas at the same point or we
purchase natural gas at one location and ship it using our pipeline capacity for sale at another location, if we are
able to capture a margin. We view these spot market transactions as low risk because we enter into the buy and sell
transactions on a back-to-back basis. We also act as an intermediary for market participants who need assistance
with short-term procurement requirements. Consumers and suppliers contact us with a need for a certain quantity of
natural gas to be bought or sold at a specific location. When this occurs, we are able to use our contacts in the
wholesale market to source the requested supply and capture a margin in these transactions.
Our risk policies require that optimization activities be limited to back-to-back purchase and sale transactions, or
open positions subject to aggregate net open position limits, which are not held for a period longer than two months.
Furthermore, all additional capacity procured outside of a utility allocation of retail assets must be approved by a
risk committee. Hedges of our firm transportation obligations are limited to two years or less and hedging of
interruptible capacity is prohibited.
Risk Management
9
We operate under a set of corporate risk policies and procedures relating to the purchase and sale of electricity and
natural gas, general risk management and credit and collections functions. Our in-house energy supply team is
responsible for managing our commodity positions (including energy, capacity, transmission, renewable energy, and
resource adequacy requirements) within our risk management policies. We attempt to increase the predictability of
cash flows by following our hedging strategies.
Our risk committee has control and authority over all of our risk management activities. The risk committee
establishes and oversees the execution of our credit risk management policy and our commodity risk policy. The
risk management policies are reviewed at least annually by the risk management committee and such committee
typically meets quarterly to assure that we have followed these policies. The risk committee also seeks to ensure the
application of our risk management policies to new products that we may offer. The risk committee is comprised of
our Chief Executive Officer and our Chief Financial Officer, who meet on a regular basis to review the status of the
risk management activities and positions. Our risk team reports directly to our Chief Financial Officer and their
compensation is unrelated to trading activity. Commodity positions are typically reviewed and updated daily based
on information from our customer databases and pricing information sources. The risk policy sets volumetric limits
on intra-day and end of day long and short positions in natural gas and electricity. With respect to specific hedges,
we have established and approved a formal delegation of authority specifying each trader's authorized volumetric
limits based on instrument type, lead time (time to trade flow), fixed price volume, index price volume and tenor
(trade flow) for individual transactions. The risk team reports to the risk committee any hedging transactions that
exceed these delegated transaction limits. A discussion of the various risks we face in our risk management
activities is as follows:
Commodity Price and Volumetric Risk
Because our contracts require that we deliver full natural gas or electricity requirements to our customers and
because our customers’ usage can be impacted by factors such as weather, we may periodically purchase more or
less commodity than our aggregate customer volumetric needs. In buying or selling excess volumes, we may be
exposed to commodity price volatility. In order to address the potential volumetric variability of our monthly
deliveries for fixed-price customers, we implement various hedging strategies to attempt to mitigate our exposure.
Our commodity risk management strategy is designed to hedge substantially all of our forecasted volumes on our
fixed-price customer contracts, as well as a portion of the near-term volumes on our variable-price customer
contracts. We use both physical and financial products to hedge our fixed-price exposure. The efficacy of our risk
management program may be adversely impacted by unanticipated events and costs that we are not able to
effectively hedge, including abnormal customer attrition and consumption, certain variable costs associated with
electricity grid reliability, pricing differences in the local markets for local delivery of commodities, unanticipated
events that impact supply and demand, such as extreme weather, and abrupt changes in the markets for, or
availability or cost of, financial instruments that help to hedge commodity price.
Variability in customer demand is primarily impacted by weather. We use utility-provided historical and/or forward
projected customer volumes as a basis for our forecasted volumes and mitigate the risk of seasonal volume
fluctuation for some customers by purchasing excess fixed-price hedges within our volumetric tolerances. Should
seasonal demand exceed our weather-normalized projections, we may experience a negative impact on our financial
results.
From time to time, we also take further measures to reduce price risk and optimize our returns by: (i) maximizing
the use of natural gas storage in our daily balancing market areas in order to give us the flexibility to offset
volumetric variability arising from changes in winter demand; (ii) entering into daily swing contracts in our daily
balancing markets over the winter months to enable us to increase or decrease daily volumes if demand increases or
decreases; and (iii) purchasing out-of-the-money call options for contract periods with the highest seasonal
volumetric risk to protect against steeply rising prices if our customer demands exceed our forecast. Being
geographically diversified in our delivery areas also permits us, from time to time, to employ assets not being used
10
in one area to other areas, thereby mitigating potential increased costs for natural gas that we otherwise may have
had to acquire at higher prices to meet increased demand.
We utilize New York Mercantile Exchange (“NYMEX”) settled financial instruments to offset price risk associated
with volume commitments under fixed-price contracts. The valuation for these financial instruments is calculated
daily based on the NYMEX Exchange published closing price, and they are settled using the NYMEX Exchange’s
published settlement price at their maturity.
Basis Risk
We are exposed to basis risk in our operations when the commodities we hedge are sold at different delivery points
from the exposure we are seeking to hedge. For example, if we hedge our natural gas commodity price with
Chicago basis but physical supply must be delivered to the individual delivery points of specific utility systems
around the Chicago metropolitan area, we are exposed to the risk that prices may differ between the Chicago
delivery point and the individual utility system delivery points. These differences can be significant from time to
time, particularly during extreme, unforecasted cold weather conditions. Similarly, in certain of our electricity
markets, customers pay the load zone price for electricity, so if we purchase supply to be delivered at a hub, we may
have basis risk between the hub and the load zone electricity prices due to local congestion that is not reflected in
the hub price. We attempt to hedge basis risk where possible, but hedging instruments are occasionally not
economically feasible or available in the smaller quantities that we require.
Customer Credit Risk
Our credit risk management policies are designed to limit customer credit exposure. Credit risk is managed through
participation in purchase of receivables ("POR") programs in utility service territories where such programs are
available. In these markets, we monitor the credit ratings of the local regulated utilities and the parent companies of
the utilities that purchase our customer accounts receivable. We also periodically review payment history and
financial information for the local regulated utilities to ensure that we identify and respond to any deteriorating
trends. In non-POR markets, we assess the creditworthiness of new applicants, monitor customer payment activities
and administer an active collection program. Using risk models, past credit experience and different levels of
exposure in each of the markets, we monitor our receivable aging, bad debt forecasts and actual bad debt expenses
and continually adjust as necessary.
In territories where POR programs have been established, the local regulated utility purchases our receivables, and
then becomes responsible for billing and collecting payment from the customer. In return for their assumption of
risk, we receive slightly discounted proceeds on the receivables sold. POR programs result in substantially all of
our credit risk being linked to the applicable utility and not to our end-use customers in these territories. For the
year ended December 31, 2019, approximately 67% of our retail revenues were derived from territories in which
substantially all of our credit risk was directly linked to local regulated utility companies, all of which had
investment grade ratings. During the same period, we paid these local regulated utilities a weighted average
discount of approximately 0.8% of total revenues for customer credit risk. In certain of the POR markets in which
we operate, the utilities limit their collections exposure by retaining the ability to transfer a delinquent account back
to us for collection when collections are past due for a specified period. If our subsequent collection efforts are
unsuccessful, we return the account to the local regulated utility for termination of service. Under these service
programs, we are exposed to credit risk related to payment for services rendered during the time between when the
customer is transferred to us by the local regulated utility and the time we return the customer to the utility for
termination of service, which is generally one to two billing periods. We may also realize a loss on fixed-price
customers in this scenario due to the fact that we will have already fully hedged the customer’s expected
commodity usage for the life of the contract.
In non-POR markets (and in select POR markets where we may choose to direct bill our customers), we manage
commercial customer credit risk through a formal credit review and manage residential customer credit risk through
a variety of procedures, which may include credit score screening, deposits and disconnection for non-payment. We
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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 these markets.
We assess the adequacy of the allowance for doubtful accounts through review of an aging of customer accounts
receivable and general economic conditions in the markets that we serve. Our bad debt expense for the year ended
December 31, 2019 was $13.5 million, or 1.7% of retail revenues. See “Management’s Discussion and Analysis of
Financial Condition and Results of Operations—Drivers of Our Business—Customer Credit Risk” for a more
detailed discussion of our bad debt expense for the year ended December 31, 2019.
We do not have high concentrations of sales volumes to individual customers. For the year ended December 31,
2019, our largest customer accounted for 1% of total retail energy sales volume.
Counterparty Credit Risk in Wholesale Markets
We do not independently produce natural gas and electricity and depend upon third parties for our supply, which
exposes us to wholesale counterparty credit risk in our retail and asset optimization activities. If the counterparties
to our supply contracts are unable to perform their obligations, we may suffer losses, including those that occur as a
result of being unable to secure replacement supplies of natural gas or electricity on a timely or cost-effective basis
or at all. At December 31, 2019, approximately $0.1 million of our total exposure of $3.1 million was either with a
non-investment grade counterparty or otherwise not secured with collateral or a guarantee.
Operational Risk
As with all companies, we are at risk from cyber-attacks (breaches, unauthorized access, misuse, computer viruses,
or other malicious code or other events) that could materially adversely affect our business, or otherwise cause
interruptions or malfunctions in our operations. We mitigate these risks through multiple layers of security controls
including policy, hardware, and software security solutions. We also have engaged third parties to assist with both
external and internal vulnerability scans and continually enhance awareness through employee education and
accountability. As of December 31, 2019, we have not experienced any material loss related to cyber-attacks or
other information security breaches.
Relationship with our Founder and Majority Shareholder
We have historically leveraged our relationship with affiliates of our founder, chairman and majority shareholder,
W. Keith Maxwell III (our "Founder"), to execute our strategy, including sourcing acquisitions, financing, and
operations support. Our Founder owns National Gas & Electric, LLC (“NG&E”), which was formed for the purpose
of purchasing retail energy companies and retail customer books that may ultimately be resold to the Company.
This relationship has afforded us access to opportunities that may not have otherwise been available to us due to our
size and availability of capital.
We may engage in additional transactions with NG&E in the future and expect that any such transactions would be
funded by a combination of cash, subordinated debt, or the issuance of Class A or Class B common stock. Actual
consideration paid for the assets would depend, among other things, on our capital structure and liquidity at the time
of any transaction. Although we believe our Founder would be incentivized to offer us additional acquisition
opportunities, he and his affiliates are under no obligation to do so, and we are under no obligation to buy assets
from them. Any acquisition activity involving NG&E or any other affiliate of our Founder will be subject to
negotiation and approval by a special committee of our Board of Directors consisting solely of independent
directors. Please see “Risk Factors” related to acquisitions and transactions with our affiliates.
Competition
The markets in which we operate are highly competitive. Our primary competition comes from the incumbent
utility and other independent retail energy companies. In the electricity sector, these competitors include larger,
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well-capitalized energy retailers such as Calpine Energy Solutions, LLC, Constellation Energy Group, Inc., Direct
Energy, Inc., NRG Energy, Inc., and Vistra Energy Corp. We also compete with small local retail energy providers
in the electricity sector that are focused exclusively on certain markets. Each market has a different group of local
retail energy providers. In the natural gas sector, our national competitors are primarily Direct Energy and
Constellation Energy. Our national competitors generally have diversified energy platforms with multiple marketing
approaches and broad geographic coverage similar to us. Competition in each market is based primarily on product
offering, price and customer service. The number of competitors in our markets varies. In well-established markets
in the Northeast and Texas we have hundreds of competitors, while in other markets the competition is limited to
several participants. Markets that offer POR programs are generally more competitive than those markets in which
retail energy providers bear customer credit risk.
Our ability to compete depends on our ability to convince customers to switch to our products and services, renew
services with customers upon expiration of their contract terms, and our ability to offer products at attractive prices.
Many local regulated utilities and their affiliates may possess the advantages of name recognition, longer operating
histories, long-standing relationships with their customers and access to financial and other resources, which could
pose a competitive challenge to us. As a result of our competitors' advantages, many customers of these local
regulated utilities may decide to stay with their longtime energy provider if they have been satisfied with their
service in the past. In addition, competitors may choose to offer more attractive short-term pricing to increase their
market share.
Seasonality of Our Business
Our overall operating results fluctuate substantially on a seasonal basis depending on: (i) the geographic mix of our
customer base; (ii) the relative concentration of our commodity mix; (iii) weather conditions, which directly
influence the demand for natural gas and electricity and affect the prices of energy commodities; and (iv) variability
in market prices for natural gas and electricity. These factors can have material short-term impacts on monthly and
quarterly operating results, which may be misleading when considered outside of the context of our annual
operating cycle.
Our accounts payable and accounts receivable are impacted by seasonality due to the timing differences between
when we pay our suppliers for accounts payable versus when we collect from our customers on accounts receivable.
We typically pay our suppliers for purchases of natural gas on a monthly basis and electricity on a weekly basis.
However, it takes approximately two months from the time we deliver the electricity or natural gas to our customers
before we collect from our customers on accounts receivable attributable to those supplies. This timing difference
affects our cash flows, especially during peak cycles in the winter and summer months.
Natural gas accounted for approximately 15% of our retail revenues for the year ended December 31, 2019, which
exposes us to a high degree of seasonality in our cash flows and income earned throughout the year as a result of the
high concentration of heating load in the winter months. We utilize a considerable amount of cash from operations
and borrowing capacity to fund working capital, which includes inventory purchases from April through October
each year. We sell our natural gas inventory during the months of November through March of each year. We expect
that the significant seasonality impacts to our cash flows and income will continue in future periods.
Regulatory Environment
We operate in the highly regulated natural gas and electricity retail sales industry in all of our respective
jurisdictions, and must comply with the legislation and regulations in these jurisdictions in order to maintain our
licenses to operate. We must also comply with the applicable regulations in order to obtain the necessary licenses in
jurisdictions in which we plan to compete. Licensing requirements vary by state, but generally involve regular,
standardized reporting in order to maintain a license in good standing with the state commission responsible for
regulating retail electricity and gas suppliers. We believe there is potential for changes to state legislation and
regulatory measures addressing licensing requirements that may impact our business model in the applicable
jurisdictions. In addition, as further discussed below, our marketing activities and customer enrollment procedures
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are subject to rules and regulations at the state and federal levels, and failure to comply with requirements imposed
by federal and state regulatory authorities could impact our licensing in a particular market. See "Risk Factors—We
face risks due to increasing regulation of the retail energy industry at the state level."
New York
A Low-Income Order was promulgated by the New York State Public Service Commission ("NYPSC") in
December of 2016 (the "Low-Income Order"), and the New York State Supreme Court, Appellate Division, Third
Department ruled in September 2017 that energy service companies ("ESCOs") must proceed with returning
existing low-income customers to utility service and stop enrolling new low-income customers. The ESCOs have
effectively exhausted their legal remedies to appeal this matter and must now comply with the Low-Income Order.
ESCOs may continue serving low income customers if those customers are enrolled in fixed arrangements with
guaranteed savings or with value add inclusions (that were entered into prior to the effective date of the Low-
Income Order) or if the ESCO receives a waiver from the NYPSC to provide low-income customers with
guaranteed savings. The Company and its subsidiaries have been returning low-income customers to the applicable
utilities as they have rolled off of their contracts. As of December 31, 2019, remaining low-income customers
represent approximately 1.3% of our total RCEs in New York and 0.2% of our RCEs overall.
In December 2019, the NYPSC issued its retail energy market reset order (the “December 2019 Reset Order”), that
ESCOs will be required to comply with commencing early May 2020. The December 2019 Reset Order states that
ESCOs can only enroll new residential or small nonresidential customers (mass-market customers) or renew
existing mass-market customer contracts for gas and/or electric service only if at least one of the following
conditions is met: (1) enrollment includes a guaranteed savings over the utility price, as reconciled on an annual
basis; (2) enrollment is for a fixed-rate commodity product that is priced at no more than 5% greater than the
trailing 12-month average utility supply rate; (3) enrollment is for a renewably sourced electric commodity product
that (a) has a renewable mix that is at least 50% greater than the ESCO’s current Renewable Energy Standard (RES)
obligation, (b) the ESCO complies with the RES locational and delivery requirements when procuring RECs or
entering into bilateral contracts for renewable commodity supply, and (c) there is transparency of information and
disclosures provided to the customer with respect to pricing and commodity sourcing. In addition, by June 9, 2020,
all New York ESCOs are directed to essentially re-apply for licenses to serve customers in New York.
We are evaluating the potential impact of the NYPSC's December 2019 Reset Order and subsequent proceedings on
our New York operations while preparing to operate in compliance with any new requirements that may come as a
result of any new order promulgated by the NYPSC. Given the uncertainty of the outcome of these matters and the
final requirements that may be implemented, we are unable to predict at this time the magnitude of the long-term
impact on our operations in New York.
Massachusetts
In October 2018, the Attorney General for the Commonwealth of Massachusetts filed suit against another ESCO
and others alleging unfair or deceptive acts or practices in violation of a consumer protections act, breach of the
covenant of good faith and fair dealing, and violation of the Massachusetts Telemarketing Solicitation Act.
Contemporaneously with the filing of their complaint, the Commonwealth filed for injunctive relief seeking to
attach purchase of receivables program revenues owed to the ESCO as possible damages. There can be no
assurance that the Commonwealth will not pursue similar claims against other ESCOs.
Other States
Recently, certain state commissions have begun efforts to restrict the ability of retail suppliers to “pass through”
costs to customers associated with certain changes in law or regulatory requirements. For example, on January 22,
2019, the New Jersey Board of Public Utilities (“NJ BPU”) sent a cease and desist letter to third party suppliers
(“TPS”) in New Jersey instructing that a TPS may not charge a customer rate that is higher than the fixed rate
applicable during the period for which that rate was fixed. The letter notified TPS that such increases were
14
prohibited and instructed TPS to refund customers amounts charged in excess of the applicable fixed rate. Parties
have challenged the NJ BPU’s letter and it is not clear at this time whether refunds will be required. Similarly, the
Connecticut Public Utilities Regulatory Authority (“PURA”) recently opened a docket after receiving complaints
regarding increases by suppliers to certain fixed-price supplier contracts due to change in law triggers. PURA will
consider whether suppliers’ actions constitute unfair and deceptive trade practices or otherwise violates applicable
laws. PURA is expected to issue a declaratory ruling following its review. Depending on the outcome of these
efforts in New Jersey and Connecticut, the Company may be required to assume costs that it otherwise would pass
on to customers under its change in law provisions and potentially provide refunds to certain customers.
Other Regulations
Our marketing efforts to consumers, including but not limited to telemarketing, door-to-door sales, direct mail and
online marketing, are subject to consumer protection regulation including state deceptive trade practices acts,
Federal Trade Commission ("FTC") marketing standards, and state utility commission rules governing customer
solicitations and enrollments, among others. By way of example, telemarketing activity is subject to federal and
state do-not-call regulation and certain enrollment standards promulgated by state regulators. Door-to-door sales are
governed by the FTC’s “Cooling Off” Rule as well as state-specific regulation in many jurisdictions. In markets in
which we conduct customer credit checks, these checks are subject to the requirements of the Fair Credit Reporting
Act. Violations of the rules and regulations governing our marketing and sales activity could impact our license to
operate in a particular market, result in suspension or otherwise limit our ability to conduct marketing activity in
certain markets, and potentially lead to private actions against us. Moreover, there is potential for changes to
legislation and regulatory measures applicable to our marketing measures that may impact our business models.
Recent interpretations of the Telephone Consumer Protection Act of 1991 (the “TCPA”) by the Federal
Communications Commission (“FCC”) have introduced confusion regarding what constitutes an “autodialer” for
purposes of determining compliance under the TCPA. Also, additional restrictions have been placed on wireless
telephone numbers making compliance with the TCPA more costly. See “Risk Factors—Risks Related to Our
Business and Our Industry—Liability under the TCPA has increased significantly in recent years, and we face risks
if we fail to comply.”
As compliance with the federal TCPA regulations and state telemarketing regulations becomes increasingly costly
and as door-to-door marketing becomes increasingly risky both from a regulatory compliance perspective, and from
the risk of such activities drawing class action litigation claims, we and our peers who rely on these sales channels
will find it more difficult than in the past to engage in direct marketing efforts. In response to these risks, we are
experimenting with new technologies, such as a web-based application to process door-to-door sales enrollments
with direct input by the consumer. This application can be accessed using tablets or any smart phone device, which
enhances and expands the opportunities to market directly to customers.
Our participation in natural gas and electricity wholesale markets to procure supply for our retail customers and
hedge pricing risk is subject to regulation by the Commodity Futures Trading Commission (the "CFTC"), including
regulation pursuant to the Dodd-Frank Wall Street Reform and Consumer Protection Act. In order to sell electricity,
capacity and ancillary services in the wholesale electricity markets, we are required to have market-based rate
authorization, also known as “MBR Authorization,” from the Federal Energy Regulatory Commission ("FERC").
We are required to make status update filings to FERC to disclose any affiliate relationships and quarterly filings to
FERC regarding volumes of wholesale electricity sales in order to maintain our MBR Authorization. We are also
required to seek prior approval by FERC to the extent any direct or indirect change in control occurs with respect to
entities that hold MBR Authorization.
The transportation and sale for resale of natural gas in interstate commerce are regulated by agencies of the U.S.
federal government, primarily FERC under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and
regulations issued under those statutes. FERC regulates interstate natural gas transportation rates and service
conditions, which affects our ability to procure natural gas supply for our retail customers and hedge pricing risk.
Since 1985, FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and
sellers on an open and non-discriminatory basis. FERC’s orders do not attempt to directly regulate natural gas retail
15
sales. As a shipper of natural gas on interstate pipelines, we are subject to those interstate pipelines' tariff
requirements and FERC regulations and policies applicable to shippers.
Changes in law and to FERC policies and regulations may adversely affect the availability and reliability of firm
and/or interruptible transportation service on interstate pipelines, and we cannot predict what future action FERC
will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs
from the way they will affect other natural gas marketers and local regulated utilities with which we compete.
In December 2007, FERC issued Order 704, a final rule on the annual natural gas transaction reporting
requirements, as amended by subsequent orders on rehearing. Under Order 704, wholesale buyers and sellers of
more than 2.2 million MMBtus of physical natural gas in the previous calendar year, including natural gas gatherers
and marketers, are required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at
wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the
formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions
should be reported based on the guidance of Order 704. Order 704 also requires market participants to indicate
whether they report prices to any index publishers, and if so, whether their reporting complies with FERC’s policy
statement on price reporting. As a wholesale buyer and seller of natural gas, we are subject to the reporting
requirements of Order 704.
Employees
We employed 164 people as of December 31, 2019, none of which were subject to any collective bargaining
agreements. We have not experienced any strikes or work stoppages and consider our relations with our employees
to be satisfactory. We also utilize the services of independent contractors and vendors to perform various services.
Facilities
Our corporate headquarters is located in Houston, Texas, and we also maintain an office in Orangeburg, New York.
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Available Information
Our website is located at www.sparkenergy.com. We make available our periodic reports and other information filed
with or furnished to the Securities and Exchange Commission (the “SEC”), including our annual reports on Form
10-K, our quarterly reports on Form 10-Q, our current reports on Form 8-K, and all amendments to those reports,
free of charge through our website, as soon as reasonably practicable after those reports and other information are
electronically filed with or furnished to the SEC. Any materials filed with the SEC may be read and copied at the
SEC’s website at www.sec.gov.
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Item 1A. Risk Factors
You should carefully consider the risks described below together with the other information contained in this
Annual Report on Form 10-K. If any of the risks below were to occur, our business, financial condition, cash flows,
results of operation and ability to pay dividends on our Class A common stock and Series A Preferred Stock could
be adversely impacted, and the price of the Class A common stock and Series A Preferred Stock could decline and
you could lose your investment.
Risks Related to Our Business and Our Industry
We are subject to commodity price risk.
Our financial results are largely dependent on the prices at which we can acquire the commodities we resell. The
prevailing market prices for natural gas and electricity have historically, and may continue to fluctuate substantially
over relatively short periods of time. Changes in market prices for natural gas and electricity may result from many
factors that are outside of our control, including:
— weather conditions;
— seasonality;
— demand for energy commodities and general economic conditions;
— disruption of natural gas or electricity transmission or transportation infrastructure or other constraints or
inefficiencies;
— reduction or unavailability of generating capacity, including temporary outages, mothballing, or
retirements;
— the level of prices and availability of natural gas and competing energy sources, including the impact of
changes in environmental regulations impacting suppliers;
— the creditworthiness or bankruptcy or other financial distress of market participants;
— changes in market liquidity;
— natural disasters, wars, embargoes, acts of terrorism and other catastrophic events;
— significant changes in the pricing methods in the wholesale markets in which we operate;
— changes in regulatory policies concerning how markets are structured, how compensation is provided for
service, and the kinds of different services that can or must be offered;
— federal, state, foreign and other governmental regulation and legislation; and
— demand side management, conservation, alternative or renewable energy sources.
We may not be able to pass along changes to the prices we pay to acquire commodities to our customers and such
pricing fluctuations can attract consumer class actions as well as state and federal regulatory actions.
Our financial results may be adversely impacted by weather conditions.
Weather conditions directly influence the demand for and availability of natural gas and electricity and affect the
prices of energy commodities. Generally, on most utility systems, demand for natural gas peaks in the winter and
demand for electricity peaks in the summer. Typically, when winters are warmer or summers are cooler, demand for
energy is lower than expected, resulting in less natural gas and electricity consumption than forecasted. When
demand is below anticipated levels due to weather patterns, we may be forced to sell excess supply at prices below
our acquisition cost, which could result in reduced margins or even losses.
Conversely, when winters are colder or summers are warmer, consumption may outpace the volumes of natural gas
and electricity against which we have hedged, and we may be unable to meet increased demand with storage or
swing supply. In these circumstances, we may experience reduced margins or even losses if we are required to
purchase additional supply at higher prices. We may fail to accurately anticipate demand due to fluctuations in
weather or to effectively manage our supply in response to a fluctuating commodity price environment.
18
Our risk management policies and hedging procedures may not mitigate risk as planned, and we may fail to fully
or effectively hedge our commodity supply and price risk.
To provide energy to our customers, we purchase commodities in the wholesale energy markets, which are often
highly volatile. Our commodity risk management strategy is designed to hedge substantially all of our forecasted
volumes on our fixed-price customer contracts, as well as a portion of the near-term volumes on our variable-price
customer contracts. We use both physical and financial products to hedge our exposure. The efficacy of our risk
management program may be adversely impacted by unanticipated events and costs that we are not able to
effectively hedge, including abnormal customer attrition and consumption, certain variable costs associated with
electricity grid reliability, pricing differences in the local markets for local delivery of commodities, unanticipated
events that impact supply and demand, such as extreme weather, and abrupt changes in the markets for, or
availability or cost of, financial instruments that help to hedge commodity price.
We are exposed to basis risk in our operations when the commodities we hedge are sold at different delivery points
from the exposure we are seeking to hedge. For example, if we hedge our natural gas commodity price with
Chicago basis but physical supply must be delivered to the individual delivery points of specific utility systems
around the Chicago metropolitan area, we are exposed to basis risk between the Chicago basis and the individual
utility system delivery points. These differences can be significant from time to time, particularly during extreme,
unforecasted cold weather conditions. Similarly, in certain of our electricity markets, customers pay the load zone
price for electricity, so if we purchase supply to be delivered at a hub, we may have basis risk between the hub and
the load zone electricity prices due to local congestion that is not reflected in the hub price. We attempt to hedge
basis risk where possible, but hedging instruments are sometimes not economically feasible or available in the
smaller quantities that we require.
Additionally, assumptions that we use in establishing our hedges may reduce the effectiveness of our hedging
instruments. Considerations that may affect our hedging policies include, but are not limited to, human error,
assumptions about customer attrition, the relationship of prices at different trading or delivery points, assumptions
about future weather, and our load forecasting models.
In addition, we incur costs monthly for ancillary charges such as reserves and capacity in the electricity sector by
ISOs. For example, the ISOs will charge all retail electricity providers for monthly reserves that the ISO determines
are necessary to protect the integrity of the grid. We attempt to estimate such amounts, but they are difficult to
estimate because they are charged in arrears by the ISOs and are subject to fluctuations based on weather and other
market conditions. We may be unable to fully pass the higher cost of ancillary reserves and reliability services
through to our customers, and increases in the cost of these ancillary reserves and reliability services could
negatively impact our results of operations.
Many of the natural gas utilities we serve allocate a share of transportation and storage capacity to us as a part of
their competitive market operations. We are required to fill our allocated storage capacity with natural gas, which
creates commodity supply and price risk. Sometimes we cannot hedge the volumes associated with these assets
because they are too small compared to the much larger bulk transaction volumes required for trades in the
wholesale market or it is not economically feasible to do so. In some regulatory programs or under some contracts,
this capacity may be subject to recall by the utilities, which could have the effect of us being required to access the
spot market to cover such a recall.
ESCOs face risks due to increased and rapidly changing regulations and increasing monetary fines by the state
regulatory agencies.
The retail energy industry is highly regulated. Regulations may be changed or reinterpreted and new laws and
regulations applicable to our business could be implemented in the future. To the extent that the competitive
restructuring of retail electricity and natural gas markets is reversed, altered or discontinued, such changes could
have a detrimental impact on our business and overall financial condition.
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Some states are beginning to increase their regulation of their retail electricity and natural gas markets in an effort to
increase consumer disclosures and ensure marketing practices are not misleading to consumers. In addition, the fines
against ESCOs that regulators are seeking has increased dramatically in recent years. For example, in 2015 the
Connecticut Legislature passed legislation providing that licensed electric suppliers in Connecticut could no longer
offer variable rate products as Connecticut regulators believed that a variable rate product was inappropriate for
residential consumers.
In addition, in December 2019, the NYPSC issued its retail energy market reset order (the “December 2019 Reset
Order”), that ESCOs will be required to comply with commencing early May 2020. The December 2019 Reset Order
states that ESCOs can only enroll new residential or small nonresidential customers (mass-market customers) or renew
existing mass-market customer contracts for gas and/or electric service only if at least one of the following conditions
is met: (1) enrollment includes a guaranteed savings over the utility price, as reconciled on an annual basis; (2) enrollment
is for a fixed-rate commodity product that is priced at no more than 5% greater than the trailing 12-month average
utility supply rate; (3) enrollment is for a renewably sourced electric commodity product that (a) has a renewable mix
that is at least 50% greater than the ESCO’s current Renewable Energy Standard (RES) obligation, (b) the ESCO
complies with the RES locational and delivery requirements when procuring Renewable Energy Credits (RECs) or
entering into bilateral contracts for renewable commodity supply, and (c) there is transparency of information and
disclosures provided to the customer with respect to pricing and commodity sourcing. In addition, by June 9, 2020,
all New York ESCOs are directed to essentially re-apply for licenses to serve customers in New York.
We are evaluating the potential impact of the NYPSC's December 2019 Reset Order and subsequent proceedings on
our New York operations while preparing to operate in compliance with any new requirements that may come as a
result of any new order promulgated by the NYPSC. Given the uncertainty of the outcome of these matters and the
final requirements that may be implemented, we are unable to predict at this time the magnitude of the long-term
impact on our operations in New York.
Prior to the December 2019 Reset Order, the NYPSC implemented a low-income order that required ESCOs to return
existing low-income customers to utility service and stop enrolling new low-income customers unless customers are
enrolled in fixed arrangements with guaranteed savings or with value add inclusions (that were entered into prior to
the effective date of the low-income order) or if the ESCO receives a waiver from the NYPSC to provide low-income
customers with guaranteed savings. As a result of the low-income order, we have been dropping low-income customers
back to the applicable utilities as they have rolled off of their contracts. As of December 31, 2019, remaining low-
income customers represent approximately 1.3% of our total RCEs in New York and 0.2% of our RCEs overall. There
can be no assurance that the NYPSC or state regulatory agencies to which we are subject will not continue trying to
implement restrictive anti-competitive regulations on us.
On October 15, 2018, the Attorney General for the Commonwealth of Massachusetts filed suit against another ESCO
and others alleging unfair or deceptive acts or practices in violation of a consumer protections act, breach of the
covenant of good faith and fair dealing, and violation of the Massachusetts Telemarketing Solicitation Act.
Contemporaneously with the filing of their complaint, the Commonwealth filed for injunctive relief seeking to attach
purchase of receivables program revenues owed to the ESCO as possible damages. There can be no assurance that the
Commonwealth will not pursue similar claims against other ESCOs.
Recently, certain state commissions have begun efforts to restrict the ability of retail suppliers to “pass through” costs
to customers associated with certain changes in law or regulatory requirements. For example, on January 22, 2019,
the New Jersey Board of Public Utilities ("NJ BPU") sent a cease and desist letter to third party suppliers ("TPS") in
New Jersey instructing that a TPS may not charge a customer rate that is higher than the fixed rate applicable during
the period for which that rate was fixed. The letter notified TPS that such increases were prohibited and instructed
TPS to refund customers amounts charged in excess of the applicable fixed rate. Parties have challenged the NJ BPU’s
letter and it is not clear at this time whether refunds will be required. Similarly, the Connecticut Public Utilities
Regulatory Authority ("PURA") recently opened a docket after receiving complaints regarding increases by suppliers
to certain fixed-price supplier contracts due to change in law triggers. PURA will consider whether suppliers’ actions
constitute unfair and deceptive trade practices or otherwise violate applicable laws. PURA is expected to issue a
declaratory ruling following its review. Depending on the outcome of these efforts in New Jersey and Connecticut,
20
the Company may be required to assume costs that it otherwise would pass on to customers under its change in law
provisions and potentially provide refunds to certain customers.
The retail energy business is subject to a high level of federal, state and local regulations, which are subject to
change.
Our costs of doing business may fluctuate based on changing state, federal and local rules and regulations. For
example, many electricity markets have rate caps, and changes to these rate caps by regulators can impact future
price exposure. Similarly, regulatory changes can result in new fees or charges that may not have been anticipated
when existing retail contracts were drafted, which can create financial exposure. Our ability to manage cost
increases that result from regulatory changes will depend, in part, on how the “change in law provisions” of our
contracts are interpreted and enforced, among other factors.
Liability under the TCPA has increased significantly in recent years, and we face risks if we fail to comply.
Our outbound telemarketing efforts and use of mobile messaging to communicate with our customers subjects us to
regulation under the TCPA. Over the last several years, companies have been subject to significant liabilities as a
result of violations of the TCPA, including penalties, fines and damages under class action lawsuits. In addition, the
increased use by us and other consumer retailers of mobile messaging to communicate with our customers has
created new issues of application of the TCPA to these communications. In 2015, the Federal Communications
Commission issued several rulings that made compliance with the TCPA more difficult and costly. Our failure to
effectively monitor and comply with our activities that are subject to the TCPA could result in significant penalties
and the adverse effects of having to defend and ultimately suffer liability in a class action lawsuit related to such
non-compliance.
We are also subject to liability under the TCPA for actions of our third party vendors who are engaging in outbound
telemarketing efforts on our behalf. The issue of vicarious liability for the actions of third parties in violation of the
TCPA remains unclear and has been the subject of conflicting precedent in the federal appellate courts. There can be
no assurance that we may be subject to significant damages as a result of a class action lawsuit for actions of our
vendors that we may not be able to control.
We are, and in the future may become, involved in legal and regulatory proceedings and, as a result, may incur
substantial costs.
We are subject to lawsuits, claims and regulatory proceeds arising in the ordinary course of our business from time
to time, including several purported class action lawsuits involving sales practices, telemarketing and TCPA claims,
as well as contract disclosure claims and breach of contract claims. These are in various stages and are subject to
substantial uncertainties concerning the outcome.
A negative outcome for any of these matters could result in significant damages. Litigation may also negatively
impact us by requiring us to pay substantial settlements, increasing our legal costs, diverting management attention
from other business issues or harming our reputation with customers.
For additional information regarding the nature and status of certain proceedings, see Note 14 "Commitments and
Contingencies" to the audited consolidated financial statements.
Our business is dependent on retaining licenses in the markets in which we operate.
Our business model is dependent on continuing to be licensed in existing markets. We may have a license revoked
or not be granted a renewal of a license, or our license could be adversely conditioned or modified (e.g., by
increased bond posting obligations). For example, recently, an ESCO was banned by the Public Utilities
Commission of Ohio from operating in Ohio for five years in response to allegations that it has misleading and
deceptive marketing practices and charged customers four times the rate as compared to other electricity and gas
suppliers.
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We may be subject to risks in connection with acquisitions, which could cause us to fail to realize many of the
anticipated benefits of such acquisitions.
We have grown our business in part through strategic acquisition opportunities from third parties and from affiliates
of our majority shareholder and may continue to do so in the future. Achieving the anticipated benefits of these
transactions depends in part upon our ability to identify accretive acquisition targets, accurately assess the benefits
and risks of the acquisition prior to undertaking it, and the ability to integrate the acquired businesses in an efficient
and effective manner. When we identify an acquisition candidate, there is a risk that we may be unable to negotiate
terms that are beneficial to us. Additionally, even if we identify an accretive acquisition target, the successful
acquisition of that business requires estimating anticipated cash flow and accretive value, evaluating potential
regulatory challenges, retaining customers and assuming liabilities. The accuracy of these estimates is inherently
uncertain and our assumptions may turn out to be incorrect.
Furthermore, when we make an acquisition, we may not be able to accomplish the integration process smoothly or
successfully. The difficulties of integrating acquisitions can include, among other things:
–
coordinating geographically separate organizations and addressing possible differences in corporate cultures
and management philosophies;
– dedicating significant management resources to the integration of the acquisition, which may temporarily
–
distract management's attention from the day-to-day business of the combined company;
increased liquidity needs to support working capital for the purchase of natural gas and electricity supply to
meet our customers’ needs, for the credit requirements of forward physical supply and for generally higher
operating expenses;
– operating in states and markets where we have not previously conducted business;
– managing different and competing brands and retail strategies in the same markets;
–
coordinating customer information and billing systems and determining how to optimize those systems on a
consolidated level;
– ensuring our hedging strategy adequately covers a customer base that is managed through multiple systems;
–
–
successfully recognizing expected cost savings and other synergies in overlapping functions; and
incurring the responsibility and cost to defend and settle regulatory and litigation matters stemming from
the acquired company’s pre-acquisition sales and marketing activities, which may not be covered by
indemnification.
In many of our acquisition agreements, we are entitled to indemnification from the counterparty for various matters,
including breaches of representations, warranties and covenants, tax matters, and litigation proceedings. We
generally obtain security to provide assurances that the counterparty could perform its indemnification obligations,
which may be in the form of escrow accounts, payment withholding or other methods. However, to the extent that
we do not obtain security, or the security turns out to be inadequate, there is a risk that the counterparty may fail to
perform on its indemnification obligations, which could result in the losses being incurred by us.
Our ability to grow at levels experienced historically may be constrained if the market for acquisition candidates is
limited and we are unable to make acquisitions of portfolios of customers and retail energy companies on
commercially reasonable terms.
Pursuant to our cash dividend policy, we distribute a significant portion of our cash through regular quarterly
dividends, and our ability to grow and make acquisitions with cash on hand could be limited.
Pursuant to our cash dividend policy, we have historically distributed and intend in the future 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
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Credit Facility and Subordinated Facility. These sources may not be available, and our ability to grow and maintain
our business may be limited.
We may not be able to manage our growth successfully.
The growth of our operations will depend upon our ability to expand our customer base in our existing markets and
to enter new markets in a timely manner at reasonable costs, organically or through acquisitions. In order for us to
recover expenses incurred in entering new markets and obtaining new customers, we must attract and retain
customers on economic terms and for extended periods. We may experience difficulty managing our growth and
implementing new product offerings, integrating new customers and employees, and complying with applicable
market rules and the infrastructure for product delivery.
Expanding our operations also may require continued development of our operating and financial controls and may
place additional stress on our management and operational resources. We may be unable to manage our growth and
development successfully.
Our financial results fluctuate on a seasonal, quarterly and annual basis.
Our overall operating results fluctuate substantially on a seasonal, quarterly and annual basis depending on: (1) the
geographic mix of our customer base; (2) the relative concentration of our commodity mix; (3) weather conditions,
which directly influence the demand for natural gas and electricity and affect the prices of energy commodities; and
(4) variability in market prices for natural gas and electricity. These factors can have material short-term impacts on
monthly and quarterly operating results, which may be misleading when considered outside of the context of our
annual operating cycle. In addition, our accounts payable and accounts receivable are impacted by seasonality due
to the timing differences between when we pay our suppliers for accounts payable versus when we collect from our
customers on accounts receivable. We typically pay our suppliers for purchases of natural gas on a monthly basis
and electricity on a weekly basis. However, it takes approximately two months from the time we deliver the
electricity or natural gas to our customers before we collect from our customers on accounts receivable attributable
to those supplies. This timing difference could affect our cash flows, especially during peak cycles in the winter and
summer months. Furthermore, as a result of the seasonality of our business, we may reserve a portion of our excess
cash available for distribution in the first and fourth quarters in order to fund our second and third quarter
distributions.
Additionally, we enter into a variety of financial derivative and physical contracts to manage commodity price risk,
and we use mark-to-market accounting to account for this hedging activity. Under the mark-to-market accounting
method, changes in the fair value of our hedging instruments that are not qualifying or not designated as hedges
under accounting rules are recognized immediately in earnings. As a result of this accounting treatment, changes in
the forward prices of natural gas and electricity cause volatility in our quarterly and annual earnings, which we are
unable to fully anticipate.
We could also incur volatility from quarter to quarter associated with gains and losses on settled hedges relating to
natural gas held in inventory if we choose to hedge the summer-winter spread on our retail allocated storage
capacity. We typically purchase natural gas inventory and store it from April to October for withdrawal from
November through March. Since a portion of the inventory is used to satisfy delivery obligations to our fixed-price
customers over the winter months, we hedge the associated price risk using derivative contracts. Any gains or losses
associated with settled derivative contracts are reflected in the statement of operations as a component of retail cost
of sales and net asset optimization.
We may have difficulty retaining our existing customers or obtaining a sufficient number of new customers, due
to competition and for other reasons.
The markets in which we compete are highly competitive, and we may face difficulty retaining our existing
customers or obtaining new customers due to competition. We encounter significant competition from local
regulated utilities or their retail affiliates and traditional and new retail energy providers. Many of these competitors
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or potential competitors are larger than us, have access to more significant capital resources, have more well-
established brand names and have larger existing installed customer bases.
Additionally, existing customers may switch to other retail energy service providers during their contract terms in
the event of a significant decrease in the retail price of natural gas or electricity in order to obtain more favorable
prices. Although we generally have a right to collect a termination fee from each customer on a fixed-price contract
who terminates their contract early, we may not be able to collect the termination fees in full or at all. Our variable-
price contracts can typically be terminated by our customers at any time without penalty. We may be unable to
obtain new customers or maintain our existing customers due to competition or otherwise.
Increased collateral requirements in connection with our supply activities may restrict our liquidity.
Our contractual agreements with certain local regulated utilities and our supplier counterparties require us to
maintain restricted cash balances or letters of credit as collateral for credit risk or the performance risk associated
with the future delivery of natural gas or electricity. These collateral requirements may increase as we grow our
customer base. Collateral requirements will increase based on the volume or cost of the commodity we purchase in
any given month and the amount of capacity or service contracted for with the local regulated utility. Significant
changes in market prices also can result in fluctuations in the collateral that local regulated utilities or suppliers
require.
The effectiveness of our operations and future growth depend in part on the amount of cash and letters of credit
available to enter into or maintain these contracts. The cost of these arrangements may be affected by changes in
credit markets, such as interest rate spreads in the cost of financing between different levels of credit ratings. These
liquidity requirements may be greater than we anticipate or are able to meet.
We are subject to direct credit risk for certain customers who may fail to pay their bills as they become due.
We bear direct credit risk related to customers located in markets that have not implemented POR programs as well
as indirect credit risk in those POR markets that pass collection efforts along to us after a specified non-payment
period. For the year ended December 31, 2019, customers in non-POR markets represented approximately 33% of
our retail revenues. We generally have the ability to terminate contracts with customers in the event of non-
payment, but in most states in which we operate we cannot disconnect their natural gas or electricity service. In
POR markets where the local regulated utility has the ability to return non-paying customers to us after specified
periods, we may realize a loss for one to two billing periods until we can terminate these customers’ contracts. We
may also realize a loss on fixed-price customers in this scenario due to the fact that we will have already fully
hedged the customer’s expected commodity usage for the life of the contract and we also remain liable to our
suppliers of natural gas and electricity for the cost of our supply commodities. Furthermore, in the Texas market, we
are responsible for billing the distribution charges for the local regulated utility and are at risk for these charges, in
addition to the cost of the commodity, in the event customers fail to pay their bills. Changing economic factors,
such as rising unemployment rates and energy prices also result in a higher risk of customers being unable to pay
their bills when due.
We depend on the accuracy of data in our information management systems, which subjects us to risks.
We depend on the accuracy and timeliness of our information management systems for billing, collections,
consumption and other important data. We rely on many internal and external sources for this information,
including:
— our marketing, pricing and customer operations functions; and
— 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.
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Inaccurate or untimely information, which may be outside of our direct control, could result in:
— inaccurate and/or untimely bills sent to customers;
— incorrect tax remittances;
— reduced effectiveness and efficiency of our operations;
— inability to adequately hedge our portfolio;
— increased overhead costs;
— inaccurate accounting and reporting of customer revenues, gross margin and accounts receivable activity;
— inaccurate measurement of usage rates, throughput and imbalances;
— customer complaints; and
— increased regulatory scrutiny.
We are also subject to disruptions in our information management systems arising out of events beyond our control,
such as natural disasters, pandemics, epidemics, failures in hardware or software, power fluctuations,
telecommunications and other similar disruptions. In addition, our information management systems may be
vulnerable to computer viruses, incursions by intruders or hackers and cyber terrorists and other similar disruptions.
A cyber-attack on our information management systems could severely disrupt business operations, preventing us
from billing and collecting revenues, and could result in significant expenses to investigate and repair security
breaches or system damage, lead to litigation, fines, other remedial action, heightened regulatory scrutiny,
diminished customer confidence and damage to our reputation. Although we maintain cyber-liability insurance that
covers certain damage caused by cyber events, it may not be sufficient to cover us in all circumstances.
Our success depends on key members of our management, the loss of whom could disrupt our business
operations.
We depend on the continued employment and performance of key management personnel. A number of our senior
executives have substantial experience in consumer and energy markets that have undergone regulatory
restructuring and have extensive risk management and hedging expertise. We believe their experience is important
to our continued success. We do not maintain key life insurance policies for our executive officers. Our key
executives may not continue in their present roles and may not be adequately replaced.
We rely on third party vendors 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 platforms to third party vendors, and we rely
heavily on the continued performance of the vendors under our current outsourcing agreement. Our vendors may
fail to operate in accordance with the terms of the outsourcing agreement or a bankruptcy or other event may
prevent it from performing under our outsourcing agreement.
A large portion of our current customers are concentrated in a limited number of states, making us vulnerable to
customer concentration risks.
As of December 31, 2019, approximately 59% of our RCEs were located in five states. Specifically, 16%, 12%,
12%, 10% and 9% of our customers on an RCE basis were located in NY, MA, PA, CT and TX, respectively. If we
are unable to increase our market share across other competitive markets or enter into new competitive markets
effectively, we may be subject to continued or greater customer concentration risk. The states that contain a large
percentage of our customers could reverse regulatory restructuring or change the regulatory environment in a
manner that causes us to be unable to operate economically in that state.
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Increases in state renewable portfolio standards or an increase in the cost of renewable energy credit and carbon
offsets may adversely impact the price, availability and marketability of our products.
Pursuant to state renewable portfolio standards, we must purchase a specified amount of RECs based on the amount
of electricity we sell in a state in a year. In addition, we have contracts with certain customers that require us to
purchase RECs or carbon offsets. If a state increases its renewable portfolio standards, the demand for RECs within
that state will increase and therefore the market price for RECs could increase. We attempt to forecast the price for
the required RECs and carbon offsets at the end of each month and incorporate this forecast into our customer
pricing models, but the price paid for RECs and carbon offsets may be higher than forecasted. We may be unable to
fully pass the higher cost of RECs through to our customers, and increases in the price of RECs may decrease our
results of operations and affect our ability to compete with other energy retailers that have not contracted with
customers to purchase RECs or carbon offsets. Further, a price increase for RECs or carbon offsets may require us
to decrease the renewable portion of our energy products, which may result in a loss of customers. A further
reduction in benefits received by local regulated utilities from production tax credits in respect of renewable energy
may adversely impact the availability to us, and marketability by us, of renewable energy under our brands.
Our access to marketing channels may be contingent upon the viability of our telemarketing and door-to-door
agreements with our vendors.
Our vendors are essential to our telemarketing and door-to-door sales activities. Our ability to increase revenues in
the future will depend significantly on our access to high quality vendors. If we are unable to attract new vendors
and retain existing vendors to achieve our marketing targets, our growth may be materially reduced. There can be
no assurance that competitive conditions will allow these vendors and their independent contractors to continue to
successfully sign up new customers. Further, if our products are not attractive to, or do not generate sufficient
revenue for our vendors, we may lose our existing relationships. In addition, the decline in landlines reduces the
number of potential customers that may be reached by our telemarketing efforts and as a result our telemarketing
sales channel may become less viable and we may be required to use more door-to-door marketing. Door-to-door
marketing is continually under scrutiny by state regulators and legislators, which may lead to new rules and
regulations that impact our ability to use these channels.
Our vendors may expose us to risks.
We are subject to reputational risks that may arise from the actions of our vendors and their independent contractors
that are wholly or partially beyond our control, such as violations of our marketing policies and procedures as well
as any failure to comply with applicable laws and regulations. If our vendors engage in marketing practices that are
not in compliance with local laws and regulations, we may be in breach of applicable laws and regulations that may
result in regulatory proceedings, disadvantageous conditioning of our energy retailer license, or the revocation of
our energy retailer license. Unauthorized activities in connection with sales efforts by agents of our vendors,
including calling consumers in violation of the TCPA and predatory door-to-door sales tactics and fraudulent
misrepresentation could subject us to class action lawsuits against which we will be required to defend. Such
defense efforts will be costly and time consuming. In addition, the independent contractors of our vendors may
consider us to be their employer and seek compensation.
Risks Related to Our Capital Structure and Capital Stock
Our indebtedness could adversely affect our ability to raise additional capital to fund our operations or pay
dividends. It could also expose us to the risk of increased interest rates and limit our ability to react to changes in
the economy or our industry as well as impact our cash available for distribution.
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We have $123.0 million of indebtedness outstanding and $37.4 million in issued letters of credit under our Senior
Credit Facility, and zero of indebtedness outstanding under our Subordinated Facility as of December 31, 2019.
Debt we incur under our Senior Credit Facility, Subordinated Facility or otherwise could have negative
consequences, including:
— increasing our vulnerability to general economic and industry conditions;
— requiring cash flow from operations to be dedicated to the payment of principal and interest on our
indebtedness, therefore reducing or eliminating our ability to pay dividends to holders of our Class A
common stock and Series A Preferred Stock, or to use our cash flow to fund our operations, capital
expenditures and future business opportunities;
— limiting our ability to fund future acquisitions or engage in other activities that we view as in our long-
term best interest;
— restricting our ability to make certain distributions with respect to our capital stock and the ability of our
subsidiaries to make certain distributions to us, in light of restricted payment and other financial
covenants, including requirements to maintain certain financial ratios, in our credit facilities and other
financing agreements;
— exposing us to the risk of increased interest rates because certain of our borrowings are at variable rates
of interest; and
— limiting our ability to obtain additional financing for working capital including collateral postings,
capital expenditures, debt service requirements, acquisitions and general corporate or other purposes.
If we are unable to satisfy financial covenants in our debt instruments, it could result in an event of default that, if
not cured or waived, may entitle the lenders to demand repayment or enforce their security interests. Our Senior
Credit Facility will mature in May 2021, and we cannot assure that we will be able to negotiate a new credit
arrangement on commercially reasonable terms.
We cannot assure you that we will be able to continue paying our targeted quarterly dividend to the holders of
our Class A common stock or dividends to the holders of our Series A Preferred Stock in the future.
The amount of our cash available for distribution principally depends upon the amount of cash we generate from
our operations, which fluctuates from quarter to quarter based on, among other things:
— changes in commodity prices, which may be driven by a variety of factors, including, but not limited to,
weather conditions, seasonality and demand for energy commodities and general economic conditions;
— the level and timing of customer acquisition costs we incur;
— the level of our operating and general and administrative expenses;
— seasonal variations in revenues generated by our business;
— our debt service requirements and other liabilities;
— fluctuations in our working capital needs;
— our ability to borrow funds and access capital markets;
— restrictions contained in our debt agreements (including our Senior Credit Facility);
— management of customer credit risk;
— abrupt changes in regulatory policies; and,
— other business risks affecting our cash flows.
As a result of these and other factors, we cannot guarantee that we will have sufficient cash generated from
operations to pay the dividends on our Series A Preferred Stock or to pay a specific level of cash dividends to
holders of our Class A common stock.
The amount of cash available for distribution depends primarily on our cash flow, and is not solely a function of
profitability, which is affected by non-cash items. We may incur other expenses or liabilities during a period that
could significantly reduce or eliminate our cash available for distribution and, in turn, impair our ability to pay
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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.
We are a holding company. Our sole material asset is our equity interest in Spark HoldCo, LLC ("Spark
HoldCo") and we are accordingly dependent upon distributions from Spark HoldCo to pay dividends on the
Class A common stock and Series A Preferred Stock.
We are a holding company and have no material assets other than our equity interest in Spark HoldCo, and have no
independent means of generating revenue. Spark HoldCo or its subsidiaries may be restricted from making
distributions to us under applicable law or regulation or under the terms of their financing arrangements, or may
otherwise be unable to provide such funds.
The Class A common stock and Series A Preferred Stock are subordinated to our existing and future debt
obligations.
The Class A common stock and Series A Preferred Stock are subordinated to all of our existing and future
indebtedness (including indebtedness outstanding under the Senior Credit Facility). Therefore, if we become
bankrupt, liquidate our assets, reorganize or enter into certain other transactions, assets will be available to pay our
obligations with respect to the Series A Preferred Stock only after we have paid all of our existing and future
indebtedness in full. The Class A common stock will only receive assets to the extent all existing and future
indebtedness and obligations under the Series A Preferred Stock is paid in full. If any of these events were to occur,
there may be insufficient assets remaining to make any payments to holders of the Series A Preferred Stock or Class
A common stock.
Additionally, none of our subsidiaries have 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
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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. Increases in market interest rates, which have been at low levels relative to historical rates, may lead
prospective purchasers of shares of Class A common stock or Series A Preferred Stock to expect a higher
distribution yield, and cause them to sell their Class A common stock or Series A Preferred Stock. Accordingly,
higher market interest rates could cause the market price of the Class A common stock and Series A Preferred Stock
to decrease.
In addition, over the last several years, prices of equity securities in the U.S. trading markets have been
experiencing extreme price fluctuations. As a result of these and other factors, investors holding our Class A
common stock and Series A Preferred Stock may experience a decrease in the value of their securities, which could
be substantial and rapid, and could be unrelated to our financial condition, performance or prospects.
There may not be an active trading market for the Class A common stock or Series A Preferred Stock, which may
in turn reduce the market value and your ability to transfer or sell your shares of Class A common stock or
Series A Preferred Stock.
There are no assurances that there will be an active trading market for our Class A common stock or Series A
Preferred Stock. The liquidity of any market for the Class A common stock and Series A Preferred Stock depends
upon the number of stockholders, our results of operations and financial condition, the market for similar securities,
the interest of securities dealers in making a market in the Class A common stock and Series A Preferred Stock, and
other factors. To the extent that an active trading market is not maintained, the liquidity and trading prices for the
Class A common stock and Series A Preferred Stock may be harmed.
Furthermore, because the Series A Preferred Stock does not have any stated maturity and is not subject to any
sinking fund or mandatory redemption, stockholders seeking liquidity will be limited to selling their respective
shares of Series A Preferred Stock in the secondary market. Active trading markets for the Series A Preferred Stock
may not exist at such times, in which case the trading price of your shares of our Series A Preferred Stock could be
reduced and your ability to transfer such shares could be limited.
Our Founder holds a substantial majority of the voting power of our common stock.
Holders of Class A and Class B common stock vote together as a single class on all matters presented to our
stockholders for their vote or approval, except as otherwise required by applicable law or our certificate of
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incorporation and bylaws. Our Founder controls 66.3% of the combined voting power of the Class A and Class B
common stock as of December 31, 2019 through his direct and indirect ownership in us.
Affiliated owners are entitled to act separately with respect to their investment in us, and they have the ability to
elect all of the members of our board of directors, and thereby to control our management and affairs. In addition,
affiliates are able to determine the outcome of all matters requiring Class A common stock and Class B common
stock shareholder approval, including mergers and other material transactions, and is able to cause or prevent a
change in the composition of our board of directors or a change in control of our company that could deprive our
stockholders of an opportunity to receive a premium for their Class A common stock as part of a sale of our
company. The existence of a significant shareholder, such as our Founder, may also have the effect of deterring
hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our
other stockholders to approve transactions that they may deem to be in the best interests of our company.
So long as affiliates continue to control a significant amount of our common stock, they will continue to be able to
strongly influence all matters requiring shareholder approval, regardless of whether other stockholders believe that
a potential transaction is in their own best interests. In any of these matters, the interests of affiliates may differ or
conflict with the interests of our other stockholders. Moreover, this concentration of stock ownership may also
adversely affect the trading price of our Class A common stock or Series A Preferred Stock to the extent investors
perceive a disadvantage in owning stock of a company with a controlling shareholder.
Holders of Series A Preferred Stock have extremely limited voting rights.
Voting rights of holders of shares of Series A Preferred Stock are extremely limited. Our Class A common stock and
our Class B common stock are the only classes of our securities carrying full voting rights. Holders of the Series A
Preferred Stock generally have no voting rights.
We have engaged in transactions with our affiliates in the past and expect to do so in the future. The terms of
such transactions and the resolution of any conflicts that may arise may not always be in our or our
stockholders’ best interests.
We have engaged in transactions and expect to continue to engage in transactions with affiliated companies. We
have acquired companies and books of customers from our affiliates and may do so in the future. We will continue
to enter into back-to-back transactions for purchases of commodities and derivatives on behalf of our affiliate. We
will also continue to pay certain expenses on behalf of several of our affiliates for which we will seek
reimbursement. We will also continue to share our corporate headquarters with certain affiliates. We cannot assure
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 September 20, 2019, 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 18, 2019. 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.
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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;
— 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.
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
31
stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us
or our directors, officers, employees or agents.
Our amended and restated certificate of incorporation provides that, unless we consent in writing to the selection of
an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by
applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf,
(ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or
agents to us or our stockholders, (iii) any action asserting a claim against us or any director or officer or other
employee of ours arising pursuant to any provision of the DGCL, our amended and restated certificate of
incorporation or our bylaws, or (iv) any action asserting a claim against us or any director or officer or other
employee of ours that is governed by the internal affairs doctrine, in each such case subject to such Court of
Chancery having personal jurisdiction over the indispensable parties named as defendants therein. This exclusive
forum provision would not apply to suits brought to enforce any liability or duty created by the Securities Act or the
Exchange Act or any other claim for which the federal courts have exclusive jurisdiction. To the extent that any
such claims may be based upon federal law claims, Section 27 of the Exchange Act creates exclusive federal
jurisdiction over all suits brought to enforce any duty or liability created by the Exchange Act or the rules and
regulations thereunder. Furthermore, Section 22 of the Securities Act creates concurrent jurisdiction for federal and
state courts over all suits brought to enforce any duty or liability created by the Securities Act or the rules and
regulations thereunder.
Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to
have notice of, and consented to, the provisions of our amended and restated certificate of incorporation described
in the preceding sentence. This choice of forum provision may limit a stockholder’s ability to bring a claim in a
judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may
discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our
amended and restated certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the
specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in
other jurisdictions, which could adversely affect our business, financial condition or results of operations.
Future sales of 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 September 20, 2019, we filed a registration statement under the Securities Act on Form S-3 registering the
primary offer and sale, from time to time, of Class A common stock, preferred stock, depositary shares and
warrants. The registration statement also registers the Class A common stock held by our affiliates, Retailco and
NuDevco (including Class A common stock that may be obtained upon conversion of Class B common stock). All
of the shares of Class A common stock held by Retailco and NuDevco and registered on the registration statement
may be immediately resold. The registration statement was declared effective on October 18, 2019.
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
32
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 have issued preferred stock and may continue to do so, and the terms of such preferred stock could adversely
affect the voting power or value of our Class A common stock.
Our certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes
or series of preferred stock having such designations, preferences, limitations and relative rights, including
preferences over our Class A common stock with respect to dividends and distributions, as our board of directors
may determine. Through December 31, 2019, we have issued an aggregate of 3,707,256 shares of Series A
Preferred Stock.
The terms of the preferred stock we offer or sell could adversely impact the voting power or value of our Class A
common stock. For example, we might grant holders of preferred stock the right to elect some number of our
directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly,
the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock, such as
the Series A Preferred Stock, could affect the residual value of the Class A common stock.
Our amended and restated certificate of incorporation limits the fiduciary duties of one of our directors and
certain of our affiliates and restricts the remedies available to our stockholders for actions taken by our Founder
or certain of our affiliates that might otherwise constitute breaches of fiduciary duty.
Our amended and restated certificate of incorporation contains provisions that we renounce any interest in existing
and future investments in other entities by, or the business opportunities of, NuDevco Partners, LLC, NuDevco
Partners Holdings, LLC and W. Keith Maxwell III, or any of their officers, directors, agents, shareholders,
members, affiliates and subsidiaries (other than a director or officer who is presented an opportunity solely in his
capacity as a director or officer). Because of this provision, these persons and entities have no obligation to offer us
those investments or opportunities that are offered to them in any capacity other than solely as an officer or director.
If one of these persons or entities pursues a business opportunity instead of presenting the opportunity to us, we will
not have any recourse against such person or entity for a breach of fiduciary duty.
The Series A Preferred Stock represent perpetual equity interests in us, and investors should not expect us to
redeem the Series A Preferred Stock on the date the Series A Preferred Stock becomes redeemable by us or on
any particular date afterwards.
The Series A Preferred Stock represents a perpetual equity interest in us, and the securities have no maturity or
mandatory redemption date and are not redeemable at the option of investors under any circumstances. As a result,
unlike our indebtedness, the Series A Preferred Stock will not give rise to a claim for payment of a principal amount
at a particular date. As a result, holders of the Series A Preferred Stock may be required to bear the financial risks of
an investment in the Series A Preferred Stock for an indefinite period of time. In addition, the Series A Preferred
Stock will rank junior to all our current and future indebtedness (including indebtedness outstanding under the
Senior Credit Facility) and other liabilities. The Series A Preferred Stock will also rank junior to any other preferred
stock ranking senior to the Series A Preferred Stock we may issue in the future with respect to assets available to
satisfy claims against us.
The Series A Preferred Stock is not rated.
We have not sought to obtain a rating for the Series A Preferred Stock, and the Series A Preferred Stock may never
be rated. It is possible, however, that one or more rating agencies might independently determine to assign a rating
to the Series A Preferred Stock or that we may elect to obtain a rating of the Series A Preferred Stock in the future.
In addition, we may elect to issue other securities for which we may seek to obtain a rating. If any ratings are
33
assigned to the Series A Preferred Stock in the future or if we issue other securities with a rating, such ratings, if
they are lower than market expectations or are subsequently lowered or withdrawn, could adversely affect the
market for or the market value of the Series A Preferred Stock. Ratings only reflect the views of the issuing rating
agency or agencies and such ratings could at any time be revised downward or withdrawn entirely at the discretion
of the issuing rating agency. A rating is not a recommendation to purchase, sell or hold any particular security,
including the Series A Preferred Stock. Ratings do not reflect market prices or suitability of a security for a
particular investor and any future rating of the Series A Preferred Stock may not reflect all risks related to us and
our business, or the structure or market value of the Series A Preferred Stock.
We cannot guarantee that our Repurchase Program will enhance shareholder value and purchases, if any, could
increase the volatility of the price of our Series A Preferred Stock.
Our Board of Directors has authorized the Repurchase Program, which permits us to purchase our Series A
Preferred Stock through December 31, 2020. The Repurchase Program does not obligate us to purchase a specific
dollar amount or number of shares of Series A Preferred Stock. The specific timing and amount of purchases, if any,
will depend upon several factors, including ongoing assessments of capital needs, the market price of the Series A
Preferred Stock, and other factors, including general market conditions. There can be no assurance that we will
make future purchases of Series A Preferred Stock or that we will purchase a sufficient number of shares to satisfy
market expectations.
Purchases of our Series A Preferred Stock could affect the market price and increase volatility of our Series A
Preferred Stock. We cannot provide any assurance that purchases under the Repurchase Program will be made at the
best possible price. Additionally, purchases under our Repurchase Program could diminish our cash reserves or
increase borrowings under our Senior Credit Facility or Subordinated Facility, which may impact our ability to
finance future growth and to pursue possible future strategic opportunities and acquisitions. Although our
Repurchase Program is intended to enhance long-term shareholder value, there is no assurance that it will do so.
We are permitted to and could discontinue our Repurchase Program prior to its expiration or completion. The
existence of the Repurchase Program could cause our Series A Preferred Stock price to be higher than it would be in
the absence of such a program, and any such discontinuation could cause the market price of our Series A Preferred
Stock to decline.
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.
Changes in the method of determining the London Interbank Offered Rate (“LIBOR”), or the replacement of
LIBOR with an alternative reference rate, may adversely affect interest rates under our Senior Credit Facility
and the floating dividend rate of our Series A Preferred Stock.
LIBOR is a basic rate of interest widely used as a global reference for setting interest rates on loans and payment
rates on other financial instruments. Our Senior Credit Facility uses LIBOR as the reference rate for Eurodollar
denominated borrowings. In addition, on and after April 15, 2022, dividends on the Series A Preferred Stock accrue
at a floating rate equal to the sum of: (a) Three-Month LIBOR Rate as calculated on each applicable determination
date, plus (b) 6.578%.
In 2017, the United Kingdom’s Financial Conduct Authority, which regulates LIBOR, announced that it intends to
phase out LIBOR by the end of 2021. It is unclear if LIBOR will cease to exist at that time, if new methods of
calculating LIBOR will be established such that it continues to exist after 2021 or whether different reference rates
34
will develop. It is impossible to predict the effect these developments, any discontinuance, modification or other
reforms to LIBOR or the establishment of alternative reference rates may have on LIBOR, other benchmark rates or
floating rate debt instruments.
Although our Senior Credit Facility and Series A Preferred Stock contain LIBOR alternative provisions and the use
of alternative reference rates, new methods of calculating LIBOR or other reforms could cause the interest rates
under our Senior Credit Facility or the dividend rate on our Series A Preferred Stock to be materially different than
expected, which could have an adverse effect on our business, financial position, and results of operations, and our
ability to pay dividends on the Series A Preferred Stock and Class A common stock.
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 or an alternative 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 (if it then exists), or a substantial increase in the alternative reference rate, could
negatively impact our ability to pay dividends on the Series A Preferred Stock. An increase in the dividends payable
on our Series A Preferred Stock would negatively impact dividends on our Class A common stock. We cannot
assure you that we will have adequate sources of capital to repurchase or redeem the Series A Preferred Stock on or
after April 15, 2022. If we are unable to repurchase or redeem the Series A Preferred Stock and our ability to pay
dividends on the Series A Preferred Stock and Class A common stock is negatively impacted, the market value of
the Series A Preferred Stock and Class A common stock could be materially adversely impacted.
We may not have sufficient earnings and profits in order for dividends on the Series A Preferred Stock to be
treated as dividends for U.S. federal income tax purposes.
The dividends payable by us on the Series A Preferred Stock may exceed our current and accumulated earnings and
profits, as calculated for U.S. federal income tax purposes. If this occurs, it will result in the amount of the
dividends that exceed such earnings and profits being treated for U.S. federal income tax purposes first as a return
of capital to the extent of the beneficial owner’s adjusted tax basis in the Series A Preferred Stock, and the excess, if
any, over such adjusted tax basis as gain from the sale or exchange of property, which generally results in capital
gain. Such treatment will generally be unfavorable for corporate beneficial owners and may also be unfavorable to
certain other beneficial owners.
You may be subject to tax if we make or fail to make certain adjustments to the conversion rate of the Series A
Preferred Stock even though you do not receive a corresponding cash 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.
We are a “controlled company” under NASDAQ Global Select Market rules, and as such we are entitled to an
exemption from certain corporate governance standards of the NASDAQ Global Select Market, and you may not
have the same protections afforded to shareholders of companies that are subject to all of the NASDAQ Global
Market corporate governance requirements.
We qualify as a “controlled company” within the meaning of NASDAQ Global Select Market corporate governance
standards because an affiliated holder controls more than 50% of our voting power. Under NASDAQ Global Select
35
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.
Although our board of directors has established a nominating and corporate governance committee and a
compensation committee of independent directors, it may determine to eliminate these committees at any time. If
these committees were eliminated, you may not have the same protections afforded to shareholders of companies
that are subject to all of NASDAQ Global Select Market corporate governance requirements.
Item 1B. Unresolved Staff Comments
None.
Item 3. Legal Proceedings
We are the subject of lawsuits and claims arising in the ordinary course of business from time to time. Management
cannot predict the ultimate outcome of such lawsuits and claims. While the lawsuits and claims are asserted for
amounts that may be material, should an unfavorable outcome occur, management does not currently expect that
any currently pending matters will have a material adverse effect on our financial position or results of operations
except as described in Part II, Item 8 “Financial Statements and Supplementary Data,” Note 14 "Commitments and
Contingencies" to the audited consolidated financial statements, which are incorporated herein by reference.
Item 4. Mine Safety Disclosures.
Not applicable.
36
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 3, 2020, we had one holder of record of our Class A
common stock and two holders of record of our Class B common stock, excluding stockholders for whom shares
are held in “nominee” or “street name.”
Dividends
We typically pay a cash dividend each quarter to holders of our Class A common stock to the extent we have cash
available for distribution and are permitted to do so under the terms of our Senior Credit Facility.
Recent Sales of Unregistered Equity Securities
We have not sold any unregistered equity securities other than as previously reported.
Purchases of Equity Securities
The following table sets forth information regarding purchases of our Series A Preferred Stock by us during
the three months ended December 31, 2019 pursuant to our Repurchase Program.
(a) Total
Number of
Shares
Purchased
(b) Average
Price Paid per
Share
(c) Total Number of
Shares Purchased as
Part of Publicly
Announced Plans or
Programs (1)
(d) Maximum Number (or
Approximate Dollar Value) of
Shares that May Yet Be
Purchased Under the Plans or
Programs (1)
Period
October 1 - October 31,
2019
November 1 - November
30, 2019
December 1 - December 31,
2019
2,300 $
23,138
—
24.94
24.82
—
Total
25,438 $
24.83
2,300
23,138
—
25,438
—
—
—
—
(1) On May 22, 2019, the Company announced that the Board of Directors authorized the Repurchase Program to
purchase shares of Series A Preferred Stock through May 20, 2020. On November 8, 2019, the Repurchase Program
was amended and extended through December 31, 2020. There is no dollar limit on the amount of Series A
Preferred Stock that may be purchased. The Repurchase Program does not obligate us to make any repurchases and
may be suspended for periods or discontinued at any time.
Stock Performance Graph
The following graph compares the quarterly performance of our Class A common stock to the NASDAQ Composite
Index ("NASDAQ Composite") and the Dow Jones U.S. Utilities Index ("IDU"). The chart assumes that the value
of the investment in our Class A common stock and each index was $100 at December 31, 2014 and that all
dividends were reinvested. The stock performance shown on the graph below is not indicative of future price
performance.
37
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.
38
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, 2019. The information as of and for the years ended December 31, 2019, 2018 and 2017 is
derived from the consolidated financial statements contained in this Form 10-K and should be read in conjunction
with the information contained in “Management’s Discussion and Analysis of Financial Condition and Results of
Operations” and “Financial Statements and Supplementary Data.” Financial information as of and for the years
ended December 31, 2016 and 2015 was derived from information filed as part of our 2018 and 2017 Form 10-Ks.
(in thousands, except per share and volumetric data)
2019
Year Ended December 31,
2017
2018
2016
2015
Income Statement Data:
Total revenues
Operating income (loss)
Net income (loss)
Net income (loss) attributable to Non-Controlling Interests
Net income (loss) attributable to Spark Energy, Inc.
stockholders
Net income (loss) attributable to stockholders of Class A
common stock
Net income (loss) attributable to Spark Energy, Inc. per share
of Class A common stock
Basic
Diluted
Weighted average common shares outstanding
Basic
Diluted
Balance Sheet Data:
Current assets
Current liabilities
Total assets
Long-term liabilities
Cash Flow Data:
Cash flows provided by operating activities
Cash flows provided by (used in) investing activities
Cash flows (used in) provided by financing activities
Other Financial Data:
Adjusted EBITDA (1)
Retail gross margin (1)
Distributions paid to Class B non-controlling unit holders and
dividends paid to Class A common shareholders
Other Operating Data:
RCEs (thousands)
Electricity volumes (MWh)
Natural gas volumes (MMBtu)
$
$
$
$
$
$
$
$
$
$
$
$
$
$
813,725
23,979
14,213
5,763
$ 1,005,928
(3,654)
(14,392)
(13,206)
798,055
102,420
75,044
55,799
$
$
546,697
84,001
65,673
51,229
358,153
29,905
25,975
22,110
8,450
(1,186)
19,245
14,444
359
(9,295)
16,207
14,444
0.03
0.02
$
$
(0.69) $
(0.69) $
1.23
1.21
$
$
1.27
1.11
$
$
14,286
14,568
13,390
13,390
13,143
13,346
11,402
12,690
3,865
3,865
0.63
0.53
6,129
6,655
236,128
141,955
422,968
123,712
$
$
$
$
291,980
141,951
488,738
165,735
$
$
$
$
296,738
151,027
503,741
152,446
$
$
$
$
197,983
184,056
367,749
67,438
$
$
$
$
102,680
84,188
162,234
44,727
$
91,735
1,398
$
(85,103) $
59,763
$
(18,981) $
(20,563) $
62,131
$
(77,558) $
$
25,886
66,950
$
(33,489) $
(18,975) $
45,931
(41,943)
(3,873)
92,404
220,740
$
$
70,716
185,109
$
$
102,884
224,509
$
$
81,892
182,369
$
$
36,869
113,615
(45,176) $
(45,261) $
(43,319) $
(43,297) $
(20,043)
672
6,416,568
14,543,563
908
8,630,653
16,778,393
1,042
6,755,663
18,203,684
774
4,170,593
16,819,713
415
2,075,479
14,786,681
(1) Adjusted EBITDA and retail gross margin are non-GAAP financial measures. For a definition and reconciliation of each of Adjusted
EBITDA and retail gross margin to their most directly comparable financial measures calculated and presented in accordance with
GAAP, please see “Management's Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Performance
Measures.”
39
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
The following discussion and analysis of our financial condition and results of operations should be read in
conjunction with the consolidated financial statements and the related notes thereto included elsewhere in this
Annual Report. In this Annual Report, the terms “Spark Energy,” “Company,” “we,” “us” and “our” refer
collectively to Spark Energy, Inc. and its subsidiaries.
Overview
We are an independent retail energy services company founded in 1999 that provides residential and commercial
customers in competitive markets across the United States with an alternative choice for 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, 2019, we operated in 94 utility service territories across 19 states and the
District of Columbia.
Our business consists of two operating segments:
• Retail Electricity Segment. In this segment, we purchase electricity supply through physical and financial
transactions with market counterparties and ISOs and supply electricity to residential and commercial
consumers pursuant to fixed-price and variable-price contracts. For the years ended December 31, 2019, 2018
and 2017, approximately 85%, 86% and 82%, respectively, of our retail revenues were derived from the sale
of electricity.
• Retail Natural Gas Segment. In this segment, we purchase natural gas supply through physical and financial
transactions with market counterparties and supply natural gas to residential and commercial consumers
pursuant to fixed-price and variable-price contracts. For the years ended December 31, 2019, 2018 and 2017,
approximately 15%, 14% and 18%, respectively, of our retail revenues were derived from the sale of natural
gas.
Recent Developments
Preferred Stock Repurchase Program
In November 2019, we amended and extended our repurchase program (the "Repurchase Program") of our Series A
Preferred Stock. The Repurchase Program allows us to purchase Series A Preferred Stock through December 31,
2020, at prevailing prices, in open market or negotiated transactions, subject to market conditions, maximum share
prices and other considerations. The Repurchase Program does not obligate us to make any repurchases and may be
suspended at any time.
Drivers of Our Business
The success of our business and our profitability are impacted by a number of drivers, the most significant of which
are discussed below.
Customer Growth
Customer growth is a key driver of our operations. Our ability to acquire customers organically or by acquisition is
important to our success as we experience ongoing customer attrition. Our customer growth strategy includes
growing organically through traditional sales channels complemented by customer portfolio and business
acquisitions.
40
We measure our number of customers using residential customer equivalents ("RCEs"). The following table shows
our RCEs by segment as of December 31, 2019, 2018 and 2017:
RCEs:
(In thousands)
Retail Electricity
Retail Natural Gas
Total Retail
2019
533
139
672
December 31,
2018
754
154
908
2017
868
174
1,042
The following table details our count of RCEs by geographical location as of December 31, 2019:
RCEs by Geographic Location:
(In thousands)
New England
Mid-Atlantic
Midwest
Southwest
Total
Electricity
% of Total Natural Gas
% of Total
Total
% of Total
217
196
57
63
533
41%
37%
10%
12%
100%
27
49
42
21
139
20%
35%
30%
15%
100%
244
245
99
84
672
36%
36%
15%
13%
100%
The geographical locations noted above include the following states:
• New England - Connecticut, Maine, Massachusetts and New Hampshire;
• Mid-Atlantic - Delaware, Maryland (including the District of Columbia), New Jersey, New York and
Pennsylvania;
• Midwest - Illinois, Indiana, Michigan and Ohio; and
• Southwest - Arizona, California, Colorado, Florida, Nevada and Texas.
Across our market areas, we have operated under a number of different retail brands. We currently operate under
seven retail brands. During 2019 and 2018, we consolidated our brands and billings systems in an effort to simplify
our business operations. Our goal is to reduce the number of separate brands to three by the end of 2020.
Organic Sales
Our organic sales strategies are designed to offer competitive pricing, price certainty, and/or green product offerings
to residential and commercial customers. We manage growth on a market-by-market basis by developing price
curves in each of the markets we serve and comparing the market prices to the price offered by the local regulated
utility. We then determine if there is an opportunity in a particular market based on our ability to create a
competitive product on economic terms that provides customer value and satisfies our profitability objectives. We
develop marketing campaigns using a combination of sales channels. Our marketing team continuously evaluates
the effectiveness of each customer acquisition channel and makes adjustments in order to achieve desired targets.
During the year ended December 31, 2019, we added approximately 214,000 RCEs through our various organic
sales channels.
Acquisitions
We acquire companies and portfolios of customers through both external and affiliated channels. In 2017, we
acquired approximately 206,000 RCEs through acquisitions of Verde Energy USA Holdings, LLC ("Verde
41
Energy"), Perigee Energy, LLC ("Perigee Energy"), and a customer portfolio. In 2018, we added approximately
81,000 RCEs through our acquisitions of HIKO, a customer portfolio from an affiliate, and a customer portfolio
from Starion Energy ("Starion"). In 2019, we added approximately 33,000 RCEs as part of the completion of the
acquisition from Starion.
Our ability to realize returns from acquisitions that are acceptable to us is dependent on our ability to successfully
identify, negotiate, finance and integrate acquisitions.
RCE Activity
The following table shows our RCE activity during the years ended December 31, 2019, 2018 and 2017.
(In thousands)
December 31, 2016
Additions
Attrition
December 31, 2017
Additions
Attrition
December 31, 2018
Additions
Attrition
December 31, 2019
Retail
Electricity
571
Retail Natural
Gas
203
659
(362)
868
363
(477)
754
189
(410)
533
61
(90)
174
69
(89)
154
58
(73)
139
% Net Annual
Increase
(Decrease)
35%
(13)%
(26)%
Total
774
720
(452)
1,042
432
(566)
908
247
(483)
672
The increase of our RCE counts in 2017 was related to the acquisition of customers and businesses in excess of
natural customer attrition. In 2018 and 2019, our attrition exceeded customer adds due to our intentional non-
renewal of certain larger C&I customer contracts, lower organic sales spending, and fewer acquisitions and slightly
higher attrition impacted by our brand consolidation activities. Average monthly attrition rates during 2019, 2018
and 2017 were as follows:
Year Ended
Quarter Ended
December 31
December 31
September 30
June 30
March 31
4.3%
4.7%
5.0%
4.9%
6.7%
7.0%
4.2%
4.0%
4.0%
4.1%
3.7%
3.8%
3.8%
4.2%
5.4%
2017
2018
2019
Customer attrition occurs primarily as a result of: (i) customer initiated switches; (ii) residential moves
(iii) disconnection resulting from customer payment defaults and (iv) pro-active non-renewal of contracts. Customer
attrition during the year ended December 31, 2019 was slightly higher than the prior year due to a previously
communicated strategy to shrink our C&I customer book, resulting in our pro-active non-renewal of some of our
lower-margin large commercial contracts.
Customer Acquisition Costs
Managing customer acquisition costs is a key component of our profitability. Customer acquisition costs are those
costs related to obtaining customers organically and do not include the cost of acquiring customers through
acquisitions, which are recorded as customer relationships. For each of the three years ended December 31, 2019,
customer acquisition costs were as follows:
42
(In thousands)
Customer Acquisition Costs
Year Ended December 31,
2019
2018
2017
$
18,685 $
13,673 $
25,874
We strive to maintain a disciplined approach to recovery of our customer acquisition costs within a 12 month
period. We capitalize and amortize our customer acquisition costs over a two year period, which is based on our
estimate of the expected average length of a customer relationship. We factor in the recovery of customer
acquisition costs in determining which markets we enter and the pricing of our products in those markets.
Accordingly, our results are significantly influenced by our customer acquisition costs. Changes in customer
acquisition costs from period to period reflect our focus on growing organically versus growth through acquisitions.
We are currently focused on growing through organic sales channels; however, we continue to evaluate
opportunities to acquire customers through acquisitions and pursue such acquisitions when it makes sense
economically or strategically for the Company.
Customer Credit Risk
Approximately 67% of our revenues are derived from customers in utilities where customer credit risk is borne by
the utility in exchange for a discount on amounts billed. Where we have customer credit risk, we record bad debt
based on an estimate of uncollectible amounts. Our bad debt expense on non-POR revenues was as follows:
Year Ended December 31,
2019
2018
2017
Total Non-POR Bad Debt as Percent of Revenue
3.3%
2.6%
2.5%
During the year ended December 31, 2019, we experienced higher bad debt expense versus 2018 primarily due to
an increase in residential customers in non-POR markets. In addition, as our geographic and acquisition channel
mix has changed, our bad debt expense has increased. In order to manage this exposure in 2019, we have increased
our focus on: collection efforts, timely billing, and credit monitoring for new enrollments in non-POR markets.
During the year ended December 31, 2018, we experienced higher bad debt expense versus 2017 primarily as a
result of our brand consolidations.
For the years ended December 31, 2019, 2018 and 2017, approximately 67%, 66% and 66%, respectively, of our
retail revenues were collected through POR programs where substantially all of our credit risk was with local
regulated utility companies. As of December 31, 2019, 2018 and 2017, all of these local regulated utility companies
had investment grade ratings. During these same periods, we paid these local regulated utilities a weighted average
discount of approximately 0.8%, 1.0% and 1.1%, respectively, of total revenues for customer credit risk protection.
Weather Conditions
Weather conditions directly influence the demand for natural gas and electricity and affect the prices of energy
commodities. Our hedging strategy is based on forecasted customer energy usage, which can vary substantially as a
result of weather patterns deviating from historical norms. We are particularly sensitive to this variability in our
residential customer segment where energy usage is highly sensitive to weather conditions that impact heating and
cooling demand.
Our risk management policies direct that we hedge substantially all of our forecasted demand, which is typically
hedged to long-term normal weather patterns. We also attempt to add additional protection through hedging from
time to time to protect us from potential volatility in markets where we have historically experienced higher
exposure to extreme weather conditions. Because we attempt to match commodity purchases to anticipated demand,
unanticipated changes in weather patterns can have a significant impact on our operating results and cash flows
from period to period.
43
We experienced milder than normal weather in most of our geographies for most of 2019 with the exception of the
third quarter. This milder weather resulted in lower sales volumes during the period and lower demand for
commodities. In markets where we were fully hedged, we were selling back some of those hedges into a depressed
wholesale market. During the first quarter of 2019, we experienced weather volatility in the New England, Mid-
Atlantic and Midwest regions that resulted in higher-than-normal heating degree days. On average, the first quarter
of 2019 turned out to be milder than normal, however prices in the day-ahead and real-time markets during this time
were less volatile than they had been in the first quarter of 2018, which in aggregate positively affected our gross
margin.
During the third quarter of 2019, we experienced warmer than normal weather across many of our markets, which
increased demand for electricity from our customer base. In anticipation of increased demand and volatility in
ERCOT ("Electric Reliability Council of Texas"), and as an additional form of insurance, we purchased additional
power to mitigate the volatility observed in late August and early September of 2019. These factors had a positive
impact on our electricity unit margins in the third quarter of 2019.
Asset Optimization
Our asset optimization opportunities primarily arise during the winter heating season when demand for natural gas
is typically at its highest. Given the opportunistic nature of these activities and because we account for these
activities using the mark to market method of accounting, we experience variability in our earnings from our asset
optimization activities from year to year.
Net asset optimization resulted in a gain of $2.8 million, a gain of $4.5 million and a loss of $0.7 million for the
years ended December 31, 2019, 2018 and 2017, respectively.
44
Non-GAAP Performance Measures
We use the Non-GAAP performance measures of Adjusted EBITDA and Retail Gross Margin to evaluate and
measure our operating results. These measures for the three years ended December 31, 2019 were as follows:
(in thousands)
Adjusted EBITDA
Retail Gross Margin
Year Ended December 31,
2019
2018
2017
$
$
92,404
220,740
$
$
70,716
185,109
$
$
102,884
224,509
Adjusted EBITDA. We define “Adjusted EBITDA” as EBITDA less (i) customer acquisition costs incurred in the
current period, plus or minus (ii) net gain (loss) on derivative instruments, and (iii) net current period cash
settlements on derivative instruments, plus (iv) non-cash compensation expense, and (v) other non-cash and non-
recurring operating items. EBITDA is defined as net income (loss) before the provision for income taxes, interest
expense and depreciation and amortization.
We deduct all current period customer acquisition costs (representing spending for organic customer acquisitions) in
the Adjusted EBITDA calculation because such costs reflect a cash outlay in the period in which they are incurred,
even though we capitalize and amortize such costs over two years. We do not deduct the cost of customer
acquisitions through acquisitions of businesses or portfolios of customers in calculating Adjusted EBITDA.
We deduct our net gains (losses) on derivative instruments, excluding current period cash settlements, from the
Adjusted EBITDA calculation in order to remove the non-cash impact of net gains and losses on these instruments.
We also deduct non-cash compensation expense that results from the issuance of restricted stock units under our
long-term incentive plan due to the non-cash nature of the expense. Finally, we also adjust from time to time other
non-cash or unusual and/or infrequent charges due to either their non-cash nature or their infrequency.
We believe that the presentation of Adjusted EBITDA provides information useful to investors in assessing our
liquidity and financial condition and results of operations and that Adjusted EBITDA is also useful to investors as a
financial indicator of our ability to incur and service debt, pay dividends and fund capital expenditures. Adjusted
EBITDA is a supplemental financial measure that management and external users of our consolidated financial
statements, such as industry analysts, investors, commercial banks and rating agencies, use to assess the following:
•
•
•
•
our operating performance as compared to other publicly traded companies in the retail energy industry,
without regard to financing methods, capital structure or historical cost basis;
the ability of our assets to generate earnings sufficient to support our proposed cash dividends;
our ability to fund capital expenditures (including customer acquisition costs) and incur and service debt;
and
our compliance with financial debt covenants. (Refer to Note 10 "Debt" in the Company’s audited
consolidated financial statements for discussion of the material terms of our Senior Credit Facility,
including the covenant requirements for our Minimum Fixed Charge Coverage Ratio, Maximum Total
Leverage Ratio, and Maximum Senior Secured Leverage Ratio.)
The GAAP measures most directly comparable to Adjusted EBITDA are net income (loss) and net cash provided by
(used in) operating activities. The following table presents a reconciliation of Adjusted EBITDA to these GAAP
measures for each of the periods indicated.
45
(in thousands)
Reconciliation of Adjusted EBITDA to Net Income (Loss):
Year Ended December 31,
2019
2018
2017
Net income (loss)
Depreciation and amortization
Interest expense
Income tax expense
EBITDA
Less:
Net, (Losses) gains on derivative instruments
Net, Cash settlements on derivative instruments
Customer acquisition costs
Plus:
Non-cash compensation expense
Non-recurring legal and regulatory settlements
Gain on disposal of eRex
Change in Tax Receivable Agreement liability (1)
$
14,213
$
40,987
8,621
7,257
71,078
(67,749)
42,820
18,685
5,487
14,457
(4,862)
—
(14,392) $
52,658
9,410
2,077
49,753
(18,170)
(10,587)
13,673
5,879
—
—
—
75,044
42,341
11,134
38,765
167,284
5,008
16,309
25,874
5,058
—
—
(22,267)
Adjusted EBITDA
$
92,404
$
70,716
$
102,884
(1) Represents the change in the value of the Tax Receivable Agreement liability due to U.S. Tax Reform. See discussion in Note 13
"Income Taxes."
The following table presents a reconciliation of Adjusted EBITDA to net cash provided by operating activities for
each of the periods indicated.
(in thousands)
Reconciliation of Adjusted EBITDA to net cash provided by
operating activities:
Net cash provided by operating activities
Amortization of deferred financing costs
Bad debt expense
Interest expense
Income tax expense
Change in Tax Receivable Agreement liability (1)
Changes in operating working capital
Accounts receivable, prepaids, current assets
Inventory
Accounts payable and accrued liabilities
Other
Adjusted EBITDA
Cash Flow Data:
Cash flows provided by operating activities
Cash flows provided by (used in) investing activities
Cash flows (used in) provided by financing activities
Year Ended December 31,
2019
2018
2017
$
$
$
$
$
91,735
(1,275)
(13,532)
8,621
7,257
—
(33,475)
(924)
11,534
22,463
92,404
91,735
1,398
$
$
$
$
59,763
(1,291)
(10,135)
9,410
2,077
—
10,482
(674)
(5,093)
6,177
70,716
59,763
$
$
$
(18,981) $
(85,103) $
(20,563) $
62,131
(1,035)
(6,550)
11,134
38,765
(22,267)
31,905
718
(13,672)
1,755
102,884
62,131
(77,558)
25,886
(1) Represents the change in the value of the Tax Receivable Agreement liability due to U.S. Tax Reform. See discussion in Note 13
"Income Taxes."
46
Retail Gross Margin. We define retail gross margin as operating income (loss) plus (i) depreciation and
amortization expenses and (ii) general and administrative expenses, less (iii) net asset optimization revenues
(expenses), (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 segments. As an indicator of our retail energy business’s operating performance, retail gross margin
should not be considered an alternative to, or more meaningful than, operating income (loss), its most directly
comparable financial measure calculated and presented in accordance with GAAP.
We believe retail gross margin provides information useful to investors as an indicator of our retail energy
business's operating performance.
The GAAP measure most directly comparable to Retail Gross Margin is operating income (loss). The following
table presents a reconciliation of Retail Gross Margin to operating income (loss) for each of the periods indicated.
(in thousands)
Reconciliation of Retail Gross Margin to Operating Income (Loss):
Operating income (loss)
Plus:
Depreciation and amortization
General and administrative expense
Less:
Net asset optimization revenue (expense)
(Losses) gains on non-trading derivative instruments
Cash settlements on non-trading derivative instruments
Retail Gross Margin
Retail Gross Margin - Retail Electricity Segment
Retail Gross Margin - Retail Natural Gas Segment
Year Ended December 31,
2018
2019
2017
$
23,979
$
(3,654) $
102,420
40,987
133,534
2,771
(67,955)
42,944
220,740
160,540
60,200
$
$
$
52,658
111,431
4,511
(19,571)
(9,614)
185,109
124,668
60,441
$
$
$
42,341
101,127
(717)
5,588
16,508
224,509
158,468
66,041
$
$
$
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 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.
47
Consolidated Results of Operations
(In Thousands)
Revenues:
Retail revenues
Net asset optimization revenues (expenses)
Total Revenues
Operating Expenses:
Retail cost of revenues
General and administrative expense
Depreciation and amortization
Total Operating Expenses
Operating income (loss)
Other (expense)/income:
Interest expense
Change in Tax Receivable Agreement liability (1)
Gain on disposal of eRex
Total other income/(expense)
Total other (expenses)/income
Income (loss) before income tax expense
Income tax expense
Net income (loss)
Other Performance Metrics:
Adjusted EBITDA (2)
Retail Gross Margin (2)
Customer Acquisition Costs
RCE Attrition
Distributions paid to Class B non-controlling unit holders and
dividends paid to Class A common shareholders
Year Ended December 31,
2019
2018
2017
$
810,954
$
1,001,417
$
2,771
813,725
615,225
133,534
40,987
789,746
23,979
(8,621)
—
4,862
1,250
(2,509)
21,470
7,257
14,213
92,404
220,740
18,685
$
$
4,511
1,005,928
845,493
111,431
52,658
1,009,582
(3,654)
(9,410)
—
—
749
(8,661)
(12,315)
2,077
(14,392)
70,716
185,109
13,673
$
$
$
$
798,772
(717)
798,055
552,167
101,127
42,341
695,635
102,420
(11,134)
22,267
—
256
11,389
113,809
38,765
75,044
102,884
224,509
25,874
5.0%
4.7%
4.3%
$
(45,176)
$
(45,261)
$
(43,319)
(1) Represents the change in the value of the Tax Receivable Agreement liability due to U.S. Tax Reform. See discussion in Note 13
"Income Taxes."
(2) Adjusted EBITDA and Retail Gross Margin are non-GAAP financial measures. See “—Non-GAAP Performance Measures” for a
reconciliation of Adjusted EBITDA and Retail Gross Margin to their most directly comparable GAAP financial measures.
Total Revenues. Total revenues for the year ended December 31, 2019 were approximately $813.7 million, a
decrease of approximately $192.2 million, or 19%, from approximately $1,005.9 million for the year ended
December 31, 2018. This decrease was primarily due to a decrease in electricity and natural gas volumes as a result
of a smaller C&I customer book in 2019 as compared to 2018, partially offset by an increase in electricity unit
revenue per MWh. Total revenues for the year ended December 31, 2018 increased approximately $207.8 million,
or 26%, from approximately $798.1 million for the year ended December 31, 2017. This increase was primarily due
to an increase in electricity volumes driven by the acquisitions of the HIKO and two customer portfolios, full year
results from the Verde Companies, and higher-than-normal electricity and natural gas pricing in 2018, partially
offset by a decrease in natural gas volumes due to warmer-than-normal weather in the second and third quarters of
2018.
Analysis of the impact of changes in prices and volumes between the years ended December 31, 2019, 2018 and
2017 are as follows:
48
Change in electricity volumes sold
Change in natural gas volumes sold
Change in electricity unit revenue per MWh
Change in natural gas unit revenue per MMBtu
Change in net asset optimization (expense) revenue
Change in total revenues
2019 vs. 2018
2018 vs. 2017
$
$
(221.5)
(18.4)
46.5
2.9
(1.7)
(192.2)
$
$
182.5
(11.1)
23.4
7.9
5.1
207.8
Retail Cost of Revenues. Total retail cost of revenues for the year ended December 31, 2019 was approximately
$615.2 million, a decrease of approximately $230.3 million, or 27%, from approximately $845.5 million for the
year ended December 31, 2018. This decrease was primarily due to a decrease in electricity and natural gas volumes
as a result of a smaller C&I customer book in 2019, a decrease in electricity and natural gas unit cost, and a change
in fair value of our retail derivative portfolio. Total retail cost of revenues for the year ended December 31, 2018
increased approximately $293.3 million, or 53%, from approximately $552.2 million for the year ended
December 31, 2017. This increase was primarily due to an increase in electricity volumes driven by the acquisitions
of HIKO and two customer portfolios, full year results from the Verde Companies, higher-than-normal electricity
and natural gas prices due to the extreme unpredictable weather in the first quarter of 2018, increased capacity costs
in the second and third quarters of 2018, and additional hedges in ERCOT in the third quarter of 2018.
Analysis of the impact of changes in prices and volumes between the years ended December 31, 2019, 2018, and
2017 are as follows:
Change in electricity volumes sold
Change in natural gas volumes sold
Change in electricity unit cost per MWh
Change in natural gas unit cost per MMBtu
Change in value of retail derivative portfolio
Change in retail cost of revenues
2019 vs. 2018
2018 vs. 2017
$
$
(189.5)
(10.3)
(21.4)
(4.9)
(4.2)
(230.3)
$
$
138.5
(5.9)
101.2
8.2
51.3
293.3
General and Administrative Expense. General and administrative expense for the year ended December 31, 2019
was approximately $133.5 million, an increase of approximately $22.1 million, or 20%, as compared to $111.4
million for the year ended December 31, 2018. This increase was primarily attributable to non-recurring legal and
regulatory settlements and increased litigation expense in 2019. General and administrative expense for the year
ended December 31, 2018 increased approximately $10.3 million or 10%, as compared to $101.1 million for the
year ended December 31, 2017. This increase was primarily attributable to reductions in the fair value of earnout
liabilities, which decreased general and administrative expenses in 2017 to a greater extent than in 2018, increased
commissions paid to commercial brokers, and variable costs associated with increased RCEs from our acquisitions.
Depreciation and Amortization Expense. Depreciation and amortization expense for the year ended December 31,
2019 was approximately $41.0 million, a decrease of approximately $11.7 million, or 22%, from approximately
$52.7 million for the year ended December 31, 2018. This decrease was primarily due to the decreased amortization
expense associated with customer relationship intangibles. Depreciation and amortization expense for the year
ended December 31, 2018 increased approximately $10.4 million, or 24%, from approximately $42.3 million for
the year ended December 31, 2017. This increase was primarily due to the increased amortization expense
associated with customer relationship intangibles from the acquisitions of the Verde Companies, HIKO and
customers from an affiliate, and the write-off of assets no longer in use as a result of integration activities.
Customer Acquisition Cost. Customer acquisition cost for the year ended December 31, 2019 was approximately
$18.7 million, an increase of approximately $5.0 million, or 37% from approximately $13.7 million for the year
ended December 31, 2018. This increase was primarily due to an increase in the number of organic sales in 2019 as
49
compared to 2018, as we had slowed our organic sales in 2018 to concentrate on acquisitions of companies and
portfolios of customers. Customer acquisition cost for the year ended December 31, 2018 decreased approximately
$12.2 million, or 47% from approximately $25.9 million for the year ended December 31, 2017. This decrease was
primarily due to a decrease in the number of organic sales in 2018 as we were more focused on acquisitions of
businesses, customer portfolio additions, and integration.
50
Operating Segment Results
Year Ended December 31,
2019
2018
2017
(in thousands, except volume and per unit operating data)
Retail Electricity Segment
Total Revenues
Retail Cost of Revenues
Less: Net (Losses) Gains on non-trading derivatives, net of
cash settlements
Retail Gross Margin (1) —Electricity
Volumes—Electricity (MWhs)
Retail Gross Margin (2) —Electricity per MWh
Retail Natural Gas Segment
Total Revenues
Retail Cost of Revenues
Less: Net (Losses) Gains on non-trading derivatives, net of
cash settlements
Retail Gross Margin (1) —Gas
Volumes—Gas (MMBtus)
Retail Gross Margin (2) —Gas per MMBtu
$
$
$
$
$
$
688,451
$
863,451
$
552,250
762,771
(24,339)
160,540
6,416,568
25.02
$
$
(23,988)
124,668
8,630,653
14.44
$
$
122,503
$
137,966
$
62,975
(672)
60,200
14,543,563
4.14
$
$
82,722
(5,197)
60,441
16,778,393
3.60
$
$
657,566
477,012
22,086
158,468
6,755,663
23.46
141,206
75,155
10
66,041
18,203,684
3.63
(1) Reflects the Retail Gross Margin attributable to our Retail Electricity Segment or Retail Natural Gas Segment, as applicable. Retail
Gross Margin is a non-GAAP financial measure. See “—Non-GAAP Performance Measures” for a reconciliation of Retail Gross Margin
to most directly comparable financial measures presented in accordance with GAAP.
(2) Reflects the Retail Gross Margin for the Retail Electricity Segment or Retail Natural Gas Segment, as applicable, divided by the total
volumes in MWh or MMBtu, respectively.
Retail Electricity Segment
Total revenues for the Retail Electricity Segment for the year ended December 31, 2019 were approximately $688.5
million, a decrease of approximately $175.0 million, or 20%, from approximately $863.5 million for the year ended
December 31, 2018. This decrease was largely due to lower volumes sold, resulting in a decrease of $221.5 million
as a result of a smaller C&I customer book in 2019. This decrease was partially offset by higher weighted average
electricity rates, due to our customer mix shifting away from large C&I customers, which resulted in an increase of
$46.5 million. Total revenues for the Retail Electricity Segment for the year ended December 31, 2018 increased
approximately $205.9 million, or 31%, from approximately $657.6 million for the year ended December 31, 2017.
This increase was largely due to an increase in volumes, a result of our acquisitions of HIKO and two customer
portfolios, full year results from the Verde Companies, a larger C&I customer book in 2018, extreme cold weather
in the first quarter of 2018, and warmer than normal weather in the second and third quarters of 2018, resulting in
an increase of $182.5 million. This increase was further impacted by the higher electricity pricing environment,
which resulted in an increase of $23.4 million.
Retail cost of revenues for the Retail Electricity Segment for the year ended December 31, 2019 was approximately
$552.3 million, a decrease of approximately $210.5 million, or 28%, from approximately $762.8 million for the
year ended December 31, 2018. This decrease was primarily due to a decrease in volumes, resulting in a decrease of
$189.5 million. This decrease was further impacted by decreased electricity supply costs, which resulted in a
decrease in retail cost of revenues of $21.4 million. Additionally, there was an increase of $0.4 million due to a
change in the value of our retail derivative portfolio used in hedging. Retail cost of revenues for the Retail
Electricity Segment for the year ended December 31, 2018 increased approximately $285.8 million, or 60%, from
approximately $477.0 million for the year ended December 31, 2017. This increase was primarily due to an increase
in volumes as a result of the acquisitions of HIKO and two customers portfolios, full year results from the Verde
51
Companies, a larger C&I customer book in 2018, extreme cold weather in the first quarter of 2018, and warmer
than normal weather in second and third quarter of 2018, resulting in an increase of $138.5 million. This increase
was further impacted by increased electricity prices, REC requirements and capacity costs, which resulted in an
increase in retail cost of revenues of $101.2 million. Additionally, there was an increase of $46.1 million due to a
change in the value of our retail derivative portfolio used in hedging.
Retail gross margin for the Retail Electricity Segment for the year ended December 31, 2019 increased
approximately $35.8 million, or 29%, as compared to the year ended December 31, 2018, and 2018 decreased
approximately $33.8 million or 21% as compared to December 31, 2017 as indicated in the table below (in
millions).
Change in volumes sold
Change in unit margin per MWh
Change in retail electricity segment retail gross margin
2019 vs. 2018
2018 vs. 2017
$
$
(32.0)
67.8
35.8
$
$
44.0
(77.8)
(33.8)
Unit margins were positively impacted in 2019 compared to prior year primarily as a result of the higher volumes
from our residential customers, which tend to have higher unit margins than our C&I customers. Unit margins were
negatively impacted in 2018 compared to prior year primarily as a result of higher volumes from our C&I
customers.
The volumes of electricity sold decreased from 8,630,653 MWh for the year ended December 31, 2018 to 6,416,568
MWh for the year ended December 31, 2019. This decrease was primarily due to a smaller C&I customer book in
2019. The volumes of electricity sold increased from 6,755,663 MWh for the year ended December 31, 2017 to
8,630,653 MWh for the year ended December 31, 2018. This increase was primarily due to our acquisitions of
HIKO and two customer portfolios, full year results from the Verde Companies, a larger C&I customer book in
2018, extreme cold weather in the first quarter of 2018, and warmer than normal weather in the second and third
quarters of 2018.
Retail Natural Gas Segment
Total revenues for the Retail Natural Gas Segment for the year ended December 31, 2019 were approximately
$122.5 million, a decrease of approximately $15.5 million, or 11%, from approximately $138.0 million for the year
ended December 31, 2018. This decrease was primarily attributable to a decrease in volumes of $18.4 million,
offset by higher rates, which resulted in an increase in total revenues of $2.9 million. Total revenues for the Retail
Natural Gas Segment for the year ended December 31, 2018 decreased by approximately $3.2 million, or 2%, from
approximately $141.2 million for the year ended December 31, 2017. This decrease was primarily attributable to an
increase in price of $7.9 million, offset by a decrease in customer sales volume, which decreased total revenues by
$11.1 million.
Retail cost of revenues for the Retail Natural Gas Segment for the year ended December 31, 2019 were
approximately $63.0 million, a decrease of approximately $19.7 million, or 24%, from approximately $82.7 million
for the year ended December 31, 2018. This decrease was primarily due to decreased supply costs of $4.9 million, a
decrease of $10.3 million related to decreased volumes, and a decrease of $4.5 million due to change in the fair
value of our retail derivative portfolio used for hedging. Retail cost of revenues for the Retail Natural Gas Segment
for the year ended December 31, 2018 increased approximately $7.5 million, or 10%, from approximately $75.2
million for the year ended December 31, 2017. This increase was due to increased supply costs of $8.2 million, $5.2
million change in the fair value of our retail derivative portfolio used for hedging, offset by $5.9 million related to
decreased volumes.
Retail gross margin for the Retail Natural Gas Segment for the year ended December 31, 2019 decreased by
approximately $0.2 million, or less than 1% from approximately $60.4 million for the year ended December 31,
52
2018, and 2018 decreased approximately $5.6 million or 8% from approximately $66.0 million for the year ended
December 31, 2017 as indicated in the table below (in millions).
Change in volumes sold
Change in unit margin per MMBtu
Change in retail natural gas segment retail gross margin
2019 vs. 2018
2018 vs. 2017
$
$
(8.1)
7.9
(0.2)
$
$
(5.2)
(0.4)
(5.6)
Unit margins were positively impacted in 2019 compared to prior year as a result of higher volumes from our
residential customers, which tend to have higher unit margins than our C&I customers. Unit margins were
negatively impacted in 2018 compared to prior year primarily as a result of higher volume from our C&I customers.
The volumes of natural gas sold decreased from 16,778,393 MMBtu for the year ended December 31, 2018 to
14,543,563 MMBtu for the year ended December 31, 2019. This decrease was primarily due to warmer-than-normal
weather in the second and third quarters of 2019. The volumes of natural gas sold decreased from 18,203,684
MMBtu for the year ended December 31, 2017 to 16,778,393 MMBtu for the year ended December 31, 2018. This
decrease was primarily due to warmer-than-normal weather in the second and third quarters of 2018.
Liquidity and Capital Resources
Overview
Our primary sources of liquidity are cash generated from operations and borrowings under our Senior Credit
Facility. Our principal liquidity requirements are to meet our financial commitments, finance current operations,
fund organic growth and/or acquisitions, service debt and pay dividends. Our liquidity requirements fluctuate with
our level of customer acquisition costs, acquisitions, collateral posting requirements on our derivative instruments
portfolio, distributions, the effects of the timing between the settlement of payables and receivables, including the
effect of bad debts, weather conditions, and our general working capital needs for ongoing operations. We believe
that cash generated from operations and our available liquidity sources will be sufficient to sustain current
operations and to pay required taxes and quarterly cash distributions, including the quarterly dividends to the
holders of the Class A common stock and the Series A Preferred Stock, for the next twelve months. Estimating our
liquidity requirements is highly dependent on then-current market conditions, including weather events, forward
prices for natural gas and electricity, market volatility and our then existing capital structure and requirements.
We believe that the financing of any additional growth through acquisitions and/or the need for more liquidity in the
first half of 2020 may require further equity or debt financing and/or further expansion of our Senior Credit Facility.
Liquidity Position
The following table details our available liquidity as of December 31, 2019:
($ in thousands)
Cash and cash equivalents
Senior Credit Facility Availability (1)
Subordinated Debt Facility Availability (2)
Total Liquidity
December 31,
2019
$
$
56,664
57,068
25,000
138,732
(1) Reflects amount of Letters of Credit that could be issued based on existing covenants as of December 31, 2019.
(2) The availability of the Subordinated Facility is dependent on our Founder's willingness and ability to lend. See "—Sources of Liquidity
—Subordinated Debt Facility."
53
Borrowings and related posting of letters of credit under our Senior Credit Facility are subject to material variations
on a seasonal basis due to the timing of commodity purchases to satisfy natural gas inventory requirements and to
meet customer demands during periods of peak usage. Additionally, borrowings are subject to borrowing base and
covenant restrictions.
Cash Flows
Our cash flows were as follows for the respective periods (in thousands):
Net cash provided by operating activities
Net cash provided by (used in) investing activities
Net cash (used in) provided by financing activities
Year Ended December 31,
2019
2018
2017
$
$
$
91,735
$
1,398
$
(85,103) $
59,763
$
(18,981) $
(20,563) $
62,131
(77,558)
25,886
Cash Flows Provided by Operating Activities. Cash flows provided by operating activities for the year ended
December 31, 2019 increased by $32.0 million compared to the year ended December 31, 2018. The increase was
primarily the result of a higher net income in 2019 coupled with a decrease in the changes in working capital for the
year ended December 31, 2019. Cash flows provided by operating activities for the year ended December 31, 2018
decreased by $2.4 million compared to the year ended December 31, 2017. The decrease was primarily the result of
a decrease in the changes in working capital for the year ended December 31, 2018 and the impact of extreme
weather events during the first quarter of 2018.
Cash Flows Provided by Investing Activities. Cash flows provided by investing activities increased by $20.4 million
for the year ended December 31, 2019. The increase was primarily the result of a reduction in the amount of cash
paid for acquisitions during the year ended December 31, 2019 compared to the year ended December 31, 2018,
and proceeds received from the sale of the Company's equity method investment in 2019. Cash flows used in
investing activities decreased by $58.6 million for the year ended December 31, 2018. The decrease was primarily
the result of the $81.3 million acquisition of the Verde Companies, Perigee and other customers during the year
ended December 31, 2017, offset by the acquisition of HIKO of $14.3 million during the year ended December 31,
2018.
Cash Flows Used in Financing Activities. Cash flows used in financing activities increased by $64.5 million for the
year ended December 31, 2019. The increase in cash flows used in financing activities was primarily due to
increased net paydown of our Senior Credit Facility and subordinated debt, as well as payments to settle the
Company's Tax Receivable Agreement liability. In addition, for the year ended December 31, 2018, we received
proceeds from the issuance of Series A Preferred Stock of approximately $48.5 million, which did not reoccur
during 2019. Cash flows used in financing activities increased by $46.4 million for the year ended December 31,
2018. The increase in cash flows used in financing activities was primarily due to increased net paydown of our
Senior Credit Facility, additional dividends paid to holders of Series A Preferred Stock, payments related to the
Verde Promissory Note and payments associated with the acquisition of customers from an affiliate for the year
ended December 31, 2018.
Sources of Liquidity and Capital Resources
Senior Credit Facility
As of December 31, 2019, we had total commitments of $217.5 million, of which $160.4 million was
outstanding, including $37.4 million of outstanding letters of credit. In January 2019, our total commitments under
our Senior Credit Facility increased to $217.5 million. Under the Senior Credit Facility, we have various limits on
advances for Working Capital Loans, Letters of Credit and Bridge Loans. The Senior Credit Facility matures on
May 19, 2021. For a description of the terms and conditions of our Senior Credit Facility, including descriptions of
the interest rate, commitment fee, covenants and terms of default, please see Note 10 "Debt" in the notes to our
54
consolidated financial statements. As of December 31, 2019, we were in compliance with the covenants under our
Senior Credit Facility.
Amended and Restated Subordinated Debt Facility
Our Subordinated Debt Facility allows us to draw advances in increments of no less than $1.0 million per advance
up to $25.0 million. Although we may use the Subordinated Debt Facility from time to time to enhance short term
liquidity, we do not view the Subordinated Debt Facility as a material source of liquidity. See Note 10 "Debt" for
additional details. As of December 31, 2019, there was zero outstanding borrowings under the Subordinated Debt
Facility.
Uses of Liquidity and Capital Resources
Repayment of Current Portion of Senior Credit Facility
Our Senior Credit Facility matures in 2021, and thus, no amounts are due currently. However, due to the revolving
nature of the facility, excess cash available is generally used to reduce the balance outstanding, which at
December 31, 2019 was $123.0 million. The current variable interest rate on the facility at December 31, 2019 was
4.71%.
Customer Acquisitions
Our customer acquisition strategy consists of customer growth obtained through organic customer additions as well
as opportunistic acquisitions. During the years ended December 31, 2019 and 2018, we spent a total of $18.7
million and $13.7 million, respectively, on organic customer acquisitions. Our ability to grow our customer base
organically or by acquisition is important to our success as we experience ongoing customer attrition each period.
Capital Expenditures
Our capital requirements each year are relatively low and generally consist of minor purchases of equipment or
information system upgrades and improvements. Capital expenditures for the year ended December 31, 2019
included approximately $1.1 million related to information systems improvements.
Dividends and Distributions
For the year ended December 31, 2019, we paid dividends to holders of our Class A common stock of $0.725 per
share or $10.4 million in the aggregate. In order to pay our stated dividends to holders of our Class A common
stock, our subsidiary, Spark HoldCo is required to make corresponding distributions to holders of Class B common
stock (our non-controlling interest holders). As a result, during the year ended December 31, 2019, Spark HoldCo
made distributions of $15.1 million to our non-controlling interest holders related to the dividend payments to our
Class A shareholders.
For the year ended December 31, 2019, we paid $8.1 million of dividends to holders of our Series A Preferred
Stock, and as of December 31, 2019, we had accrued $2.0 million related to dividends to holders of our Series A
Preferred Stock, which we paid on January 15, 2020. For the year ended December 31, 2019, we declared dividends
of $2.1875 per share or $8.1 million in the aggregate on our Series A Preferred Stock.
On January 21, 2020, our Board of Directors declared a quarterly cash dividend in the amount of $0.18125 per
share to holders of our Class A common stock and $0.546875 per share for the Series A Preferred Stock. Dividends
on Class A common stock will be paid on March 16, 2020 to holders of record on March 2, 2020 and Series A
Preferred Stock dividends will be paid on April 15, 2020 to holders of record on April 1, 2020.
55
Our ability to pay dividends in the future will depend on many factors, including the performance of our business
and restrictions under our Senior Credit Facility. If our business does not generate sufficient cash for Spark HoldCo
to make distributions to us to fund our Class A common stock and Series A Preferred Stock dividends, we may have
to borrow to pay such amounts. Further, even if our business generates cash in excess of our current annual
dividend (of $0.725 per share on our Class A common stock), we may reinvest such excess cash flows in our
business and not increase the dividends payable to holders of our Class A common stock. Our future dividend
policy is within the discretion of our Board of Directors and will depend upon the results of our operations, our
financial condition, capital requirements and investment opportunities.
Verde Promissory Note
In January 2018, we issued an amended and restated promissory note to the sellers of the Verde Companies (the
"Verde Promissory Note"). As of December 31, 2018, there was $1.0 million outstanding under the Verde
Promissory Note, all of which was paid in January 2019. The note bore interest at 9% per annum, and we made
monthly payments of principal and associated interest, a portion of which was deposited into an escrow account to
provide security for certain indemnification claims and obligations under the Verde purchase agreement. As of
December 31, 2019 and 2018, a total of $5.3 million and $7.6 million was held in escrow for such claims.
Verde Earnout Termination Note
In January 2018, we issued a promissory note in the principal amount of $5.9 million in connection with an
agreement to terminate the earnout obligation arising in connection with our acquisition of the Verde Companies
(the "Verde Earnout Termination Note"). The Verde Earnout Termination Note matured in June 2019 and bore
interest at a rate of 9% per annum. Under the terms of the Verde Earnout Termination Note, we were permitted to
withhold amounts otherwise due at maturity related to certain indemnifiable matters. A payment of $1.0 million was
made to the seller of the Verde Companies in June 2019, and $4.9 million was withheld (the “Verde Holdback”) to
be applied to indemnifiable matters. As of December 31, 2019 and 2018, there was zero and $5.9 million
outstanding under the Verde Earnout Termination Note, respectively.
56
Summary of Contractual Obligations
The following table discloses aggregate information about our contractual obligations and commercial
commitments as of December 31, 2019 (in millions):
Purchase obligations:
Pipeline transportation agreements
Other purchase obligations (1)
Total purchase obligations
Senior Credit Facility
Debt
Total
2020
2021
2022
2023
2024
> 5 years
$
$
6.6 $
0.9 $
1.5 $
0.7 $
0.7 $
0.7 $
9.4
6.1
2.8
0.5
—
—
16.0 $
7.0 $
4.3 $
1.2 $
0.7 $
0.7 $
$ 123.0 $ — $ 123.0 $ — $ — $ — $
$ 123.0 $ — $ 123.0 $ — $ — $ — $
2.1
—
2.1
—
—
(1) The amounts presented here include contracts for billing services and other software agreements to support our operations.
Off-Balance Sheet Arrangements
As of December 31, 2019, we had no material "off-balance sheet arrangements."
57
Related Party Transactions
For a discussion of related party transactions, see Note 15 "Transactions with Affiliates" in the Company’s audited
consolidated financial statements.
Critical Accounting Policies and Estimates
Our significant accounting policies are described in Note 2 "Basis of Presentation and Summary of Significant
Accounting Policies" to our audited consolidated financial statements. We prepare our financial statements in
conformity with accounting principles generally accepted in the United States of America and pursuant to the rules
and regulations of the SEC, which require us to make estimates and assumptions that affect the amounts reported in
the financial statements and accompanying footnotes. Actual results could differ from those estimates. We consider
the following policies to be the most critical in understanding the judgments that are involved in preparing our
financial statements and the uncertainties that could impact our financial condition and results of operations.
Revenue Recognition and Retail Cost of Revenues
Our revenues are derived primarily from the sale of natural gas and electricity to retail customers. We also record
revenues from sales of natural gas and electricity to wholesale counterparties, including affiliates. Revenues are
recognized when the natural gas or electricity is delivered. Similarly, cost of revenues is recognized when the
commodity is delivered.
In each period, natural gas and electricity that has been delivered but not billed by period is estimated. Accrued
unbilled revenues are based on estimates of customer usage since the date of the last meter read and are provided by
the utility. Volume estimates are based on forecasted volumes and estimated customer usage by class. Unbilled
revenues are calculated by multiplying these volume estimates by the applicable rate by customer class. Estimated
amounts are adjusted when actual usage is known and billed.
The cost of natural gas and electricity for sale to retail customers is similarly based on estimated supply volumes for
the applicable reporting period. In estimating supply volumes, we consider the effects of historical customer
volumes, weather factors and usage by customer class. Transmission and distribution delivery fees, where
applicable, are estimated using the same method used for sales to retail customers. In addition, other load related
costs, such as ISO fees, ancillary services and renewable energy credits are estimated based on historical trends,
estimated supply volumes and initial utility data. Volume estimates are then multiplied by the supply rate and
recorded as retail cost of revenues in the applicable reporting period. Estimated amounts are adjusted when actual
usage is known and billed.
Business Combinations
When we acquire a business or a book of customers, we assign and allocate the purchase price to the identifiable
assets acquired and liabilities assumed based upon their estimated fair value. Generally, the amount recorded in the
financial statements for an acquisition’s assets and liabilities is equal to the purchase price (the fair value of the
consideration paid); however, when the purchase price exceeds the underlying fair value of the net assets acquired,
we recognize goodwill. Conversely, a purchase price that is below the fair value of the net assets acquired will
result in the recognition of a bargain purchase in the income statement.
In addition to the potential for the recognition of goodwill or a bargain purchase, differing fair values will impact
the allocation of the purchase price to the individual assets and liabilities and can impact the gross amount and
classification of assets and liabilities recorded in our consolidated balance sheets, which can impact the timing and
amount of depreciation and amortization expense recorded in any given period.
In estimating fair value, we use discounted cash flow (“DCF”) projections, recent comparable market transactions,
if available, or quoted prices. We consider assumptions that third parties would make in estimating fair value,
58
including, but not limited to, the highest and best use of the asset. There is a significant amount of judgment
involved in cash-flow estimates, including assumptions regarding market convergence, discount rates, commodity
prices, customer attrition, useful lives and growth factors. The assumptions used by another party could differ
significantly from our assumptions.
We utilize our best effort to make our determinations and review all information available, including estimated
future cash flows and prices of similar assets when making our best estimate. We also may hire independent
appraisers or valuation specialists to help us make this determination as we deem appropriate under the
circumstances. Refer to Note 4 "Acquisitions" for further discussion of assumptions used in acquisitions.
There is a significant amount of judgment in determining the fair value of acquisitions and in allocating the
purchase price to individual assets and liabilities. Had different assumptions been used, the fair value of the assets
acquired and liabilities assumed could have been significantly higher or lower with a corresponding increase or
reduction in recognized goodwill, or could have required recognition of a bargain purchase.
In the case of acquisitions that involve potential future contingent consideration, we record on the date of
acquisition a liability equal to the fair value of the estimated additional consideration we may be obligated to pay in
the future. We re-measure this liability each reporting period and record changes in the fair value as general and
administrative expense. Increase or decreases in the fair value of the contingent consideration can result from
changes in in the timing or likelihood of achieving revenue or customer count thresholds. The use of alternative
valuation assumptions, including estimated revenue projections, growth rates, cash flows and discount rates and
alternative estimated probabilities surrounding revenue or customer count thresholds could result in different
expense related to contingent consideration.
Goodwill
As noted above, Goodwill represents the excess of cost over fair value of the assets of businesses. The goodwill on
our consolidated balance sheet as of December 31, 2019 is associated with both our Retail Natural Gas and Retail
Electricity reporting units. We determine our reporting units by identifying each unit that is engaged in business
activities from which it may earn revenues and incur expenses, has operating results regularly reviewed by the
segment manager for purposes of resource allocation and performance assessment, and has discrete financial
information.
Goodwill is assessed for impairment whenever events or circumstances indicate that impairment of the carrying
value of goodwill is likely, but no less often than annually. Our annual assessment, absent a triggering event is as of
October 31 of each year. On October 31, 2019, we elected to perform a qualitative assessment of goodwill in
accordance with guidance from ASC 350. This guidance permits an entity to first assess qualitative factors to
determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as
a basis for determining whether it is necessary to perform the quantitative goodwill impairment test. If we fail the
qualitative test or if we elect to by-pass the qualitative assessment, then we must compare our estimate of the fair
value of a reporting unit with its carrying value, including goodwill. If the carrying value of the reporting unit
exceeds its fair value, we would recognize a goodwill impairment loss for the amount by which the reporting unit’s
carrying value exceeds its fair value. All of these assessments and calculations, including the determination of
whether a triggering event has occurred to undertake an assessment of goodwill involve a high degree of judgment.
We completed our annual assessment of goodwill impairment at October 31, 2019, and the test indicated no
impairment.
Deferred tax assets and liabilities
The Company recognizes the amount of taxes payable or refundable for each tax year. In addition, the Company
follows the asset and liability method of accounting for income taxes where deferred tax assets and liabilities are
recognized for the expected future tax consequences of events that have been recognized in the financial statements
or tax returns and operating loss carryforwards. Deferred tax assets and liabilities are measured using enacted tax
59
rates expected to apply to taxable income in those years in which those temporary differences are expected to be
recovered or settled. The effect on deferred tax assets and liabilities of a change in the tax rates is recognized in
income in the period that includes the enactment date. A valuation allowance is provided for deferred tax assets if it
is more likely than not that these items will not be realized.
In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that
some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is
dependent upon the generation of future taxable income during the periods in which those temporary differences
become deductible. Management considers the projected future taxable income and tax planning strategies in
making this assessment. All of these determinations involve estimates and assumptions.
Recent Accounting Pronouncements
Refer to Note 2 "Basis of Presentation and Summary of Significant Accounting Policies" for a discussion of recent
accounting pronouncements.
Contingencies
In the ordinary course of business, we may become party to lawsuits, administrative proceedings and governmental
investigations, including regulatory and other matters. Liabilities for loss contingencies arising from claims,
assessments, litigation, fines, penalties and other sources are recorded when it is probable that a liability has been
incurred and the amount can be reasonably estimated. For a discussion of the status of current legal and regulatory
matters, see Note 14 "Commitments and Contingencies" in the Company’s audited consolidated financial
statements.
60
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market risks relating to our operations result primarily from changes in commodity prices and interest rates, as well
as counterparty credit risk. We employ established risk management policies and procedures to manage, measure,
and limit our exposure to these risks.
Commodity Price Risk
We hedge and procure our energy requirements from various wholesale energy markets, including both physical and
financial markets and through short and long-term contracts. Our financial results are largely dependent on the
margin we are able to realize between the wholesale purchase price of natural gas and electricity plus related costs
and the retail sales price we charge our customers for these commodities. We actively manage our commodity price
risk by entering into various derivative or non-derivative instruments to hedge the variability in future cash flows
from fixed-price forecasted sales and purchases of natural gas and electricity in connection with our retail energy
operations. These instruments include forwards, futures, swaps, and option contracts traded on various exchanges,
such as NYMEX and Intercontinental Exchange, or ICE, as well as over-the-counter markets. These contracts have
varying terms and durations, which range from a few days to several years, depending on the instrument. We also
utilize similar derivative contracts in connection with our asset optimization activities to attempt to generate
incremental gross margin by effecting transactions in markets where we have a retail presence. Generally, any such
instruments that are entered into to support our retail electricity and natural gas business are categorized as having
been entered into for non-trading purposes, and instruments entered into for any other purpose are categorized as
having been entered into for trading purposes.
Our net loss on our non-trading derivative instruments, net of cash settlements, was $25.0 million for the year ended
December 31, 2019.
We have adopted risk management policies to measure and limit market risk associated with our fixed-price
portfolio and our hedging activities.
We measure the commodity risk of our non-trading energy derivatives using a sensitivity analysis on our net open
position. As of December 31, 2019, our Gas Non-Trading Fixed Price Open Position (hedges net of retail load) was
a short position of 388,833 MMBtu. An increase of 10% in the market prices (NYMEX) from their December 31,
2019 levels would have increased the fair market value of our net non-trading energy portfolio by $0.1 million.
Likewise, a decrease of 10% in the market prices (NYMEX) from their December 31, 2019 levels would have
decreased the fair market value of our non-trading energy derivatives by $0.1 million. As of December 31, 2019,
our Electricity Non-Trading Fixed Price Open Position (hedges net of retail load) was a short position of 182,509
MWhs. An increase of 10% in the forward market prices from their December 31, 2019 levels would have
decreased the fair market value of our net non-trading energy portfolio by $0.4 million. Likewise, a decrease of
10% in the forward market prices from their December 31, 2019 levels would have increased the fair market value
of our non-trading energy derivatives by $0.4 million.
Credit Risk
In many of the utility services territories where we conduct business, Purchase of Receivables ("POR") programs
have been established, whereby the local regulated utility purchases our receivables, and becomes responsible for
billing the customer and collecting payment from the customer. This service results in substantially all of our credit
risk being with the utility and not to our end-use customer in these territories. Approximately 67%, 66% and 66% of
our retail revenues were derived from territories in which substantially all of our credit risk was with local regulated
utility companies as of December 31, 2019, 2018 and 2017, respectively, all of which had investment grade ratings
as of such date. During the same period, we paid these local regulated utilities a weighted average discount of
approximately 0.8%, 1.0% and 1.1%, respectively, of total revenues for customer credit risk protection. In certain of
the POR markets in which we operate, the utilities limit their collections exposure by retaining the ability to transfer
a delinquent account back to us for collection when collections are past due for a specified period.
61
If our collection efforts are unsuccessful, we return the account to the local regulated utility for termination of
service. Under these service programs, we are exposed to credit risk related to payment for services rendered during
the time between when the customer is transferred to us by the local regulated utility and the time we return the
customer to the utility for termination of service, which is generally one to two billing periods. We may also realize
a loss on fixed-price customers in this scenario due to the fact that we will have already fully hedged the customer's
expected commodity usage for the life of the contract.
In non-POR markets (and in POR markets where we may choose to direct bill our customers), we manage customer
credit risk through formal credit review in the case of commercial customers, and credit score screening, deposits
and disconnection for non-payment, in the case of residential customers. Economic conditions may affect our
customers' ability to pay bills in a timely manner, which could increase customer delinquencies and may lead to an
increase in bad debt expense. Our bad debt expense for the year ended December 31, 2019, 2018 and 2017 was
approximately 3.3%, 2.6% and 2.5% of non-POR market retail revenues, respectively. See “Management's
Discussion and Analysis of Financial Condition and Results of Operations—Drivers of Our Business—Customer
Credit Risk” for an analysis of our bad debt expense related to non-POR markets during 2019.
We are exposed to wholesale counterparty credit risk in our retail and asset optimization activities. We manage this
risk at a counterparty level and secure our exposure with collateral or guarantees when needed. At December 31,
2019 and 2018, approximately $0.1 million and $4.1 million of our total exposure of $3.1 million and $22.7
million, respectively, was either with a non-investment grade counterparty or otherwise not secured with collateral
or a guarantee. The credit worthiness of the remaining exposure with other customers was evaluated with no
material allowance recorded at December 31, 2019 and 2018.
Interest Rate Risk
We are exposed to fluctuations in interest rates under our variable-price debt obligations. At December 31, 2019, we
were co-borrowers under the Senior Credit Facility, under which $123.0 million of variable rate indebtedness was
outstanding. Based on the average amount of our variable rate indebtedness outstanding during the year ended
December 31, 2019, a 1% percent increase in interest rates would have resulted in additional annual interest
expense of approximately $1.2 million. We currently have two interest rate swap agreements to manage interest rate
risk.
62
Item 8. Financial Statements and Supplementary Data
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMS
CONSOLIDATED BALANCE SHEETS AS OF DECEMBER 31, 2019 AND DECEMBER 31, 2018
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)
FOR THE YEARS ENDED DECEMBER 31, 2019, 2018 AND 2017
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY FOR THE YEARS ENDED
DECEMBER 31, 2019, 2018 AND 2017
CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31,
2019, 2018 AND 2017
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
64
65
68
70
71
73
75
63
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
It is the responsibility of the management of Spark Energy, Inc. to establish and maintain adequate internal control
over financial reporting. Internal control over financial reporting is defined in Rule 13a-15(f) or 15d-15(f)
promulgated under the Securities Exchange Act of 1934, as amended, as a process designed by, or under the
supervision of, our principal executive and principal financial officers and effected by our board of directors,
management, and other personnel, to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance with generally accepted accounting
principles and includes those policies and procedures that:
• Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect our transactions
and dispositions of the assets;
• Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting principles, and the receipts and expenditures
are being made only in accordance with authorizations of our management and directors; and
• Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use,
or disposition of our assets that could have a material effect on our financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may
deteriorate.
Management has assessed the effectiveness of the Company’s internal control over financial reporting as of
December 31, 2019, utilizing the criteria in the Committee of Sponsoring Organizations of the Treadway Commission’s
Internal Control-Integrated Framework (2013). Based on its assessment, our management concluded the Company’s
internal control over financial reporting was effective as of December 31, 2019.
Ernst & Young LLP, an independent registered public accounting firm, who audited the Company's consolidated
financial statements included in this Form 10-K, has issued an attestation report on the Company's internal control
over financial reporting, which is included herein.
64
Report of Independent Registered Public Accounting Firm
To the Shareholders and the Board of Directors of Spark Energy, Inc.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Spark Energy, Inc. (the Company) as of
December 31, 2019 and 2018, the related consolidated statements of operations and comprehensive income (loss),
changes in equity and cash flows for each of the two years in the period ended December 31, 2019, and the related
notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial
statements present fairly, in all material respects, the financial position of the Company at December 31, 2019 and
2018, and the results of its operations and its cash flows for each of the two years in the period ended December 31,
2019, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board
(United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2019, based
on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (2013 framework) and our report dated March 5, 2020 expressed an
unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an
opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with
the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal
securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the
PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial statements are free of material
misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of
material misstatement of the financial statements, whether due to error or fraud, and performing procedures that
respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and
disclosures in the financial statements. Our audits also included evaluating the accounting principles used and
significant estimates made by management, as well as evaluating the overall presentation of the financial
statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ Ernst & Young LLP
We have served as Spark Energy, Inc.’s auditor since 2018.
Houston, Texas
March 5, 2020
65
Report of Independent Registered Public Accounting Firm
To the Stockholders and the Board of Directors of Spark Energy, Inc.
Opinion on Internal Control over Financial Reporting
We have audited Spark Energy, Inc.’s internal control over financial reporting as of December 31, 2019, based on criteria
established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (2013 framework) (the COSO criteria). In our opinion, Spark Energy, Inc. (the Company) maintained, in all
material respects, effective internal control over financial reporting as of December 31, 2019, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(PCAOB), the consolidated balance sheets of Spark Energy, Inc. as of December 31, 2019 and 2018, and the related
consolidated statements of operations, comprehensive income (loss), changes in equity and cash flows for each of the two years
in the period ended December 31, 2019, and the related notes (collectively referred to as the “consolidated financial
statements”), and our report dated March 5, 2020 expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting included in the accompanying Management Report
on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control
over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be
independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and
regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all
material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material
weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and
performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a
reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures
that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and
dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and directors of the
company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Ernst & Young LLP
Houston, Texas
March 5, 2020
66
Report of Independent Registered Public Accounting Firm
To the Stockholders and Board of Directors
Spark Energy, Inc.:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated statements of operations and comprehensive income (loss), changes in
equity, and cash flows of Spark Energy, Inc. and subsidiaries (the Company) for the year ended December 31, 2017, and
the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial
statements present fairly, in all material respects, the results of the Company’s operations and its cash flows for the year
ended December 31, 2017, in conformity with U.S. generally accepted accounting principles.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express
an opinion on these consolidated financial statements based on our audit. We are a public accounting firm registered with the
Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the
Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and
Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement,
whether due to error or fraud. Our audit included performing procedures to assess the risks of material misstatement of the
consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such
procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial
statements. Our audit also included evaluating the accounting principles used and significant estimates made by management,
as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audit provides a
reasonable basis for our opinion.
/s/ KPMG LLP
We served as the Company’s auditor from 2011 to 2018.
Houston, Texas
March 9, 2018, except for note 3, as to which the date is March 5, 2020.
67
AUDITED CONSOLIDATED FINANCIAL STATEMENTS
SPARK ENERGY, INC.
CONSOLIDATED BALANCE SHEETS AS OF DECEMBER 31, 2019 AND DECEMBER 31, 2018
(in thousands, except share counts)
68
Assets
Current assets:
Cash and cash equivalents
Restricted cash
Accounts receivable, net of allowance for doubtful accounts of $4,797 and $3,353 as of
December 31, 2019 and 2018, respectively
Accounts receivable—affiliates
Inventory
Fair value of derivative assets
Customer acquisition costs, net
Customer relationships, net
Deposits
Renewable energy credit asset
Other current assets
Total current assets
Property and equipment, net
Fair value of derivative assets
Customer acquisition costs, net
Customer relationships, net
Deferred tax assets
Goodwill
Other assets
Total Assets
Liabilities, Series A Preferred Stock and Stockholders' Equity
Current liabilities:
Accounts payable
Accounts payable—affiliates
Accrued liabilities
Renewable energy credit liability
Fair value of derivative liabilities
Current payable pursuant to tax receivable agreement—affiliates
Current contingent consideration for acquisitions
Current portion of note payable
Other current liabilities
Total current liabilities
Long-term liabilities:
Fair value of derivative liabilities
Payable pursuant to tax receivable agreement—affiliates
Long-term portion of Senior Credit Facility
Subordinated debt—affiliate
Other long-term liabilities
Total liabilities
December 31, 2019
December 31, 2018
$
$
$
$
$
$
56,664
1,004
113,635
2,032
2,954
464
8,649
13,607
6,806
24,204
6,109
236,128
3,267
106
9,845
17,767
29,865
120,343
5,647
422,968
48,245
1,009
37,941
33,120
19,943
—
—
—
1,697
141,955
495
—
123,000
—
217
265,667
41,002
8,636
150,866
2,558
3,878
7,289
14,431
16,630
9,226
25,717
11,747
291,980
4,366
3,276
3,893
26,429
27,321
120,343
11,130
488,738
68,790
2,464
10,845
42,805
6,478
1,658
1,328
6,936
647
141,951
106
25,917
129,500
10,000
212
307,686
Commitments and contingencies (Note 14)
Series A Preferred Stock, par value $0.01 per share, 20,000,000 shares authorized, 3,707,256 shares
issued and 3,677,318 shares outstanding at December 31, 2019 and 3,707,256 shares issued and
outstanding at December 31, 2018
90,015
90,758
Stockholders' equity:
Common Stock :
Class A common stock, par value $0.01 per share, 120,000,000 shares authorized,
14,478,999 issued and 14,379,553 outstanding at December 31, 2019 and 14,178,284
issued and 14,078,838 outstanding at December 31, 2018
Class B common stock, par value $0.01 per share, 60,000,000 shares authorized,
20,800,000 issued and outstanding at December 31, 2019 and 20,800,000 issued and
outstanding at December 31, 2018
Additional paid-in capital
Accumulated other comprehensive (loss)/income
Retained earnings
Treasury stock, at cost, 99,446 shares at December 31, 2019 and December 31, 2018
Total stockholders' equity
Non-controlling interest in Spark HoldCo, LLC
Total equity
Total Liabilities, Series A Preferred Stock and stockholders' equity
$
145
142
209
51,842
(40)
1,074
(2,011)
51,219
16,067
67,286
422,968
$
209
46,157
2
1,307
(2,011)
45,806
44,488
90,294
488,738
The accompanying notes are an integral part of the consolidated financial statements.
69
SPARK ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) FOR THE YEARS ENDED
DECEMBER 31, 2019, 2018 and 2017
(in thousands, except per share data)
Year Ended December 31,
2019
2018
2017
Revenues:
Retail revenues
Net asset optimization revenues (expense)
Total revenues
Operating expenses:
Retail cost of revenues
General and administrative
Depreciation and amortization
Total operating expenses
Operating income (loss)
Other (expense)/income:
Interest expense
Change in tax receivable agreement liability
Gain on disposal of eRex
Total other income/(expense)
Total other (expense)/income
Income (loss) before income tax expense
Income tax expense
Net income (loss)
Less: Net income (loss) attributable to non-controlling interest
Net income (loss) attributable to Spark Energy, Inc. stockholders
Less: Dividend on Series A preferred stock
Net income (loss) attributable to stockholders of Class A common
stock
Other comprehensive (loss) income, net of tax:
Currency translation (loss) gain
Other comprehensive (loss) income
Comprehensive income (loss)
Less: Comprehensive income (loss) attributable to non-controlling
interest
Comprehensive income (loss) attributable to Spark Energy, Inc.
stockholders
Net income (loss) attributable to Spark Energy, Inc. per share of Class
A common stock
Basic
Diluted
Weighted average shares of Class A common stock outstanding
Basic
Diluted
$
$
$
$
$
$
$
$
810,954
$
1,001,417
$
2,771
813,725
615,225
133,534
40,987
789,746
23,979
(8,621)
—
4,862
1,250
(2,509)
21,470
7,257
14,213
5,763
8,450
8,091
$
$
4,511
1,005,928
845,493
111,431
52,658
1,009,582
(3,654)
(9,410)
—
—
749
(8,661)
(12,315)
2,077
(14,392) $
(13,206)
(1,186) $
8,109
798,772
(717)
798,055
552,167
101,127
42,341
695,635
102,420
(11,134)
22,267
—
256
11,389
113,809
38,765
75,044
55,799
19,245
3,038
359
$
(9,295) $
16,207
(102)
(102)
14,111
$
31
31
(14,361) $
(59)
(59)
74,985
5,703
(13,188)
55,762
8,408
$
(1,173) $
19,223
0.03
0.02
$
$
(0.69) $
(0.69) $
14,286
14,568
13,390
13,390
1.23
1.21
13,143
13,346
The accompanying notes are an integral part of the consolidated financial statements.
70
SPARK ENERGY, INC.
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2019, 2018 and 2017
(in thousands)
Issued
Shares of
Class A
Common
Stock
Issued
Shares of
Class B
Common
Stock
Treasury
Stock
Class A
Common
Stock
Class B
Common
Stock
Treasury
Stock
Accumulated
Other
Comprehensive
Income (Loss)
Additional
Paid-In
Capital
Retained
Earnings
(Deficit)
Total
Stockholders'
Equity
Non-
controlling
Interest
Total
Equity
12,993
20,450
— $
130 $
206 $
— $
11 $
39,187 $
4,711 $
44,245 $
72,010 $116,255
—
242
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
1,035
—
—
—
—
(99)
—
—
—
2
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
10
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(2,011)
—
—
—
—
—
(22)
—
—
—
—
—
—
—
—
—
—
—
2,754
1,052
—
—
2,754
1,054
—
—
2,754
1,054
—
19,245
19,245
55,799
75,044
—
—
—
—
—
—
708
(2,872)
—
—
6,511
471
—
—
—
—
(22)
(37)
(59)
—
—
—
176
176
(33,800)
(33,800)
274
274
(9,519)
(9,519)
— (9,519)
(3,038)
(3,038)
— (3,038)
—
—
—
—
—
—
708
—
708
(2,872)
— (2,872)
10
7,608
7,618
(2,011)
— (2,011)
6,511
—
6,511
471
(471)
—
13,235
21,485
(99) $
132 $
216 $ (2,011) $
(11) $
47,811 $ 11,399 $
57,536 $
101,559 $159,095
—
258
—
—
—
—
—
—
—
—
3
—
—
—
—
—
—
—
—
—
—
5,703
(1,018)
—
—
5,703
—
5,703
(1,015)
— (1,015)
—
(1,186)
(1,186)
(13,206)
(14,392)
—
—
—
—
—
—
13
—
—
13
18
31
71
Balance at
12/31/2016:
Stock based
compensation
Restricted stock
unit vesting
Consolidated
net income
Foreign
currency
translation
adjustment for
equity method
investee
Beneficial
conversion
feature
Distributions
paid to non-
controlling unit
holders
Net contribution
by NG&E
Dividends paid
to Class A
common
stockholders
($0.725 per
share)
Dividends to
Preferred Stock
Proceeds from
disgorgement of
stockholder
short-swing
profits
Tax receivable
agreement
liability true-up
Conversion of
Convertible
Subordinated
Notes to Class B
Common Stock
Treasury Stock
Remeasurement
of deferred tax
assets
Changes in
ownership
interest
Balance at
12/31/2017:
Stock based
compensation
Restricted stock
unit vesting
Consolidated
net income
Foreign
currency
translation
adjustment for
equity method
investee
Distributions
paid to non-
controlling unit
holders
Dividends paid
to Class A
common
stockholders
($0.725 per
share)
Dividends to
Preferred Stock
Exchange of
shares of Class
B common
stock to shares
of Class A
common stock
Acquisition of
Customers from
Affiliate
Remeasurement
of deferred tax
assets
Changes in
ownership
interest
Balance at
12/31/2018:
Stock based
compensation
Restricted stock
unit vesting
Consolidated
net income
Foreign
currency
translation
adjustment for
equity method
investee
Gain on
settlement of
TRA, net of tax
Distributions
paid to non-
controlling unit
holders
Dividends paid
to Class A
common
stockholders
($0.725 per
share)
Changes in
ownership
interest
Dividends to
Preferred
Shareholders
Proceeds from
disgorgement of
stockholder
short-swing
profits
Acquisition of
Customers from
Affiliate
Balance at
12/31/2019:
—
—
—
—
—
—
—
—
—
—
(35,478)
(35,478)
—
—
—
—
685
(685)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
7
—
—
—
—
—
(7)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(4,932)
(4,851)
(9,783)
— (9,783)
(4,055)
(4,055)
(8,110)
— (8,110)
—
—
1,372
1,276
—
—
—
—
—
—
—
—
(7,129)
(7,129)
1,372
—
1,372
1,276
(1,276)
—
14,178
20,800
(99) $
142 $
209 $ (2,011) $
2 $
46,157 $
1,307 $
45,806 $
44,488 $ 90,294
—
301
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
3
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
5,271
(1,107)
—
—
5,271
—
5,271
(1,104)
— (1,104)
—
8,450
8,450
5,763
14,213
(42)
—
—
11,951
—
—
(42)
(60)
(102)
11,951
— 11,951
—
—
—
—
—
—
—
—
—
(34,794)
(34,794)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(7,776)
(2,606)
(10,382)
— (10,382)
—
(680)
—
(680)
680
—
—
(2,029)
(6,077)
(8,106)
— (8,106)
—
—
55
—
—
—
55
—
—
55
(10)
(10)
14,479
20,800
(99) $
145 $
209 $ (2,011) $
(40) $
51,842 $
1,074 $
51,219 $
16,067 $ 67,286
The accompanying notes are an integral part of the consolidated financial statements.
72
SPARK ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2019, 2018 AND 2017
(in thousands)
Cash flows from operating activities:
Net income (loss)
Adjustments to reconcile net income (loss) to net cash flows provided by operating
activities:
Year Ended December 31,
2019
2018
2017
$
14,213
$
(14,392) $
75,044
Depreciation and amortization expense
Deferred income taxes
Change in TRA liability
Stock based compensation
Amortization of deferred financing costs
Change in fair value of earnout liabilities
Accretion on fair value of earnout liabilities
Excess tax expense (benefit) related to restricted stock vesting
Bad debt expense
Loss (gain) on derivatives, net
Current period cash settlements on derivatives, net
Accretion of discount to convertible subordinated notes to affiliate
Earnout payments
Gain on disposal of eRex
Other
Changes in assets and liabilities:
Decrease (increase) in accounts receivable
Decrease (increase) in accounts receivable—affiliates
Decrease (increase) in inventory
Increase in customer acquisition costs
Decrease (increase) in prepaid and other current assets
Decrease (increase) in other assets
(Decrease) increase in accounts payable and accrued liabilities
(Decrease) increase in accounts payable—affiliates
Decrease in other current liabilities
Increase (decrease) in other non-current liabilities
Decrease in intangible assets—customer acquisitions
Net cash provided by operating activities
Cash flows from investing activities:
Purchases of property and equipment
Cash paid for acquisitions
Acquisition of Starion Customers
Disposal of eRex investment
Net cash provided by (used in) investing activities
Cash flows from financing activities:
Proceeds from (buyback) issuance of Series A Preferred Stock, net of issuance costs paid
Payment to affiliates for acquisition of customer book
Borrowings on notes payable
Payments on notes payable
Earnout Payments
Net paydown on subordinated debt facility
Payments on the Verde promissory note
Restricted stock vesting
Proceeds from disgorgement of stockholders short-swing profits
Payment of Tax Receivable Agreement Liability
Payment of dividends to Class A common stockholders
Payment of distributions to non-controlling unitholders
Payment of Preferred Stock dividends
Purchase of Treasury Stock
Net cash (used in) provided by financing activities
Increase in Cash and cash equivalents and Restricted Cash
Cash and cash equivalents and Restricted cash—beginning of period
Cash and cash equivalents and Restricted cash—end of period
Supplemental Disclosure of Cash Flow Information:
Non-cash items:
Property and equipment purchase accrual
Holdback for Verde Note—Indemnified Matters
$
$
$
73
41,002
(6,929)
—
5,487
1,275
(1,328)
—
50
13,532
67,749
(41,919)
—
—
(4,862)
(776)
23,699
526
924
(18,685)
9,250
55
(8,620)
(1,455)
(1,459)
6
—
91,735
(1,120)
—
(5,913)
8,431
1,398
(743)
(10)
356,000
(362,500)
—
(10,000)
(2,036)
(1,348)
55
(11,239)
(10,382)
(34,794)
(8,106)
—
(85,103)
8,030
49,638
57,668
92
4,900
$
$
$
51,436
(2,328)
—
5,879
1,291
(1,715)
—
(101)
10,135
18,170
11,038
—
—
—
(882)
2,692
859
674
(13,673)
(14,033)
(335)
10,301
(2,158)
(3,050)
41
(86)
59,763
(1,429)
(17,552)
—
—
(18,981)
48,490
(7,129)
417,300
(403,050)
(1,607)
—
(13,422)
(2,895)
244
(6,219)
(9,783)
(35,478)
(7,014)
—
(20,563)
20,219
29,419
49,638
$
42,666
29,821
(22,267)
5,058
1,035
(7,898)
4,108
179
6,550
(5,008)
(19,598)
1,004
(1,781)
—
(5)
(32,361)
(1,459)
(718)
(25,874)
1,915
(465)
14,831
51
(1,210)
(1,487)
—
62,131
(1,704)
(75,854)
—
—
(77,558)
40,241
—
206,400
(152,939)
(18,418)
—
—
(3,091)
1,129
—
(9,519)
(33,800)
(2,106)
(2,011)
25,886
10,459
18,960
29,419
(123) $
— $
91
—
Write-off of tax benefit related to tax receivable agreement liability—affiliates
Gain on settlement of tax receivable agreement liability—affiliates
Net contribution by NG&E in excess of cash
Installment consideration incurred in connection with the Verde Companies acquisition
and Verde Earnout Termination Note
Tax benefit from tax receivable agreement
Liability due to tax receivable agreement
Cash paid during the period for:
Interest
Taxes
$
$
$
$
$
$
$
$
4,384
16,336
$
$
— $
— $
— $
— $
— $
— $
— $
— $
(1,508) $
$
1,642
6,634
7,516
$
$
7,883
8,561
$
$
—
—
274
19,994
(1,802)
4,674
5,715
11,205
The accompanying notes are an integral part of the consolidated financial statements.
74
SPARK ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Formation and Organization
We are an independent retail energy services company that provides residential and commercial customers in
competitive markets across the United States with an alternative choice for natural gas and electricity. The
Company is a holding company whose sole material asset consists of units in Spark HoldCo, LLC (“Spark
HoldCo”). The Company is the sole managing member of Spark HoldCo, is responsible for all operational,
management and administrative decisions relating to Spark HoldCo’s business and consolidates the financial results
of Spark HoldCo and its subsidiaries. Spark HoldCo is the direct and indirect owner of the subsidiaries through
which we operate. We conduct our business through several brands across our service areas, including CenStar
Energy, Electricity Maine, Electricity N.H., HIKO Energy, Major Energy, Oasis Energy, Perigee Energy, Provider
Power Massachusetts, Respond Power, Spark Energy, and Verde Energy.
2. Basis of Presentation and Summary of Significant Accounting Policies
Basis of Presentation
The accompanying consolidated financial statements of the Company have been prepared in accordance with
accounting principles generally accepted in the United States (“GAAP”) and pursuant to the rules and regulations of
the Securities and Exchange Commission (“SEC”). Our financial statements are presented on a consolidated basis
and include all wholly-owned and controlled subsidiaries. We account for investments over which we have
significant influence but not a controlling financial interest using the equity method of accounting. All significant
intercompany transactions and balances have been eliminated in the consolidated financial statements.
In the opinion of the Company's management, the accompanying consolidated financial statements reflect all
adjustments that are necessary to fairly present the financial position, the results of operations, the changes in equity
and the cash flows of the Company for the respective periods. Such adjustments are of a normal recurring nature,
unless otherwise disclosed.
Subsequent Events
Subsequent events have been evaluated through the date these financial statements are issued. Any material
subsequent events that occurred prior to such date have been properly recognized or disclosed in the consolidated
financial statements.
Use of Estimates and Assumptions
The preparation of our consolidated financial statements requires estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated
financial statements and the reported amounts of revenues and expenses during the period. Actual results could
materially differ from those estimates.
Relationship with our Founder and Majority Shareholder
W. Keith Maxwell, III (our "Founder") is the owner of a majority of the voting power of our common stock through
his ownership of NuDevco Retail, LLC ("NuDevco Retail") and Retailco, LLC ("Retailco"). Retailco is a wholly
owned subsidiary of TxEx Energy Investments, LLC ("TxEx"), which is wholly owned by Mr. Maxwell. NuDevco
Retail is a wholly owned subsidiary of NuDevco Retail Holdings LLC ("NuDevco Retail Holdings"), which is a
wholly owned subsidiary of Electric HoldCo, LLC, which is also a wholly owned subsidiary of TxEx.
75
We enter into transactions with and pay certain costs on behalf of affiliates that are commonly controlled by Mr.
Maxwell, and these affiliates enter into transactions with and pay certain costs on our behalf. We undertake these
transactions in order to reduce risk, reduce administrative expense, create economies of scale, create strategic
alliances and supply goods and services among these related parties.
These transactions include, but are not limited to, employee benefits provided through the Company’s benefit plans,
insurance plans, leased office space, certain administrative salaries, management due diligence, recurring
management consulting, and accounting, tax, legal, or technology services. Amounts billed under these
arrangements are based on services provided, departmental usage, or headcount, which are considered reasonable
by management. As such, the accompanying consolidated financial statements include costs that have been incurred
by the Company and then directly billed or allocated to affiliates, and costs that have been incurred by our affiliates
and then directly billed or allocated to us, and are recorded net in general and administrative expense on the
consolidated statements of operations with a corresponding accounts receivable—affiliates or accounts payable—
affiliates, respectively, recorded in the consolidated balance sheets. Additionally, the Company enters into
transactions with certain affiliates for sales or purchases of natural gas and electricity, which are recorded in retail
revenues, retail cost of revenues, and net asset optimization revenues in the consolidated statements of operations
with a corresponding accounts receivable—affiliate or accounts payable—affiliate in the consolidated balance
sheets. The allocations and related estimates and assumptions are described more fully in Note 15 "Transactions
with Affiliates."
Cash and Cash Equivalents
Cash and cash equivalents consist of all unrestricted demand deposits and funds invested in highly liquid
instruments with original maturities of three months or less. The Company periodically assesses the financial
condition of the institutions where these funds are held and believes that its credit risk is minimal with respect to
these institutions.
Accounts Receivable
Trade accounts receivable are recorded at the invoiced amount and do not bear interest.
The Company accrues an allowance for doubtful accounts based upon estimated uncollectible accounts receivable
considering historical collections, accounts receivable aging analysis, credit risk and other factors. The Company
writes off accounts receivable balances against the allowance for doubtful accounts when the accounts receivable is
deemed to be uncollectible. Bad debt expense of $13.5 million, $10.1 million and $6.6 million was recorded in
general and administrative expense in the consolidated statements of operations for the years ended December 31,
2019, 2018 and 2017, respectively.
The Company conducts business in many utility service markets where the local regulated utility purchases our
receivables, and then becomes responsible for billing the customer and collecting payment from the customer
(“POR programs”). This POR service results in substantially all of the Company’s credit risk being linked to the
applicable utility, which generally has an investment-grade rating, and not to the end-use customer. The Company
monitors the financial condition of each utility and currently believes such amounts are collectible. Trade accounts
receivable that are part of a local regulated utility’s POR program are recorded on a gross basis in accounts
receivable in the consolidated balance sheets. The discount paid to the local regulated utilities is recorded in general
and administrative expense in the consolidated statements of operations.
In markets that do not offer POR services or when the Company chooses to directly bill its customers, certain
receivables are billed and collected by the Company. The Company bears the credit risk on these accounts and
records an appropriate allowance for doubtful accounts to reflect any losses due to non-payment by customers. The
Company’s customers are individually insignificant and geographically dispersed in these markets. The Company
writes off customer balances when it believes that amounts are no longer collectible and when it has exhausted all
means to collect these receivables.
76
Inventory
Inventory consists of natural gas used to fulfill and manage seasonality for fixed and variable-price retail customer
load requirements and is valued at the lower of weighted average cost or net realizable value. Purchased natural gas
costs are recognized in the consolidated statements of operations, within retail cost of revenues, when the natural
gas is sold and delivered out of the storage facility using the weighted average cost of the gas sold.
Customer Acquisition Costs
The Company capitalizes direct response advertising costs that consist primarily of hourly and commission-based
telemarketing costs, door-to-door agent commissions and other direct advertising costs associated with proven
customer generation in its balance sheet. These costs are amortized over the estimated life of a customer.
As of December 31, 2019 and 2018, the net customer acquisition costs were $18.5 million and $18.3 million,
respectively, of which $8.7 million and $14.4 million were recorded in current assets, and $9.8 million and $3.9
million were recorded in non-current assets. Amortization of customer acquisition costs was $18.5 million, $24.4
million, and $21.4 million for the years ended December 31, 2019, 2018 and 2017, respectively. Customer
acquisition costs do not include customer acquisitions through merger and acquisition activities, which are recorded
as customer relationships.
Recoverability of customer acquisition costs is evaluated based on a comparison of the carrying amount of such
costs to the future net cash flows expected to be generated by the customers acquired, considering specific
assumptions for customer attrition, per unit gross profit, and operating costs. These assumptions are based on
forecasts and historical experience.
Customer Relationships
Customer contracts recorded as part of mergers or acquisitions are reflected as customer relationships in our balance
sheet. The Company had capitalized customer relationship of $13.6 million and $16.6 million, net of amortization,
as current assets as of December 31, 2019 and 2018, respectively, and $17.8 million and $26.4 million, net of
amortization, as non-current assets as of December 31, 2019 and 2018, respectively, related to these intangible
assets. These intangibles are amortized on a straight-line basis over the estimated average life of the related
customer contracts acquired, which ranges from three to six years.
The acquired customer relationships intangibles related to Oasis, CenStar, Provider Companies, Major Energy
Companies, Perigee Energy LLC, Verde Companies, and HIKO are reflective of the acquired companies’ customer
base, and were valued at the respective dates of acquisition using an excess earnings method under the income
approach. Using this method, the Company estimated the future cash flows resulting from the existing customer
relationships, considering attrition as well as charges for contributory assets, such as net working capital, fixed
assets, and assembled workforce. These future cash flows were then discounted using an appropriate risk-adjusted
rate of return by retail unit to arrive at the present value of the expected future cash flows. CenStar, Oasis, Perigee,
and HIKO customer relationships are amortized to depreciation and amortization based on the expected future net
cash flows by year. The acquired customer relationship intangibles related to the Major Energy Companies, the
Provider Companies and the Verde Companies were bifurcated between hedged and unhedged and amortized to
depreciation and amortization based on the expected future cash flows by year and expensed to retail cost of
revenue based on the expected term of the underlying fixed price contract in each reporting period, respectively.
Customer relationship amortization expense was $18.3 million, $20.3 million, and $17.8 million for the years ended
December 31, 2019, 2018 and 2017, respectively, of which approximately less than $0.1 million, $(1.2) million, and
$0.3 million was included in retail cost of revenue for those years.
We review customer relationships for impairment whenever events or changes in business circumstances indicate
the carrying value of the intangible assets may not be recoverable. Impairment is indicated when the undiscounted
77
cash flows estimated to be generated by the intangible assets are less than their respective carrying value. If an
impairment exists, a loss is recognized for the difference between the fair value and carrying value of the intangible
assets. No impairments of customer relationships were recorded for the years ended December 31, 2019, 2018 and
2017.
Non-compete agreements
We capitalize intangible costs associated with non-compete agreements in certain of our acquisitions. Non-compete
agreements provide the Company with a certain level of assurance that acquired companies' expected earnings
streams will not be disrupted by competition from the companies’ previous owners or members. These non-compete
agreements are amortized over their estimated useful life of three years on a straight-line basis. As of December 31,
2019, the Company had zero capitalized costs related to these non-compete agreements. As of December 31, 2018,
the Company had $0.3 million of capitalized costs related to non-compete agreements, of which $0.3 million was
current, and of which zero was non-current. Amortization expense was $0.3 million, $1.1 million and $1.2 million
for the years ended December 31, 2019, 2018 and 2017.
Trademarks
We record trademarks as part of our acquisitions which represent the value associated with the recognition and
positive reputation of an acquired company to its target markets. This value would otherwise have to be internally
developed through significant time and expense or by paying a third party for its use. These intangibles are
amortized over the estimated five-year to ten-year life of the trademark on a straight-line basis. The fair values of
trademark assets were determined at the date of acquisition using a royalty savings method under the income
approach. Under this approach, the Company estimates the present value of expected cash flows resulting from
avoiding royalty payments to use a third party trademark. The Company analyzes market royalty rates charged for
licensing trademarks and applied an expected royalty rate to a forecast of estimated revenue, which was then
discounted using an appropriate risk adjusted rate of return. As of December 31, 2019 and 2018, we had recorded
$5.7 million and $7.3 million related to these trademarks in other assets. Amortization expense was $1.6 million,
$1.3 million, and $0.8 million for the years ended December 31, 2019, 2018 and 2017, respectively.
We review trademarks for impairment whenever events or changes in business circumstances indicate the carrying
value of the intangible assets may not be recoverable. Impairment is indicated when the undiscounted cash flows
estimated to be generated by the intangible assets are less than their respective carrying value. If an impairment
exists, a loss is recognized for the difference between the fair value and carrying value of the intangible assets. No
impairments of trademarks were recorded for the years ended December 31, 2019, 2018 and 2017.
Operating Leases
The Company's leases consist of operating leases related to our offices with lease terms expiring through 2022. The
initial term for our property leases is typically three to five years, with renewal options. Rent is recognized on a
straight-line basis over the lease term. We adopted ASU 2016-02 effective January 1, 2019, and recorded right-of-
use assets and liabilities for our operating leases of $1.0 million.
For our operating leases, we recorded rent expense of $0.8 million, $0.8 million and $0.6 million for the years
ended December 31, 2019, 2018 and 2017, respectively. We recorded sub-lease income of $0.4 million, zero and
zero for the years ended December 31, 2019, 2018 and 2017, respectively. As of December 31, 2019 we had
recorded right-of-use asset of $0.4 million in other current assets and other assets. As of December 31, 2019 we had
recorded lease liability of $0.6 million in other current liabilities and other long-term liabilities.
Deferred Financing Costs
78
Costs incurred in connection with the issuance of long-term debt are capitalized and amortized to interest expense
using the straight-line method over the life of the related long-term debt. These costs are included in other assets in
our consolidated balance sheets.
Property and Equipment
The Company records property and equipment at historical cost. Depreciation expense is recorded on a straight-line
method based on estimated useful lives, which range from 2 to 5 years, along with estimates of the salvage values
of the assets. When items of property and equipment are sold or otherwise disposed of, any gain or loss is recorded
in the consolidated statements of operations.
The Company capitalizes costs associated with certain of its internal-use software projects. Costs capitalized are
those incurred during the application development stage of projects such as software configuration, coding,
installation of hardware and testing. Costs incurred during the preliminary or post-implementation stage of the
project are expensed in the period incurred, including costs associated with formulation of ideas and alternatives,
training and application maintenance. After internal-use software projects are completed, the associated capitalized
costs are depreciated over the estimated useful life of the related asset. Interest costs incurred while developing
internal-use software projects are also capitalized. Capitalized interest costs for the years ended December 31, 2019,
2018 and 2017 were not material.
Goodwill
Goodwill represents the excess of cost over fair value of the assets of businesses acquired in accordance with FASB
ASC Topic 350 Intangibles-Goodwill and Other ("ASC 350"). The goodwill on our consolidated balance sheet as of
December 31, 2019 is associated with both our Retail Natural Gas and Retail Electricity segments. We determine
our segments, which are also considered our reporting unit, by identifying each unit that engaged in business
activities from which it may earn revenues and incur expenses, had operating results regularly reviewed by the
segment manager for purposes of resource allocation and performance assessment, and had discrete financial
information.
Goodwill is not amortized, but rather is assessed for impairment whenever events or circumstances indicate that
impairment of the carrying value of goodwill is likely, but no less often than annually as of October 31. We
compare our estimate of the fair value of the reporting unit with its carrying value, including goodwill. If the
carrying value of the reporting unit exceeds its fair value, we would recognize a goodwill impairment loss for the
amount by which the reporting unit's carrying value exceeds its fair value. In accordance with our accounting
policy, we completed our annual assessment of goodwill impairment as of October 31, 2019 during the fourth
quarter of 2019, using a qualitative assessment approach, and the test indicated no impairment.
Treasury Stock
Treasury stock consists of Company's own stock that has been issued, but subsequently reacquired by the Company.
Treasury stock does not reduce the number of shares issued but does reduce the number of shares outstanding.
These shares are not eligible to receive cash dividends. We use the cost method to account for treasury shares.
Equity Method Investments
We use the equity method of accounting to account for investments where we have the ability to exercise significant
influence, but not control over, the investee. Under the equity method of accounting, investments are stated at initial
cost and are adjusted for subsequent additional investments and our share of earnings or losses and distributions.
Prior to the sale of our equity investment in November 2019, our equity investment was presented on the
consolidated balance sheet under "Other assets", with our share of their income reflected as "Total other income/
(expense)" on the consolidated statements of operations. We determined our equity investment earnings using the
Hypothetical Liquidation at Book Value (HLBV) method. Under the HLBV method, a calculation was prepared at
79
each balance sheet date to determine the amount the Company would receive if the investee were to liquidate all of
its assets, as valued in accordance with U.S. GAAP, and distribute that cash to the investors. The difference between
the calculated liquidation distribution amounts at the beginning and the end of the reporting period, after adjusting
for capital contributions and distributions, is the Company's share of the earnings or losses from the equity
investment for the period. See Note 17 "Equity Method Investment" for further discussion.
Revenues and Cost of Revenues
Our revenues are derived primarily from the sale of natural gas and electricity to customers, including affiliates.
Revenues are recognized by the Company based on consideration specified in contracts with customers when
performance obligations are satisfied by transferring control over products to a customer . Utilizing these criteria,
revenue is recognized when the natural gas or electricity is delivered to the customer. Similarly, cost of revenues is
recognized when the commodity is delivered.
Revenues for natural gas and electricity sales are recognized under the accrual method. Natural gas and electricity
sales that have been delivered but not billed by period end are estimated. Accrued unbilled revenues are based on
estimates of customer usage since the date of the last meter read provided by the utility. Volume estimates are based
on forecasted volumes and estimated customer usage by class. Unbilled revenues are calculated by multiplying
these volume estimates by the applicable rate by customer class. Estimated amounts are adjusted when actual usage
is known and billed.
Costs for natural gas and electricity sales are similarly recognized under the accrual method. Natural gas and
electricity costs that have not been billed to the Company by suppliers but have been incurred by period end are
estimated. The Company estimates volumes for natural gas and electricity delivered based on the forecasted
revenue volumes, estimated transportation cost volumes and estimation of other costs associated with retail load
that varies by commodity utility territory. These costs include items like ISO fees, ancillary services and renewable
energy credits. Estimated amounts are adjusted when actual usage is known and billed.
Our asset optimization activities, which primarily include natural gas physical arbitrage and other short term storage
and transportation transactions, meet the definition of trading activities and are recorded on a net basis in the
consolidated statements of operations in net asset optimization revenues. The Company recorded asset optimization
revenues, primarily related to physical sales or purchases of commodities, of $62.8 million, $113.7 million and
$178.3 million for the years ended December 31, 2019, 2018 and 2017, respectively, and recorded asset
optimization costs of revenues of $60.0 million, $109.2 million and $179.0 million for the years ended
December 31, 2019, 2018 and 2017, respectively, which are presented on a net basis in asset optimization revenues.
Natural Gas Imbalances
The consolidated balance sheets include natural gas imbalance receivables and payables, which primarily result
when customers consume more or less gas than has been delivered by the Company to local distribution companies
(“LDCs”). The settlement of natural gas imbalances varies by LDC, but typically the natural gas imbalances are
settled in cash or in kind on a monthly, quarterly, semi-annual or annual basis. The imbalances are valued at their
estimated net realizable value. The Company recorded an imbalance receivable of $1.6 million and $0.8 million in
other current assets on the consolidated balance sheets as of December 31, 2019 and 2018, respectively. The
Company recorded an imbalance payable of $0.1 million and $0.3 million in other current liabilities on the
consolidated balance sheets as of December 31, 2019 and 2018, respectively.
Derivative Instruments
The Company uses derivative instruments such as futures, swaps, forwards and options to manage the commodity
price risks of its business operations.
80
All derivatives are recorded in the consolidated balance sheets at fair value. Derivative instruments representing
unrealized gains are reported as derivative assets while derivative instruments representing unrealized losses are
reported as derivative liabilities. We offset amounts in the consolidated balance sheets for derivative instruments
executed with the same counterparty where we have a master netting arrangement.
As part of our asset optimization activities, we manage a portfolio of commodity derivative instruments held for
trading purposes. Changes in fair value of and amounts realized upon settlements of derivatives instruments held for
trading purposes are recognized in earnings in net asset optimization revenues.
To manage the retail business, the Company holds derivative instruments that are not for trading purposes and are
not designated as hedges for accounting purposes. Changes in the fair value of and amounts realized upon
settlement of derivative instruments not held for trading purposes are recognized in retail costs of revenues.
Income Taxes
The Company follows the asset and liability method of accounting for income taxes where deferred tax assets and
liabilities are recognized for the expected future tax consequences of events that have been recognized in the
financial statements or tax returns and operating loss carryforwards. Deferred tax assets and liabilities are measured
using enacted tax rates expected to apply to taxable income in those years in which those temporary differences are
expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in the tax rates is
recognized in income in the period that includes the enactment date. A valuation allowance is provided for deferred
tax assets if it is more likely than not that these items will not be realized. Amounts owed or refundable on current
year returns is included as a current payable or receivable in the consolidated balance sheet.
In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that
some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is
dependent upon the generation of future taxable income during the periods in which those temporary differences
become deductible. Management considers the projected future taxable income and tax planning strategies in
making this assessment.
The Company recognizes interest and penalties related to unrecognized tax benefits within the provision for income
taxes on continuing operations in our consolidated statements of operations.
Earnings per Share
Basic earnings per share (“EPS”) is computed by dividing net income attributable to stockholders (the numerator)
by the weighted-average number of Class A common shares outstanding for the period (the denominator). Class B
common shares are not included in the calculation of basic earnings per share because they are not participating
securities and have no economic interests. Diluted earnings per share is similarly calculated except that the
denominator is increased by potentially dilutive securities. We use the treasury stock method to determine the
potential dilutive effect of our outstanding unvested restricted stock units and use the if-converted method to
determine the potential dilutive effect of our Class B common stock.
Non-controlling Interest
Net income attributable to non-controlling interest represents the Class B Common stockholders' interest in income
and expenses of the Company. The weighted average ownership percentages for the applicable reporting period are
used to allocate the income (loss) before income taxes to each economic interest owner.
Commitments and Contingencies
81
Liabilities for loss contingencies arising from claims, assessments, litigation, fines, penalties and other sources are
recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Legal
costs incurred in connection with loss contingencies are expensed as incurred.
Recent Accounting Pronouncements
In January 2017, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update
("ASU") No. 2017-04, Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment
("ASU 2017-04"). ASU 2017-04 simplifies the subsequent measurement of goodwill by eliminating Step 2 from the
goodwill impairment test. Under this update, an entity should perform its annual or interim goodwill impairment
test by comparing the fair value of a reporting unit with its carrying amount, including goodwill. An entity should
recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit's fair
value. However, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit.
ASU 2017-04 should be applied on a prospective basis and is effective for annual or any interim goodwill
impairment tests in fiscal years beginning after December 15, 2019. Early adoption is permitted for interim or
annual goodwill impairment tests performed on testing dates after January 1, 2017. We adopted ASU 2017-04
effective January 1, 2019, and the adoption of this standard did not have a material impact on the Company's
consolidated financial statements.
In June 2018, the FASB issued ASU No. 2018-07, Compensation - Stock Compensation (Topic 718): Improvements
to Non-employee Share-Based Payment Accounting ("ASU 2018-07"). ASU 2018-07 primarily expands the scope
of Topic 718 to include share-based payment transactions for acquiring goods and services from non-employees.
ASU 2018-07 is effective for fiscal years beginning after December 15, 2018, including interim periods within that
fiscal year. We adopted ASU 2018-07 effective January 1, 2019, and the adoption of this standard did not have a
material impact on the Company's consolidated financial statements.
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) ("ASU 2016-02"). Under this new
guidance, lessees are required to recognize assets and liabilities on the balance sheet for the rights and obligations
created by all leases with terms of greater than twelve months. The guidance requires qualitative disclosures along
with certain specific quantitative disclosures for both lessees and lessors. The FASB issued ASU No.
2018-10, Codification Improvements to Topic 842, Leases, ASU No. 2018-11, Leases (Topic 842): Targeted
Improvements, and ASU No. 2019-01, Leases (Topic 842): Codification Improvements, to provide additional
guidance for the adoption of Topic 842. ASU 2016-02 and its related amendments are effective for fiscal years
beginning after December 15, 2018, with early adoption permitted, and are effective for interim periods in the year
of adoption. ASU 2016-02 should be applied using a modified retrospective approach, which requires lessees and
lessors to recognize and measure leases at the beginning of the earliest period presented with an option to use
certain practical expedients, which we elected to use. We evaluated the impact of this new guidance and reviewed
lease or possible lease contracts and evaluated contract related processes. We adopted ASU 2016-02 effective
January 1, 2019 and recorded right-of-use assets and liabilities for our real estate operating leases of
approximately $1.0 million.
Standards Being Evaluated/Standards Not Yet Adopted
Below are accounting standards that have been issued, but not yet been adopted by the Company at December 31,
2019. The Company considers the applicability and impact of all ASUs. ASUs not listed below were assessed and
determined to be either not applicable or are expected to have minimal impact on our consolidated financial
statements.
In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement
of Credit Losses on Financial Instruments ("ASU 2016-13"). ASU 2016-13 requires entities to use a current
expected credit loss ("CECL") model, which is a new impairment model based on expected losses rather than
incurred losses on financial assets, including trade accounts receivables. The model requires financial assets
measured at amortized cost to be presented at the net amount expected to be collected. ASU 2016-13 is effective for
82
fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. We adopted
ASU 2016-13 and related amendments effective January 1, 2020, and the adoption did not have a material impact
on our consolidated financial statements.
In December 2019, the FASB issued ASU No. 2019-12, Income Taxes (Topic 740), Simplifying the Accounting for
Income Taxes ("ASU 2019-12"). These amendments simplify the accounting for income taxes by removing certain
exceptions to the general principles in Topic 740. For public business entities, the amendments in this Update are
effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020. We do
not expect adoption of the new standard to have a material impact to our consolidated statement of operations.
3. Revenues
Our revenues are derived primarily from the sale of natural gas and electricity to customers, including affiliates.
Revenue is measured based upon the quantity of gas or power delivered at prices contained or referenced in the
customer's contract, and excludes any sales incentives (e.g. rebates) and amounts collected on behalf of third parties
(e.g. sales tax).
Our revenues also include asset optimization activities. Asset optimization activities consist primarily of purchases
and sales of gas that meet the definition of trading activities per FASB ASC Topic 815, Derivatives and
Hedging. They are therefore excluded from the scope of FASB ASC Topic 606, Revenue from Contracts with
Customers.
Revenues for electricity and natural gas sales are recognized under the accrual method when our performance
obligation to a customer is satisfied, which is the point in time when the product is delivered and control of the
product passes to the customer. Electricity and natural gas products may be sold as fixed-price or variable-price
products. The typical length of a contract to provide electricity and/or natural gas is 12 months. Customers are
billed and typically pay at least monthly, based on usage. Electricity and natural gas sales that have been delivered
but not billed by period end are estimated and recorded as accrued unbilled revenues based on estimates of
customer usage since the date of the last meter read provided by the utility. Volume estimates are based on
forecasted volumes and estimated residential and commercial customer usage. Unbilled revenues are calculated by
multiplying these volume estimates by the applicable rate by customer class (residential or commercial). Estimated
amounts are adjusted when actual usage is known and billed.
The following table discloses revenue by primary geographical market, customer type, and customer credit risk
profile (in thousands). The table also includes a reconciliation of the disaggregated revenue to revenue by reportable
segment (in thousands).
83
Reportable Segments
Year Ended December 31, 2019
Year Ended December 31, 2018
Year Ended December 31, 2017
Retail
Electricity
Retail
Natural
Gas
Total
Reportable
Segments
Retail
Electricity
Retail
Natural
Gas
Total
Reportable
Segments
Retail
Electricity
Retail
Natural
Gas
Total
Reportable
Segments
Primary
markets (a)
New England $
284,909 $
19,289 $
304,198
$
395,682 $
21,221 $
416,903
$
229,546 $
21,196 $
250,742
Mid-Atlantic
242,556
Midwest
Southwest
79,188
81,798
42,469
39,200
21,545
285,025
118,388
103,343
291,046
73,167
103,556
54,815
39,894
22,036
345,861
113,061
125,592
272,127
59,506
96,387
52,737
37,792
29,481
324,864
97,298
125,868
$
688,451 $
122,503 $
810,954
$
863,451 $
137,966 $ 1,001,417
$
657,566 $
141,206 $
798,772
Customer type
Commercial
$
249,730 $
40,466 $
290,196
$
355,607 $
50,156 $
405,763
$
195,356 $
50,424 $
245,780
Residential
449,900
83,455
533,355
518,261
93,186
611,447
441,580
89,889
531,469
(11,179)
(1,418)
(12,597)
(10,417)
(5,376)
(15,793)
20,630
893
21,523
$
688,451 $
122,503 $
810,954
$
863,451 $
137,966 $ 1,001,417
$
657,566 $
141,206 $
798,772
Unbilled
revenue (b)
Customer
credit risk
POR
$
479,011 $
64,416 $
543,427
$
586,901 $
71,565 $
658,466
$
447,581 $
76,002 $
523,583
Non-POR
209,440
58,087
267,527
276,550
66,401
342,951
209,985
65,204
275,189
$
688,451 $
122,503 $
810,954
$
863,451 $
137,966 $ 1,001,417
$
657,566 $
141,206 $
798,772
(a) The primary markets include the following states:
• New England - Connecticut, Maine, Massachusetts, New Hampshire;
• Mid-Atlantic - Delaware, Maryland (including the District of Colombia), New Jersey, New York and
Pennsylvania;
• Midwest - Illinois, Indiana, Michigan and Ohio; and
• Southwest - Arizona, California, Colorado, Florida, Nevada, and Texas.
(b) Unbilled revenue is recorded in total until it is actualized, at which time it is categorized between commercial
and residential customers.
We record gross receipts taxes on a gross basis in retail revenues and retail cost of revenues. During the year ended
December 31, 2019, 2018 and 2017 our retail revenues included gross receipts taxes of $1.5 million, $1.6 million
and $6.4 million respectively. During the year ended December 31, 2019, 2018 and 2017, our retail cost of revenues
included gross receipts taxes of $8.4 million, $9.9 million and $9.0 million, respectively.
4. Acquisitions
Acquisition of Perigee
In April 2017, we acquired all of the outstanding membership interests of Perigee Energy, LLC, a Texas limited
liability company ("Perigee"), with operations across 14 utilities in Connecticut, Delaware, Massachusetts, New
York and Ohio from our affiliate, NG&E. The purchase price for Perigee from NG&E was approximately $4.1
million, which consisted of a base price of $2.0 million, $0.2 million additional customer option payment, and $1.9
million in working capital, subject to adjustments. The acquisition was treated as a transfer of equity interests
84
between entities under common control, and accordingly, the assets acquired and liabilities assumed were based on
their historical value as of the date. NG&E acquired Perigee, which was on February 3, 2017, and the fair value of
the net assets acquired was as follows (in thousands):
Cash
Intangible assets—customer relationships
Goodwill
Net working capital, net of cash acquired
Fair value of derivative liabilities
Total
Final Purchase Price Allocation
$
$
23
1,100
1,540
2,085
(443)
4,305
The Perigee acquisition did not have a material impact on our financial position or results of operations.
Acquisition of Verde
In July 2017, we acquired, through our subsidiary CenStar Energy Corp. ("CenStar"), all of the outstanding
membership interests and stock in a group of companies (the "Verde Companies") from Verde Energy USA
Holdings, LLC (the “Seller”). Total consideration was approximately $90.7 million, of which $20.1 million
represented positive net working capital, as adjusted. We also entered into an agreement to pay an additional
amount based on achievement by the Verde Companies of certain performance targets over the 18 month period
following closing of the acquisition (the "Verde Earnout"). The Verde Earnout was initially valued at $5.4 million.
The acquisition of the Verde Companies was accounted for under the acquisition method. The allocation of
purchase consideration was based upon the estimated fair value of the tangible and identifiable intangible assets
acquired and liabilities assumed in the acquisition based on management's best estimates, and was supported by
independent third-party analyses. The excess of the purchase price over the estimated fair value of tangible and
intangible assets acquired and liabilities assumed was allocated to goodwill. The allocation of the purchase
consideration was as follows (in thousands):
Final Purchase Price Allocation
as of December 31, 2018
Cash and restricted cash
Property and equipment
Intangible assets—customer relationships
Intangible assets—trademarks
Goodwill
Net working capital, net of cash acquired
Deferred tax liability
Fair value of derivative liabilities
Total
$
$
1,653
4,560
28,700
3,000
39,396
18,473
(3,126)
(1,942)
90,714
The Verde Earnout was based on achievement by the Verde Companies of certain performance targets over the 18
month period following the closing of the Verde acquisition. In January 2018, we settled the Verde Earnout by
issuing a $5.9 million note payable to the Seller. See Note 10 "Debt" for further discussion.
The Verde Companies contributed revenues of $76.0 million and earnings of $1.2 million to the Company for the
year ended December 31, 2017.
Acquisition of HIKO
85
In March 2018, we entered into a Membership Interest Purchase Agreement under which we acquired all of the
membership interests of HIKO Energy, LLC ("HIKO"), a New York limited liability company, for a total purchase
price of $6.0 million in cash, plus working capital. At the time of acquisition, HIKO had a total of approximately
29,000 RCEs located in 42 markets in seven states. The acquisition was accounted for under the acquisition method.
Our preliminary allocation of the purchase price was based upon the estimated fair value of the tangible and
identified intangible assets acquired and liabilities assumed in the acquisition. The allocation of the purchase
consideration is as follows (in thousands):
Cash and restricted cash
Intangible assets—customer relationships
Net working capital, net of cash acquired
Fair value of derivative liabilities
Total
Final Purchase Price Allocation
as of December 31, 2018
$
$
375
6,031
8,465
(205)
14,666
Our consolidated statements of operations for the twelve months ended December 31, 2018 included $15.3 million
of revenue and $3.8 million of net income related to the operations of HIKO.
In each of our acquisitions, we evaluate and allocate purchase price based on the following general assumptions.
Customer relationships. Acquired customer relationships were reflective of the acquired companies' customer
bases, and were valued using an excess earnings method under the income approach. Using this method, we
estimated the future cash flows resulting from the existing customer relationships, considering estimated attrition as
well as charges for contributory assets, such as net working capital, intangible assets, fixed assets, and any
assembled workforce. These future cash flows were then discounted using an appropriate risk-adjusted rate of
return to arrive at the present value of the expected future cash flows.
In acquisitions where we acquired commodity contracts that we could match to fixed-price contracts, customer
relationships were bifurcated between unhedged and hedged and are being amortized based on the expected term of
the underlying fixed-price contract acquired in each reporting period, respectively.
Non-compete Agreements. The fair value of non-compete agreements were determined using the differential value
approach. Under this approach, we estimated the present value of expected future cash flows of the business with
and without the non-compete agreement. The difference in discounted cash flows was then adjusted by probability
factors related to the likelihood that those with the non-compete agreements would be successful competitors.
Trademarks. The fair value of acquired trademarks is reflective of the value associated with the recognition and
reputation of the acquired company to target markets. The fair value of trademarks was valued using a royalty
savings method under the income approach. The value was based on the savings we would realize from owning the
trademark rather than paying a royalty for the use of that trademark. Under this approach, we estimate the present
value of the expected cash flows resulting from avoiding royalty payments to use a third party trademark. In the
Verde acquisition, we analyzed market royalty rates charged for licensing trademarks and applied an expected
royalty rate to a forecast of estimated revenue, which was then discounted using an appropriate risk adjusted rate of
return.
Goodwill. The excess of the purchase consideration over the estimated fair value of the amounts initially assigned to
the identifiable assets acquired and liabilities assumed was recorded as goodwill. Goodwill arose on the acquisitions
of the Provider Companies, Verde Companies and Perigee primarily due to the value of their assembled workforce,
proprietary sales channels, and/or access to new utility service territories. Goodwill arose on the acquisition of the
Major Energy Companies primarily due to the value of the Major Energy Companies brand strength, established
86
vendor relationships and access to new utility service territories. Goodwill recorded in connection with these
acquisitions is deductible for income tax purposes because these were acquisitions of all of the assets of the
companies.
Customer Acquisitions. We also, from time to time, acquire books of customers from affiliated and non-affiliated
parties. These acquisitions do not involve an allocation of the purchase price but rather are recorded as customer
relationships.
Acquisition of customers from Perigee
In April 2017, we acquired approximately 44,000 RCEs from the original owner of Perigee. During 2017, we paid
$7.5 million for customers transferred.
Acquisition from Related Parties
In March 2018, we entered into an asset purchase agreement with an affiliate pursuant to which we agreed to
acquire up to 50,000 RCEs for a cash purchase price of $250 for each RCE, or up to $12.5 million in the aggregate.
These customers began transferring after April 1, 2018 and are located in 24 markets in 8 states. For the year ended
December 31, 2018, we paid $8.8 million under the terms of the purchase agreement for approximately 35,000
RCEs. No additional customer transfers or consideration will be paid on this transaction. The acquisition was
treated as a transfer of assets between entities under common control, and accordingly, the assets were recorded at
our affiliate's historical value at the date of transfer, which was $1.7 million. The transaction resulted in $7.1
million recorded in equity as a net distribution to affiliate as of December 31, 2018. Of the $8.8 million paid to our
affiliate, $1.7 million was an investing cash outflow, and the remaining $7.1 million was deemed a distribution to
our non-controlling interest and classified as financing activity.
Acquisitions of Customer Books
In October 2018, we entered into an asset purchase agreement pursuant to which we agreed to acquire up
to 60,000 RCEs from Starion Energy Inc., Starion Energy NY Inc. and Starion Energy PA Inc. (collectively
"Starion") for a cash purchase price of up to a maximum of $10.7 million. These customers began transferring in
December 2018, and are located in our existing markets. As of December 31, 2019, a total of $8.0 million was paid
under the terms of the purchase agreement for approximately 51,000 RCEs.
As part of the acquisition, we funded an escrow account, the balance of which is reflected as restricted cash in our
consolidated balance sheet. As of December 31, 2019 and 2018, the balance in the escrow account was $1.0 million
and $8.6 million, respectively. The balance remaining as of December 31, 2019 represents a holdback of amounts
due to the seller for acquired customers that will be released to the seller in April 2020, subject to certain
adjustments outlined in the asset purchase agreement.
5. Equity
Non-controlling Interest
We hold an economic interest and are the sole managing member in Spark HoldCo, with affiliates of our Founder
and majority shareholder holding the remaining economic interests in Spark HoldCo. As a result, we consolidate the
financial position and results of operations of Spark HoldCo, and reflect the economic interests owned by these
affiliates as a non-controlling interest. The Company and affiliates owned the following economic interests in Spark
HoldCo at December 31, 2019 and December 31, 2018, respectively.
87
December 31, 2019
December 31, 2018
The Company
Affiliated Owners
41.04%
40.53%
58.96%
59.47%
The following table summarizes the portion of net income (loss) and income tax expense (benefit) attributable to
non-controlling interest (in thousands):
Year Ended December 31,
2018
2017
2019
Net income (loss) allocated to non-controlling interest
Income tax expense (benefit) allocated to non-controlling interest
Net income (loss) attributable to non-controlling interest
$
$
7,604 $
1,841
5,763 $
(12,140) $
1,066
(13,206) $
55,068
(731)
55,799
Class A Common Stock and Class B Common Stock
Holders of the Company's Class A common stock and Class B common stock vote together as a single class on all
matters presented to our stockholders for their vote or approval, except as otherwise required by applicable law or
by our certificate of incorporation.
Dividends on Class A Common Stock
Dividends declared for the Company's Class A common stock are reported as a reduction of retained earnings, or a
reduction of additional paid in capital to the extent retained earnings are exhausted. During the years ended
December 31, 2019, 2018, and 2017, we paid dividends on our Class A Common Stock of $10.4 million, $9.8
million, and $9.5 million. This dividend represented an annual rate of $0.725 per share on each share of Class A
common stock.
On January 21, 2020, the Company declared a dividend of $0.18125 per share to holders of record of our Class A
common stock on March 2, 2020 and payable on March 16, 2020.
In order to pay our stated dividends to holders of our Class A common stock, our subsidiary, Spark HoldCo is
required to make corresponding distributions to holders of its units, including those holders that own our Class B
common stock (our non-controlling interest holder). As a result, during the year ended December 31, 2019, Spark
HoldCo made corresponding distributions of $15.1 million to our non-controlling interest holders.
Stock Split
In May 2017, the Company authorized and approved a two-for-one stock split of the Company's issued Class A
common stock and Class B common stock, which was effected through a stock dividend (the "Stock Split").
Shareholders of record at the close of business on June 5, 2017 were issued one additional share of Class A common
stock or Class B common stock of the Company for each share of Class A common stock or Class B common stock,
respectively, held by such shareholder on that date. Such additional shares of Class A common stock or Class B
common stock were distributed on June 16, 2017. All shares and per share amounts in this report have been
retrospectively restated to reflect the Stock Split.
Preferred Stock
The Company has 20,000,000 shares of authorized preferred stock for which there are 3,707,256 shares issued and
3,677,318 shares outstanding at December 31, 2019 and 3,707,256 issued and outstanding shares at December 31,
2018. See Note 6 "Preferred Stock" for a further discussion of preferred stock.
88
Issuance of Class A Common Stock Upon Vesting of Restricted Stock Units
For the years ended December 31, 2019, 2018, and 2017, 473,492, 394,243, and 356,014, respectively of restricted
stock units vested, with 300,715, 258,076, and 241,965, respectively of shares of common stock distributed to the
holders of these units. Differences between shares vested and issued were a result of 172,777, 136,167, and 114,049
shares of common stock withheld by the Company to cover taxes owed on the vesting of such units.
Conversion of Class B Common Stock to Class A Common Stock
In 2018, holders of Class B common stock exchanged 685,126 of their Spark HoldCo units (together with a
corresponding number of shares of Class B common stock) for shares of Class A common stock at an exchange
ratio of one share of Class A common stock for each Spark HoldCo unit (and corresponding share of Class B
common stock) exchanged.
Earnings Per Share
Basic earnings per share (“EPS”) is computed by dividing net income attributable to stockholders (the numerator)
by the weighted-average number of Class A common shares outstanding for the period (the denominator). Class B
common shares are not included in the calculation of basic earnings per share because they are not participating
securities and have no economic interests. Diluted earnings per share is similarly calculated except that the
denominator is increased by potentially dilutive securities.
The following table presents the computation of basic and diluted income (loss) per share for the years ended
December 31, 2019, 2018, and 2017 (in thousands, except per share data):
Net income (loss) attributable to Spark Energy, Inc. stockholders
Less: Dividend on Series A preferred stock
Net income (loss) attributable to stockholders of Class A common stock
Basic weighted average Class A common shares outstanding
Basic earnings (loss) per share attributable to stockholders
Net income (loss) attributable to stockholders of Class A common stock
Effect of conversion of Class B common stock to shares of Class A
common stock
Diluted net income (loss) attributable to stockholders of Class A common
stock
Year Ended December 31,
2018
2019
2017
8,450 $
8,091
359 $
(1,186) $
8,109
(9,295) $
14,286
0.03 $
13,390
(0.69) $
19,245
3,038
16,207
13,143
1.23
359 $
(9,295) $
16,207
—
—
—
359 $
(9,295) $
16,207
$
$
$
$
$
Basic weighted average Class A common shares outstanding
14,286
13,390
13,143
Effect of dilutive Class B common stock
Effect of dilutive restricted stock units
Diluted weighted average shares outstanding
—
282
—
—
—
203
14,568
13,390
13,346
Diluted earnings (loss) per share attributable to stockholders
$
0.02 $
(0.69) $
1.21
The computation of diluted earnings per share for the year ended December 31, 2019 excludes 20.8 million shares
of Class B common stock because the effect of their conversion was antidilutive. The Company's outstanding shares
89
of Series A Preferred Stock were not included in the calculation of diluted earnings per share because they contain
only contingent redemption provisions that have not occurred.
Variable Interest Entity
Spark HoldCo is a variable interest entity due to its lack of rights to participate in significant financial and operating
decisions and its inability to dissolve or otherwise remove its management. Spark HoldCo owns all of the
outstanding membership interests in each of our operating subsidiaries. We are the sole managing member of Spark
HoldCo, manage Spark HoldCo's operating subsidiaries through this managing membership interest, and are
considered the primary beneficiary of Spark HoldCo. The assets of Spark HoldCo cannot be used to settle our
obligations except through distributions to us, and the liabilities of Spark HoldCo cannot be settled by us except
through contributions to Spark HoldCo. The following table includes the carrying amounts and classification of the
assets and liabilities of Spark HoldCo that are included in our consolidated balance sheet as of December 31, 2019
and 2018 (in thousands):
December 31, 2019
December 31, 2018
Assets
Current assets:
Cash and cash equivalents
Accounts receivable
Other current assets
Total current assets
Non-current assets:
Goodwill
Other assets
Total non-current assets
Total Assets
Liabilities
Current liabilities:
Accounts Payable and Accrued Liabilities
Contingent consideration
Other current liabilities
Total current liabilities
Long-term liabilities:
Long-term portion of Senior Credit Facility
Subordinated debt—affiliate
Other long-term liabilities
Total long-term liabilities
Total Liabilities
6. Preferred Stock
$
$
$
$
56,598 $
113,635
64,476
234,709
120,343
37,826
158,169
392,878 $
86,097 $
—
65,863
151,960
123,000
—
712
123,712
275,672 $
36,724
150,866
92,963
280,553
120,343
47,159
167,502
448,055
79,692
1,328
59,330
140,350
129,500
10,000
319
139,819
280,169
In March 2017, we issued 1,610,000 shares of 8.75% Series A Fixed-to-Floating Rate Cumulative Redeemable
Perpetual Preferred Stock ("Series A Preferred Stock"), par value $0.01 per share and having a liquidation
preference $25.00 per share, plus accumulated and unpaid dividends, at a price to the public of $25.00 per share
($24.21 per share to us, net of underwriting discounts and commissions). We received approximately $39.0 million
in net proceeds from the offering, after deducting underwriting discounts and commissions and a structuring fee.
Offering expenses of $1.0 million were recorded as a reduction to the carrying value of the Series A Preferred
Stock.
90
In July 2017, we entered into an At-the-Market Issuance Sales Agreement ("the ATM Agreement") with FBR
Capital Markets & Co. as sales agent (the "Agent"). Pursuant to the terms of the ATM Agreement, we may sell,
from time to time through the Agent, our Series A Preferred Stock, having an aggregate offering price of up to $50.0
million. During the year ended December 31, 2017, we issued an aggregate of 94,339 shares of Series A Preferred
Stock under the ATM Agreement. We received net proceeds of $2.4 million and paid compensation to the sales
agent of less than $0.1 million with respect to these sales. During the year ended December 31, 2018, we issued an
aggregate of 2,917 shares of Series A Preferred Stock under the ATM Agreement. We received net proceeds of $0.1
million and paid compensation to the sales agent of less than $0.1 million with respect to these sales.
In January 2018, we issued 2,000,000 shares of Series A Preferred Stock, plus accumulated and unpaid dividends, at
a price to the public of $25.25 per share. The Company received approximately $48.9 million ($24.45 per share) in
net proceeds from the offering, after deducting underwriting discounts and commissions and a structuring fee.
Offering expenses of $0.5 million were recorded as a reduction to the carrying value of the Series A Preferred
Stock.
In May 2019, we commenced a share repurchase program (the "Repurchase Program") of our Series A Preferred
Stock. We may make purchases of our Series A Preferred Stock under the Repurchase Program through May 20,
2020, and there is no dollar limit on the amount of Series A Preferred Stock that may be repurchased, nor does the
Repurchase Program obligate the Company to make any repurchases.
In November 2019, we amended and extended our repurchase program (the "Repurchase Program") of our Series A
Preferred Stock. The Repurchase Program allows us to purchase Preferred Stock through December 31, 2020, at
prevailing prices, in open market or negotiated transactions, subject to market conditions, maximum share prices
and other considerations. The Repurchase Program does not obligate us to make any repurchases and may be
suspended at any time.
During the year ended December 31, 2019, we repurchased 29,938 shares of Series A Preferred Stock at a
weighted-average price of $24.82 per share, for a total cost of approximately $0.7 million.
Holders of the Series A Preferred Stock have no voting rights, except in specific circumstances of delisting or in the
case the dividends are in arrears as specified in the Series A Preferred Stock Certificate of Designations. The Series
A Preferred Stock accrue dividends at an annual percentage rate of 8.75%, and the liquidation preference provisions
of the Series A Preferred Stock are considered contingent redemption provisions because there are rights granted to
the holders of the Series A Preferred Stock that are not solely within our control upon a change in control of the
Company. Accordingly, the Series A Preferred Stock is presented between liabilities and the equity sections in the
accompanying consolidated balance sheet.
During the year ended December 31, 2019, we paid $8.1 million in dividends to holders of the Series A Preferred
Stock. As of December 31, 2019, we had accrued $2.0 million related to dividends to holders of the Series A
Preferred Stock. This dividend was paid on January 15, 2020. During the year ended December 31, 2018, the
Company paid $7.0 million in dividends to holders of the Series A Preferred Stock and had accrued $2.0 million as
of December 31, 2018.
On January 21, 2020, the Company declared a quarterly cash dividend in the amount of $0.546875 per share of
Series A Preferred Stock. This amount represents an annualized dividend of $2.1875 per share. The dividend will be
paid on April 15, 2020 to holders of record on April 1, 2020 of the Series A Preferred Stock.
A summary of our preferred equity balance for the years ended December 31, 2019 and 2018 is as follows:
91
Balance at December 31, 2017
Issuance of Series A Preferred Stock, net of issuance cost
Accumulated dividends on Series A Preferred Stock
Balance at December 31, 2018
Repurchase of Series A Preferred Stock
Accumulated dividends on Series A Preferred Stock
Balance at December 31, 2019
7. Derivative Instruments
(in thousands)
41,173
48,490
1,095
90,758
(727)
(16)
90,015
$
$
$
We are exposed to the impact of market fluctuations in the price of electricity and natural gas, basis differences in
the price of natural gas, storage charges, renewable energy credits ("RECs"), and capacity charges from independent
system operators. We use derivative instruments in an effort to manage our cash flow exposure to these risks. These
instruments are not designated as hedges for accounting purposes, and accordingly, changes in the market value of
these derivative instruments are recorded in the cost of revenues. As part of our strategy to optimize pricing in our
natural gas related activities, we also manage a portfolio of commodity derivative instruments held for trading
purposes. Our commodity trading activities are subject to limits within our Risk Management Policy. For these
derivative instruments, changes in the fair value are recognized currently in earnings in net asset optimization
revenues.
Derivative assets and liabilities are presented net in our consolidated balance sheets when the derivative instruments
are executed with the same counterparty under a master netting arrangement. Our derivative contracts include
transactions that are executed both on an exchange and centrally cleared, as well as over-the-counter, bilateral
contracts that are transacted directly with third parties. To the extent we have paid or received collateral related to
the derivative assets or liabilities, such amounts would be presented net against the related derivative asset or
liability’s fair value. As of December 31, 2019 and 2018, we had paid $1.7 million and zero, respectively, in
collateral. The specific types of derivative instruments we may execute to manage the commodity price risk include
the following:
• Forward contracts, which commit us to purchase or sell energy commodities in the future;
• Futures contracts, which are exchange-traded standardized commitments to purchase or sell a commodity or
financial instrument;
• Swap agreements, which require payments to or from counterparties based upon the differential between
two prices for a predetermined notional quantity; and
• Option contracts, which convey to the option holder the right but not the obligation to purchase or sell a
commodity.
The Company has entered into other energy-related contracts that do not meet the definition of a derivative
instrument or for which we made a normal purchase, normal sale election and are therefore not accounted for at fair
value including the following:
Forward electricity and natural gas purchase contracts for retail customer load;
• Renewable energy credits; and
Natural gas transportation contracts and storage agreements.
Volumes Underlying Derivative Transactions
The following table summarizes the net notional volumes of our open derivative financial instruments accounted for
at fair value by commodity. Positive amounts represent net buys while bracketed amounts are net sell transactions
(in thousands):
92
Non-trading
Natural Gas
Natural Gas Basis
Electricity
Trading
Natural Gas
Natural Gas Basis
Commodity
Commodity
Gains (Losses) on Derivative Instruments
Notional
MMBtu
MMBtu
MWh
Notional
MMBtu
MMBtu
December 31,
2019
December 31,
2018
6,130
42
6,015
8,176
115
6,781
December 31,
2019
December 31,
2018
204
—
188
(380)
Gains (losses) on derivative instruments, net and current period settlements on derivative instruments were as
follows for the periods indicated (in thousands):
(Loss) gain on non-trading derivatives, net
Gain (loss) on trading derivatives, net
(Loss) gain on derivatives, net
Current period settlements on non-trading derivatives (1) (2)
Current period settlements on trading derivatives
Total current period settlements on derivatives (1) (2)
Year Ended December 31,
2019
2018
2017
$
$
$
$
$
(67,955)
206
(67,749)
42,944
(124)
$
$
(19,571)
1,401
(18,170)
(9,614)
(973)
42,820
$
(10,587)
$
5,588
(580)
5,008
16,508
(199)
16,309
(1) Excludes settlements of less than $0.1 million, $(0.3) million, and $3.4 million, respectively, for the years ended December 31, 2019,
2018, and 2017 related to non-trading derivative liabilities assumed in various acquisitions.
(2) Excludes settlements of $(0.9) million, zero, and zero, respectively, for the years ended December 31, 2019, 2018, and 2017 related to
power call options.
Gains (losses) on trading derivative instruments are recorded in net asset optimization revenues and gains (losses)
on non-trading derivative instruments are recorded in retail cost of revenues on the consolidated statements of
operations.
Fair Value of Derivative Instruments
The following tables summarize the fair value and offsetting amounts of our derivative instruments by counterparty
and collateral received or paid (in thousands):
93
December 31, 2019
Description
Non-trading commodity derivatives
Trading commodity derivatives
Total Current Derivative Assets
Non-trading commodity derivatives
Trading commodity derivatives
Total Non-current Derivative Assets
Total Derivative Assets
$
Gross Assets
570
$
170
740
333
—
333
1,073
Gross
Amounts
Offset
$
$
(275)
(1)
(276)
(227)
—
(227)
(503)
$
Net Assets
295
169
464
106
—
106
570
$
Description
Gross
Liabilities
Gross
Amounts
Offset
Net
Liabilities
Non-trading commodity derivatives
$
(34,434)
$
12,859
$
Trading commodity derivatives
Total Current Derivative Liabilities
Non-trading commodity derivatives
Trading commodity derivatives
Total Non-current Derivative Liabilities
Total Derivative Liabilities
$
(194)
(34,628)
(1,951)
—
(1,951)
(36,579)
$
194
13,053
1,422
—
1,422
14,475
$
(21,575)
—
(21,575)
(529)
—
(529)
(22,104)
Cash
Collateral
Offset
Net Amount
Presented
— $
—
—
—
—
—
— $
295
169
464
106
—
106
570
Cash
Collateral
Offset
Net Amount
Presented
1,632
—
1,632
34
—
34
1,666
$
$
(19,943)
—
(19,943)
(495)
—
(495)
(20,438)
$
$
$
$
December 31, 2018
Gross
Amounts
Offset
Net Assets
Cash
Collateral
Offset
Net Amount
Presented
$
6,649
$
— $
Description
Gross Assets
Non-trading commodity derivatives
$
18,649
$
Trading commodity derivatives
Total Current Derivative Assets
Non-trading commodity derivatives
Trading commodity derivatives
Total Non-current Derivative Assets
Total Derivative Assets
$
734
19,383
9,657
—
9,657
29,040
$
(12,000)
(94)
(12,094)
(6,381)
—
(6,381)
(18,475)
640
7,289
3,276
—
3,276
10,565
$
Description
Gross
Liabilities
Gross
Amounts
Offset
Net
Liabilities
Non-trading commodity derivatives
$
(21,391)
$
15,385
$
Trading commodity derivatives
Total Current Derivative Liabilities
Non-trading commodity derivatives
Trading commodity derivatives
(491)
(21,882)
(71)
(135)
19
15,404
40
60
Total Non-current Derivative Liabilities
Total Derivative Liabilities
(206)
(22,088)
$
$
100
15,504
$
(6,006)
(472)
(6,478)
(31)
(75)
(106)
(6,584)
94
—
—
—
—
—
— $
6,649
640
7,289
3,276
—
3,276
10,565
$
$
$
Cash
Collateral
Offset
Net Amount
Presented
— $
—
—
—
—
—
— $
(6,006)
(472)
(6,478)
(31)
(75)
(106)
(6,584)
8. Property and Equipment
Property and equipment consist of the following (in thousands):
Information technology
Building and leasehold improvements
Furniture and fixtures
Total
Accumulated depreciation
Property and equipment—net
Estimated
useful
lives (years)
2 – 5
2 – 5
2 – 5
December 31,
2019
December 31,
2018
$
$
22,005
$
—
1,802
23,807
(20,540)
3,267
$
34,611
4,836
1,964
41,411
(37,045)
4,366
Information technology assets include software and consultant time used in the application, development and
implementation of various systems including customer billing and resource management systems. As of each of
December 31, 2019 and 2018, information technology includes $0.6 million and $0.3 million, respectively, of costs
associated with assets not yet placed into service.
Depreciation expense recorded in the consolidated statements of operations was $2.3 million, $3.9 million and $2.6
million for the years ended December 31, 2019, 2018 and 2017, respectively.
9. Intangible Assets
Goodwill, customer relationships and trademarks consist of the following amounts (in thousands):
December 31, 2019
December 31, 2018
Goodwill
Customer Relationships— Acquired
Cost
Accumulated amortization
$
$
Customer Relationships—Acquired & Non-Compete Agreements, net $
Customer Relationships—Other
Cost
$
Accumulated amortization
Customer Relationships—Other, net
Trademarks
Cost
Accumulated amortization
Trademarks, net
$
$
$
120,343
64,083
(40,231)
23,852
17,056
(9,534)
7,522
8,502
(2,794)
5,708
$
$
$
$
$
$
$
120,343
99,402
(63,208)
36,194
16,155
(9,290)
6,865
9,770
(2,483)
7,287
Changes in goodwill, customer relationships (including non-compete agreements) and trademarks consisted of the
following (in thousands):
95
Balance at December 31, 2016
Adjustments (1)
Acquisition of Perigee
Acquisition of Verde
Additions (Other)
Amortization expense
Balance at December 31, 2017
Additions
Adjustments (1)
Amortization
Balance at December 31, 2018
Additions
Amortization
Balance at December 31, 2019
Customer
Relationships—
Acquired &
Non-Compete
Agreements
Goodwill
Customer
Relationships—
Other
Trademarks
$
$
$
$
79,147
$
31,911
$
1,612
$
260
1,540
39,207
—
—
120,154
$
—
189
—
120,343
$
—
—
120,343
$
—
1,100
28,700
—
(15,021)
46,690
6,205
(174)
(16,527)
36,194
—
(12,342)
23,852
$
$
$
—
—
—
8,016
(2,826)
6,802
3,818
—
(3,755)
6,865
6,913
(6,256)
7,522
$
$
$
6,339
—
—
3,000
—
(781)
8,558
—
—
(1,271)
7,287
—
(1,579)
5,708
(1) Related to working capital adjustments on various acquisitions.
The acquired customer relationship intangibles related to Major Energy Companies, the Provider Companies, and
the Verde Companies were bifurcated between hedged and unhedged customer contracts. The unhedged customer
contracts are amortized to depreciation and amortization based on the expected future cash flows by year. The
hedged customer contracts were evaluated for favorable or unfavorable positions at the time of acquisition and
amortized to retail cost of revenue based on the expected term and position of the underlying fixed price contract in
each reporting period. For the years ended December 31, 2019, 2018, and 2017, respectively, approximately less
than $0.1 million, $(1.2) million, and $0.3 million of the $12.3 million, $16.5 million, and $15.0 million acquired
customer relationship amortization expense is included in the cost of revenues.
Estimated future amortization expense for customer relationships and trademarks at December 31, 2019 is as
follows (in thousands):
Year Ending December 31,
2020
2021
2022
2023
2024
> 5 years
Total
$
$
14,561
12,987
6,038
450
249
2,797
37,082
96
10. Debt
Debt consists of the following amounts as of December 31, 2019 and 2018 (in thousands):
Current:
Note Payable—Verde Notes
Total current portion of debt
Long-term debt:
Senior Credit Facility (1) (2)
Subordinated Debt
Total long-term debt
Total debt
December 31, 2019
December 31, 2018
$
$
— $
—
123,000
—
123,000
123,000
$
6,936
6,936
129,500
10,000
139,500
146,436
(1) As of December 31, 2019 and 2018, the weighted average interest rate on the Senior Credit Facility was 4.71% and 5.48%, respectively.
(2) As of December 31, 2019 and 2018, we had $37.4 million and $49.4 million in letters of credit issued, respectively.
Capitalized financing costs associated with our Senior Credit Facility were $1.3 million and $1.4 million as of
December 31, 2019 and 2018, respectively. Of these amounts, $0.9 million and $1.0 million are recorded in other
current assets, and $0.4 million and $0.4 million are recorded in other non-current assets in the consolidated balance
sheets as of December 31, 2019 and 2018, respectively.
Interest expense consists of the following components for the periods indicated (in thousands):
Senior Credit Facility
Accretion related to Earnouts
Letters of credit fees and commitment fees
Amortization of deferred financing costs
Convertible subordinated notes to affiliate
Subordinated debt
Verde promissory note
Interest expense
Senior Credit Facility
Years Ended December 31,
2019
2018
2017
$
5,263
$
5,300
$
—
1,656
1,275
—
197
230
$
8,621
$
—
1,604
1,291
—
26
1,189
9,410
3,275
4,108
1,125
1,035
1,052
167
372
$
11,134
The Company, as guarantor, and Spark HoldCo (the “Borrower” and, together with each subsidiary of Spark
HoldCo (“Co-Borrowers”)) maintain a senior secured borrowing base credit facility (as amended, “Senior Credit
Facility”) that allows us to borrow on a revolving basis and has a maximum borrowing capacity of $217.5 million
as of December 31, 2019. Subject to applicable sublimits and terms of the Senior Credit Facility, as amended,
borrowings are available for the issuance of letters of credit (“Letters of Credit”), working capital and general
purpose revolving credit loans (“Working Capital Loans”), and bridge loans (“Bridge Loans”) for the purpose of
partial funding for acquisitions. Borrowings under the Senior Credit Facility may be used to pay fees and expenses
in connection with the Senior Credit Facility, finance ongoing working capital requirements and general corporate
purpose requirements of the Co-Borrowers, to provide partial funding for acquisitions, as allowed under terms of
the Senior Credit Facility, and to make open market purchases of our Class A common stock and Series A Preferred
Stock.
The Senior Credit Facility will mature on May 19, 2021, and all amounts outstanding thereunder will be payable on
the maturity date. Borrowings under the Bridge Loan sublimit, if any, will be repaid 25% per year on a quarterly
97
basis (or 6.25% per quarter), with the remainder due at maturity. As of December 31, 2019, there was zero in Bridge
Loans outstanding.
At our election, the interest rate for Working Capital Loans and Letters of Credit under the Senior Credit Facility is
generally determined by reference to the Eurodollar rate plus an applicable margin of up to 3.00% per annum (based
on the prevailing utilization) or an alternate base rate plus an applicable margin of up to 2.00% per annum (based on
the prevailing utilization). The alternate base rate is equal to the highest of (i) the prime rate (as published in the
Wall Street Journal), (ii) the federal funds rate plus 0.50% per annum, or (iii) the reference Eurodollar rate plus
1.00%.
Bridge Loan borrowings, if any, under the Senior Credit Facility are generally determined by reference to the
Eurodollar rate plus an applicable margin of 3.75% per annum or an alternate base rate plus an applicable margin of
2.75% per annum. The alternate base rate is equal to the highest of (i) the prime rate (as published in the Wall Street
Journal), (ii) the federal funds rate plus 0.50% per annum, or (iii) the reference Eurodollar rate plus 1.00%.
The Co-Borrowers pay a commitment fee of 0.50% quarterly in arrears on the unused portion of the Senior Credit
Facility. In addition, the Co-Borrowers are subject to additional fees including an upfront fee, an annual agency fee,
and letter of credit fees based on a percentage of the face amount of letters of credit payable to any syndicate
member that issues a letter of credit.
The Senior Credit Facility contains covenants that, among other things, require the maintenance of specified ratios
or conditions including:
• Minimum Fixed Charge Coverage Ratio. We must maintain a minimum fixed charge coverage ratio of not
less than 1.25 to 1.00. The Fixed Charge Coverage Ratio is defined as the ratio of (a) Adjusted EBITDA to
(b) the sum of consolidated (with respect to the Company and the Co-Borrowers) interest expense (other
than interest paid-in-kind in respect of certain subordinated debt but including interest in respect of that
certain promissory note made by CenStar Energy Corp. ("CenStar") in connection with the permitted
acquisition from Verde Energy USA Holdings, LLC), letter of credit fees, commitment fees, acquisition
earn-out payments (excluding earnout payments funded with proceeds from newly issued preferred or
common equity), distributions, the aggregate amount of repurchases of our Class A common stock, Series A
Preferred Stock, or commitments for such purchases, taxes and scheduled amortization payments. The
Senior Credit Facility permits, upon satisfaction of a Step-Down Condition, for the Company to elect to
reduce the minimum required Fixed Charge Coverage Ratio from 1.25 to 1.00 to 1.10 to 1.00 for a period of
one year. A Step-Down Condition is defined as the consummation by the Company of share buybacks of its
Series A Preferred Stock under the Repurchase Program with an aggregate purchase price not less than
$10.0 million.
• Maximum Total Leverage Ratio. We must maintain a ratio of total indebtedness (excluding eligible
subordinated debt and letter of credit obligations) to Adjusted EBITDA of no more than 2.50 to 1.00.
• Maximum Senior Secured Leverage Ratio. We must maintain a Senior Secured Leverage Ratio of no more
than 1.85 to 1.00. The Senior Secured Leverage Ratio is defined as the ratio of (a) all indebtedness of the
loan parties on a consolidated basis that is secured by a lien on any property of any loan party (including the
effective amount of all loans then outstanding under the Senior Credit Facility) plus 50% of the effective
amount of letter of credit obligations attributable to performance standby letters of credit to (b) Adjusted
EBITDA.
The Senior Credit Facility contains various negative covenants that limit our ability to, among other things, incur
certain additional indebtedness, grant certain liens, engage in certain asset dispositions, merge or consolidate, make
certain payments, distributions, investments, acquisitions or loans, materially modify certain agreements, or enter
into transactions with affiliates. The Senior Credit Facility also contains affirmative covenants that are customary
98
for credit facilities of this type. As of December 31, 2019, we were in compliance with our various covenants under
the Senior Credit Facility.
The Senior Credit Facility is secured by pledges of the equity of the portion of Spark HoldCo owned by us, the
equity of Spark HoldCo’s subsidiaries, the Co-Borrowers’ present and future subsidiaries, and substantially all of
the Co-Borrowers’ and their subsidiaries’ present and future property and assets, including accounts receivable,
inventory and liquid investments, and control agreements relating to bank accounts.
We are entitled to pay cash dividends to the holders of the Series A Preferred Stock and Class A common stock and
will be entitled to repurchase up to an aggregate amount of 10,000,000 shares of our Class A common stock, and up
to $92.7 million of Series A Preferred Stock through one or more normal course open market purchases through
NASDAQ so long as: (a) no default exists or would result therefrom; (b) the Co-Borrowers are in pro forma
compliance with all financial covenants before and after giving effect thereto; and (c) the outstanding amount of all
loans and letters of credit does not exceed the borrowing base limits.
The Senior Credit Facility contains certain customary representations and warranties and events of default. Events
of default include, among other things, payment defaults, breaches of representations and warranties, covenant
defaults, cross-defaults and cross-acceleration to certain indebtedness, certain events of bankruptcy, certain events
under ERISA, material judgments in excess of $5.0 million, certain events with respect to material contracts, and
actual or asserted failure of any guaranty or security document supporting the Senior Credit Facility to be in full
force and effect. A default will also occur if at any time W. Keith Maxwell III ceases to, directly or indirectly, own
at least 13,600,000 Class A and Class B shares on a combined basis (to be adjusted for any stock split, subdivisions
or other stock reclassification or recapitalization), and a controlling percentage of the voting equity interest of the
Company, and certain other changes in control. If such an event of default occurs, the lenders under the Senior
Credit Facility would be entitled to take various actions, including the acceleration of amounts due under the facility
and all actions permitted to be taken by a secured creditor.
Convertible Subordinated Notes to Affiliate
In connection with the financing of the CenStar and Oasis acquisitions, the Company issued Notes totaling $7.1
million, at an annual interest rate of 5%, payable semiannually. In January 2017, these Notes were converted into
1,035,642 shares of Class B common stock (and related Spark HoldCo units).
Subordinated Debt Facility
In June 2019, the Company entered into an Amended and Restated Subordinated Promissory Note in the principal
amount of up to $25.0 million (the “Subordinated Debt Facility”), by and among the Company, Spark HoldCo and
Retailco. The Subordinated Debt Facility amended and restated the Subordinated Promissory Note, dated as of
December 27, 2016, by and among the Company, Spark HoldCo and Retailco, solely to extend the expiration date
from July 1, 2020 to December 31, 2021.
The Subordinated Debt Facility allows us to draw advances in increments of no less than $1.0 million per advance
up to the maximum principal amount of the Subordinated Debt Facility. Advances thereunder accrue interest at 5%
per annum from the date of the advance. We have the right to capitalize interest payments under the Subordinated
Debt Facility. The Subordinated Debt Facility is subordinated in certain respects to our Senior Credit Facility
pursuant to a subordination agreement. We may pay interest and prepay principal on the Subordinated Debt Facility
so long as we are in compliance with the covenants under our Senior Credit Facility, are not in default under the
Senior Credit Facility and have minimum availability of $5.0 million under the borrowing base under the Senior
Credit Facility. Payment of principal and interest under the Subordinated Debt Facility is accelerated upon the
occurrence of certain change of control or sale transactions.
As of December 31, 2019 and 2018, there was zero and $10.0 million outstanding under the Subordinated Debt
Facility.
99
Verde Notes
In connection with the acquisition of the Verde Companies in July 2017, we entered into a promissory note in the
aggregate principal amount of $20.0 million (the "Verde Promissory Note"). The Verde Promissory Note required
repayment in 18 monthly installments beginning in August 2017, and accrued interest at 5% per annum from the
date of issuance. The Verde Promissory Note, including principal and interest, was unsecured, but was guaranteed
by us. In January 2018, in connection with the Earnout Termination Agreement (defined below), we issued to the
seller of the Verde Companies an amended and restated promissory note (the “Amended and Restated Verde
Promissory Note”), which amended and restated the Verde Promissory Note. The Amended and Restated Verde
Promissory Note matured in January 2019, and bore interest at a rate of 9% per annum. Principal and interest were
payable monthly on the first day of each month, with a portion of each payment going into an escrow account,
which serves as security for certain indemnification claims and obligations under the Verde purchase agreement. As
of December 31, 2019 and 2018, there was zero and $1.0 million outstanding, respectively, under the Amended and
Restated Verde Promissory Note.
In January 2018, we issued a promissory note in the principal amount of $5.9 million in connection with an
agreement to terminate the earnout obligations arising in connection with our acquisition of the Verde Companies
(the “Verde Earnout Termination Note”). The Verde Earnout Termination Note matured in June 2019 and bore
interest at a rate of 9% per annum. Under the terms of the Verde Earnout Termination Note, we were permitted to
withhold amounts otherwise due at maturity related to certain indemnifiable matters. A payment of $1.0 million was
made to the seller of the Verde Companies in June 2019, and $4.9 million was withheld (the “Verde Holdback”) to
be applied to indemnifiable matters. As of December 31, 2019 and 2018, there was zero and $5.9 million
outstanding under the Verde Earnout Termination Note, respectively.
The Verde Earnout Termination Note, the Verde Promissory Note, and the Amended and Restated Verde Promissory
Note are collectively referred to as the "Verde Notes."
11. Fair Value Measurements
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (exit price) in
an orderly transaction between market participants at the measurement date. Fair values are based on assumptions
that market participants would use when pricing an asset or liability, including assumptions about risk and the risks
inherent in valuation techniques and the inputs to valuations. This includes the credit standing of counterparties
involved and the impact of credit enhancements.
We apply fair value measurements to our commodity derivative instruments and contingent payment arrangements
based on the following fair value hierarchy, which prioritizes the inputs to the valuation techniques used to measure
fair value into three broad levels:
•
•
•
Level 1—Quoted prices in active markets for identical assets and liabilities. Instruments
categorized in Level 1 primarily consist of financial instruments such as exchange-traded derivative
instruments.
Level 2—Inputs other than quoted prices recorded in Level 1 that are either directly or indirectly
observable for the asset or liability, including quoted prices for similar assets or liabilities in active
markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other
than quoted prices that are observable for the asset or liability, and inputs that are derived from
observable market data by correlation or other means. Instruments categorized in Level 2 primarily
include non-exchange traded derivatives such as over-the-counter commodity forwards and swaps
and options.
Level 3—Unobservable inputs for the asset or liability, including situations where there is little, if
any, observable market activity for the asset or liability. The Level 3 category includes estimated
earnout obligations related to our acquisitions.
100
As the fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest
priority to unobservable data (Level 3), the Company maximizes the use of observable inputs and minimizes the use
of unobservable inputs when measuring fair value. These levels can change over time. In some cases, the inputs
used to measure fair value might fall in different levels of the fair value hierarchy. In these cases, the lowest level
input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value
hierarchy.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
The following tables present assets and liabilities measured and recorded at fair value in our consolidated balance
sheets on a recurring basis by and their level within the fair value hierarchy (in thousands):
December 31, 2019
Non-trading commodity derivative assets
Trading commodity derivative assets
Total commodity derivative assets
Non-trading commodity derivative liabilities
Trading commodity derivative liabilities
Total commodity derivative liabilities
Contingent payment arrangement
December 31, 2018
Non-trading commodity derivative assets
Trading commodity derivative assets
Total commodity derivative assets
Non-trading commodity derivative liabilities
Trading commodity derivative liabilities
Total commodity derivative liabilities
Contingent payment arrangement
Level 1
Level 2
Level 3
Total
— $
—
— $
(1,666) $
—
(1,666) $
— $
401
169
570
$
$
(18,772) $
—
(18,772) $
— $
— $
—
— $
— $
—
— $
— $
401
169
570
(20,438)
—
(20,438)
—
Level 1
Level 2
Level 3
Total
104
44
148
$
$
(352) $
(75)
(427) $
— $
9,821
596
10,417
$
$
(5,685) $
(472)
(6,157) $
— $
—
— $
— $
—
— $
— $
(1,328) $
9,925
640
10,565
(6,037)
(547)
(6,584)
(1,328)
$
$
$
$
$
$
$
$
$
$
We had no transfers of assets or liabilities between any of the above levels during the years ended December 31,
2019, 2018 and 2017.
Our derivative contracts include exchange-traded contracts valued utilizing readily available quoted market prices
and non-exchange-traded contracts valued using market price quotations available through brokers or over-the-
counter and on-line exchanges. In addition, in determining the fair value of our derivative contracts, we apply a
credit risk valuation adjustment to reflect credit risk, which is calculated based on our or the counterparty’s
historical credit risks. As of December 31, 2019 and 2018, the credit risk valuation adjustment was a gain of $0.2
million and zero, respectively.
The contingent payment arrangements referred to above reflect estimated earnout obligations incurred in relation to
our acquisition of the Major Energy Companies in 2016.
Contingent Payment Arrangements
The following tables present a roll forward of our contingent payment arrangements, which are measured at fair
value on a recurring basis using significant unobservable inputs (Level 3):
101
Fair Value at December 31, 2017
Change in fair value of contingent consideration, net
Payments and settlements
Fair Value at December 31, 2018
Transfer
Fair Value at December 31, 2019
Major Earnout and
Stock Earnout
$
$
$
$
4,650
(1,715)
(1,607)
1,328
(1,328)
—
The Major Earnout is based on the achievement by the Major Energy Companies of certain performance targets
over a 33 month period following the date our affiliate acquired the Major Energy Companies and ended on
December 31, 2018. Under the Earnout provisions, the previous members of Major Energy Companies were
entitled to a maximum of $20.0 million in earnout payments based on the level of performance targets attained, as
defined by the Major Purchase Agreement. The Stock Earnout obligation was contingent upon the Major Energy
Companies achieving the Major Earnout's performance target ceiling, thereby earning the maximum Major Earnout
payments. If the Major Energy Companies earned such maximum Major Earnout payments, NG&E would be
entitled to additional consideration up to a maximum of 400,000 shares of Class B common stock (and a
corresponding number of Spark HoldCo units). In determining the fair value of the Major Earnout and the Stock
Earnout, we forecasted certain expected performance targets and calculated the probability of such forecast being
attained. The impact of the fair value decreases for the years ended December 31, 2018 and 2017 were recorded in
general and administrative expenses. The $1.3 million has not been paid as of December 31, 2019 due to ongoing
litigation with the Major sellers. It was transferred to accrued liabilities as of December 31, 2019, as discussed
further in Note 14 "Commitments and Contingencies."
12. Stock-Based Compensation
Restricted Stock Units
We maintain a Long-Term Incentive Plan ("LTIP") for employees, consultants and directors of the Company and its
affiliates who perform services for the Company. The purpose of the LTIP is to provide a means to attract and retain
individuals to serve as directors, employees and consultants who provide services to the Company by affording such
individuals a means to acquire and maintain ownership of awards, the value of which is tied to the performance of
the Company’s Class A common stock. The LTIP provides for grants of cash payments, stock options, stock
appreciation rights, restricted stock or units, bonus stock, dividend equivalents, and other stock-based awards with
the total number of shares of stock available for issuance under the LTIP not to exceed 2,750,000 shares.
Restricted stock units granted to our officers, employees, non-employee directors and certain employees of our
affiliates who perform services for the Company vest over approximately one year for non-employee directors and
ratably over approximately one to four years for officers, employees, and employees of affiliates, with the initial
vesting date occurring in May of the subsequent year. Each restricted stock unit is entitled to receive a dividend
equivalent when dividends are declared and distributed to shareholders of Class A common stock. These dividend
equivalents are retained by the Company, reinvested in additional restricted stock units effective as of the record
date of such dividends and vested upon the same schedule as the underlying restricted stock unit.
The Company measures the cost of awards classified as equity awards based on the grant date fair value of the
award, and the Company measures the cost of awards classified as liability awards at the fair value of the award at
each reporting period. The Company has utilized an estimated 6% annual forfeiture rate of restricted stock units in
determining the fair value for all awards excluding those issued to executive level recipients and non-employee
directors, for which no forfeitures are estimated to occur. The Company has elected to recognize related
compensation expense on a straight-line basis over the associated vesting periods.
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Although the restricted stock units allow for cash settlement of the awards at the sole discretion of management of
the Company, management intends to settle the awards by issuing shares of the Company’s Class A common stock.
Total stock-based compensation expense for the years ended December 31, 2019, 2018 and 2017 was $5.5 million,
$5.9 million and $5.1 million. Total income tax benefit related to stock-based compensation recognized in net
income (loss) was $0.6 million, $0.6 million and $0.8 million for the years ended December 31, 2019, 2018 and
2017.
Equity Classified Restricted Stock Units
Restricted stock units issued to employees and officers of the Company are classified as equity awards. The fair
value of the equity classified restricted stock units is based on the Company’s Class A common stock price as of the
grant date. The Company recognized stock based compensation expense of $5.0 million, $5.3 million and $2.8
million for the years ended December 31, 2019, 2018 and 2017, respectively, in general and administrative expense
with a corresponding increase to additional paid in capital. The following table summarizes equity classified
restricted stock unit activity and unvested restricted stock units for the year ended December 31, 2019:
Unvested at December 31, 2018
Granted
Dividend reinvestment issuances
Vested
Forfeited
Unvested at December 31, 2019
Number of Shares
(in thousands)
Weighted Average Grant
Date Fair Value
827 $
547
53
(450)
(148)
829 $
10.09
9.53
10.07
9.60
10.72
9.88
For the year ended December 31, 2019, 449,725 restricted stock units vested, with 284,896 shares of Class A
common stock distributed to the holders of these units and 164,829 shares of Class A common stock withheld by the
Company to cover taxes owed on the vesting of such units. As of December 31, 2019, there was $5.1 million of
total unrecognized compensation cost related to the Company’s equity classified restricted stock units, which is
expected to be recognized over a weighted average period of approximately 2.5 years.
Change in Control Restricted Stock Units
In 2018, the Company granted Change in Control Restricted Stock Units ("CIC RSUs") to certain officers that vest
upon a "Change in Control", if certain conditions are met. The terms of the CIC RSUs define a "Change in Control"
to generally mean:
–
–
the consummation of an agreement to acquire or tender offer for beneficial ownership by any person, of
50% or more of the combined voting power of our outstanding voting securities entitled to vote generally in
the election of directors, or by any person of 90% or more of the then total outstanding shares of Class A
common stock;
individuals who constitute the incumbent board cease for any reason to constitute at least a majority of the
board;
– consummation of certain reorganizations, mergers or consolidations or a sale or other disposition of all or
substantially all of our assets;
– approval by our stockholders of a complete liquidation or dissolution;
– a public offering or series of public offerings by Retailco and its affiliates, as a selling shareholder group, in
which their total interest drops below 10 million of our total outstanding voting securities;
– a disposition by Retailco and its affiliates in which their total interest drops below 10 million of our total
outstanding voting securities; or
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– any other business combination, liquidation event of Retailco and its affiliates or restructuring of us which
the Compensation Committee deems in its discretion to achieve the principles of a Change in Control.
The equity classified restricted stock unit table above excludes unvested CIC RSUs as the conditions for Change in
Control have not been met. The Company has not recognized stock compensation expense related to the CIC RSUs
as the Change in Control conditions have not been met.
Liability Classified Restricted Stock Units
Restricted stock units issued to non-employee directors of the Company and employees of certain of our affiliates
are classified as liability awards as the awards are either to a) non-employee directors that allow for the recipient to
choose net settlement for the amount of withholding taxes dues upon vesting or b) to employees of certain affiliates
of the Company and are therefore not deemed to be employees of the Company. The fair value of the liability
classified restricted stock units is based on the Company’s Class A common stock price as of the reported period
ending date. The Company recognized stock based compensation expense of $0.5 million, $0.6 million and $2.3
million for years ended December 31, 2019, 2018 and 2017, respectively, in general and administrative expense
with a corresponding increase to liabilities. As of December 31, 2019, the Company’s liabilities related to these
restricted stock units recorded in current liabilities was $0.2 million. As of December 31, 2018, the Company's
liabilities related to these restricted stock units recorded in current liabilities was $0.2 million. The following table
summarizes liability classified restricted stock unit activity and unvested restricted stock units for the year ended
December 31, 2019:
Unvested at December 31, 2018
Granted
Dividend reinvestment issuances
Vested
Forfeited
Unvested at December 31, 2019
Number of Shares
(in thousands)
Weighted Average Reporting
Date Fair Value
68 $
76
4
(24)
(96)
28 $
7.43
9.23
9.23
10.25
9.27
9.23
For the year ended December 31, 2019, 23,767 restricted stock units vested, with 15,819 shares of Class A common
stock distributed to the holders of these units and 7,948 shares of Class A common stock withheld by the Company
to cover taxes owed on the vesting of such units. As of December 31, 2019, there was $0.1 million of total
unrecognized compensation cost related to the Company’s liability classified restricted stock units, which is
expected to be recognized over a weighted average period of approximately 0.4 years.
13. Income Taxes
We and our subsidiaries, CenStar and Verde Energy USA, Inc. ("Verde Corp") are each subject to U.S. federal
income tax as corporations. CenStar and Verde Corp file consolidated tax returns in jurisdictions that allow
combined reporting. Spark HoldCo and its subsidiaries, with the exception of CenStar and Verde Corp, are treated
as flow-through entities for U.S. federal income tax purposes, and, as such, are generally not subject to U.S. federal
income tax at the entity level. Rather, the tax liability with respect to their taxable income is passed through to their
members or partners. Accordingly, we are subject to U.S. federal income taxation on our allocable share of Spark
HoldCo's net U.S. taxable income.
In our financial statements, we report federal and state income taxes for our share of the partnership income
attributable to our ownership in Spark HoldCo and for the income taxes attributable to CenStar and Verde Corp. Net
income attributable to non-controlling interest includes the provision for income taxes related to CenStar and Verde
Corp.
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We account for income taxes using the asset and liability method. Deferred tax assets and liabilities are recognized
for future tax consequences attributable to differences between the financial statement carrying amounts of existing
assets and liabilities and the tax bases of the assets and liabilities. We apply existing tax law and the tax rate that we
expect to apply to taxable income in the years in which those differences are expected to be recovered or settled in
calculating the deferred tax assets and liabilities. Effects of changes in tax rates on deferred tax assets and liabilities
are recognized in income in the period of the tax rate enactment. A valuation allowance is recorded when it is not
more likely than not that some or all of the benefit from the deferred tax asset will be realized.
In December 2017, the President signed the U.S. Tax Reform legislation, which enacted a wide range of changes to
the U.S. Corporate income tax system. Accordingly, we adjusted the value of our U.S. deferred tax assets and
liabilities based on the rates at which they are expected to be recognized in the future. For U.S. federal purposes the
corporate statutory income tax rate was reduced from 35% to 21%, effective for the 2018 tax year. During 2018, we
completed our analysis of the impact of U.S. Tax Reform based on further guidance provided on the new tax law by
the U.S. Treasury Department and Internal Revenue Service, with no material changes from our assessment
performed as of December 31, 2017.
The provision for income taxes for the years ended December 31, 2019, 2018, and 2017 included the following
components:
(in thousands)
Current:
Federal
State
Total Current
Deferred:
Federal
State
Total Deferred
Provision for income taxes
2019
2018
2017
$
$
10,511
3,675
14,186
(4,668)
(2,261)
(6,929)
7,257
$
$
3,862
1,099
4,961
(2,792)
(92)
(2,884)
2,077
$
$
6,992
1,952
8,944
27,820
2,001
29,821
38,765
The effective income tax rate was 34%, (17)%, and 34% for the years ended December 31, 2019, 2018, and 2017,
respectively. The following table reconciles the income tax benefit that would result from application of the statutory
federal tax rate, 21%, 21%, and 35% for the years ended December 31, 2019, 2018, and 2017 respectively, to the
amount included in the consolidated statement of operations:
(in thousands)
Expected provision at federal statutory rate
(Decrease) increase resulting from:
Non-controlling interest
Class A Preferred Stock dividends
Impact of U.S. Tax Reform
Intra-entity transfer of customer contracts
State income taxes, net of federal income tax effect
Prior year true-up
Non-deductible expenses
Other
2019
2018
2017
$
4,509
$
(2,586)
$
39,833
(1,329)
1,341
—
—
1,382
1,060
256
38
7,257
$
1,738
1,579
—
473
428
(31)
256
220
2,077
$
(19,810)
1,758
14,454
—
2,569
—
234
(273)
38,765
Provision for income taxes
$
Total income tax expense for the years ended December 31, 2019 and 2018 differed from amounts computed by
applying the U.S. federal statutory tax rates to pre-tax income primarily due to state income taxes and the impact of
permanent differences between book and taxable income, most notably the income attributable to non-controlling
interest, which gets taxed at the non-controlling interest partner level. The effective rate in 2017 was also impacted
105
by the enactment of U.S. Tax Reform. Since we were in a net deferred tax asset position, the rate reduced our
overall asset having an unfavorable effect on tax expense.
The components of our deferred tax assets as of December 31, 2019 and 2018 are as follows:
(in thousands)
Deferred Tax Assets:
Investment in Spark HoldCo
Benefit of TRA Liability
State net operating loss carryforward
Derivative Liabilities
Other
Total deferred tax assets
Deferred Tax Liabilities:
Derivative liabilities
Intangibles
Property and equipment
Total deferred tax liabilities
Total deferred tax assets/liabilities
2019
2018
28,671 $
—
140
1,669
220
30,700
—
(808)
(27)
(835)
29,865 $
22,251
7,016
—
—
78
29,345
(715)
(849)
(460)
(2,024)
27,321
$
$
The benefit of the TRA Liability as of December 31, 2018 related to the step up in tax basis resulting from the
purchase by the Company of Spark HoldCo units from our Founder at the time of our IPO. Subsequent issuances of
Series A common stock, exchanges of Series A Common Stock for Series B Shares and vesting of incentive stock
compensation since our IPO also resulted in step ups in the basis of our stock similarly resulting in a liability under
our Tax Receivable Agreement prior to it being settled in July 2019. As a result of the settlement, there is no
outstanding liability as of December 31, 2019. For the period ending December 31, 2018, we had a current liability
of $1.7 million and a long-term liability of $25.9 million to reflect the obligation under the Tax Receivable
Agreement. See Note 15 "Transactions with Affiliates" for further discussion.
We periodically assess whether it is more likely than not that we will generate sufficient taxable income to realize
our deferred income tax assets. In making this determination, we consider all available positive and negative
evidence and makes certain assumptions. We consider, among other things, our deferred tax liabilities, the overall
business environment, our historical earnings and losses, current industry trends, and our outlook for future years.
We believe it is more likely than not that our deferred tax assets will be utilized, and accordingly have not recorded
a valuation allowance on these assets.
The tax years 2013 through 2017 remain open to examination by the major taxing jurisdictions to which the
Company is subject to income tax. An affiliate owned by our Founder would be responsible for any audit
adjustments incurred in connection with transactions occurring prior to July 2014 for Spark Energy, Inc. and Spark
HoldCo.
Accounting for uncertainty in income taxes prescribes a recognition threshold and measurement methodology for
the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return.
As of December 31, 2019 and 2018 there was no liability, and for the years ended December 31, 2019, 2018 and
2017, there was no expense recorded for interest and penalties associated with uncertain tax positions or
unrecognized tax positions. Additionally, the Company does not have unrecognized tax benefits as of December 31,
2019 and 2018.
14. Commitments and Contingencies
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From time to time, we may be involved in legal, tax, regulatory and other proceedings in the ordinary course of
business. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded
when it is probable that a liability has been incurred and the amount can be reasonably estimated.
Legal Proceedings
Below is a summary of our currently pending material legal proceedings. We are subject to lawsuits and claims
arising in the ordinary course of our business. The following legal proceedings are in various stages and are subject
to substantial uncertainties concerning the outcome of material factual and legal issues. Accordingly, unless
otherwise specifically noted, we cannot currently predict the manner and timing of the resolutions of these legal
proceedings or estimate a range of possible losses or a minimum loss that could result from an adverse verdict in a
potential lawsuit. While the lawsuits and claims are asserted for amounts that may be material should an
unfavorable outcome occur, management does not currently expect that any currently pending matters will have a
material adverse effect on our financial position or results of operations.
Consumer Rate Lawsuits
The Company, like other ESCOs in the industry, is subject to several class actions in various jurisdictions where the
Company sells energy, such actions alleging consumers paid higher rates than they would have if they stayed with
the default utility.
Janet Rolland, et al v. Spark Energy, LLC is a purported class action originally filed on April 19, 2017 in the United
States District Court for the District of New Jersey alleging that Spark Energy, LLC charged a variable rate that was
higher than permitted by its terms of service, resulting in breach of contract and violation of the duty of good faith
and fair dealing. Plaintiffs alleged claims under the New Jersey Consumer Fraud Act and Illinois Consumer Fraud
and Deceptive Business Practices Act. The case seeks to certify a putative nationwide class of all Spark variable
rate electricity customers from April 19, 2011 to the present. The relief sought includes unspecified actual damages,
refunds, treble damages and punitive damages for the putative class, injunctive relief, attorneys’ fees and costs of
suit. Spark obtained dismissal with prejudice of the New Jersey Consumer Fraud Act claim and has sought
dismissal of the Illinois Consumer Fraud and Deceptive Business Practices Act claim and other claims. Discovery is
ongoing in this matter. Spark denies the allegations asserted by Plaintiffs and intends to vigorously defend this
matter. Given the ongoing discovery and current stage of this matter, we cannot predict the outcome of this case at
this time.
Katherine Veilleux, et. al. v. Electricity Maine LLC, Provider Power, LLC, Spark HoldCo, LLC, Kevin Dean, and
Emile Clavet is a purported class action lawsuit filed on November 18, 2016 in the United States District Court of
Maine, alleging that Electricity Maine, LLC ("Electricity Maine"), an entity acquired by Spark Holdco in mid-2016,
enrolled customers and conducted advertising, and promotions not in compliance with law. Plaintiffs seek damages
for themselves and the purported class, injunctive relief, restitution, and attorneys' fees. The parties are completing a
settlement agreement and will present such Agreement to the court for approval, which we expect the court to
review in second quarter of 2020.
Gillis et al. v. Respond Power, LLC is a purported class action lawsuit that was originally filed on May 21, 2014 in
the Philadelphia Court of Common Pleas but was later removed to the United States District Court for the Eastern
District of Pennsylvania. On July 16, 2018, the district court granted Respond Power LLC's motion to dismiss the
Plaintiff’s class action claims. Plaintiffs filed their notice of appeal to the Third Circuit Court on August 7, 2018.
The Third Circuit ruled in favor of Respond Power on February 3, 2019. Barring an appeal to the Supreme Court of
United States, this matter has been resolved in Respond Power's favor.
Jurich v. Verde Energy USA, Inc. is a class action originally filed on March 3, 2015 in the United States District
Court for the District of Connecticut and subsequently re-filed on October 8, 2015 in the Superior Court of Judicial
District of Hartford, State of Connecticut. The Amended Complaint asserts that the Verde Companies charged rates
in violation of its contracts with Connecticut customers and alleges (i) violation of the Connecticut Unfair Trade
107
Practices Act, Conn. Gen. Stat. §§ 42-110a et seq., and (ii) breach of the covenant of good faith and fair dealing.
Plaintiffs are seeking unspecified actual and punitive damages for the class and injunctive relief. As part of an
agreement in connection with the acquisition of the Verde Companies, the original owners of the Verde Companies
are handling this matter. The parties have reached a class settlement in this matter, which has received final court
approval, and an order of dismissal on February 24, 2020. Settlement claims’ administration is continuing. The
Company believes it has full indemnity coverage, net of tax benefit, for any actual exposure in this case at this time.
Telemarketing Lawsuits
Albrecht v. Oasis Power, LLC is a putative nationwide class action that was filed on February 12, 2018 in the United
States District Court for the Northern District of Illinois, alleging that Oasis made illegal prerecorded telemarketing
calls, including auto-dialed calls, to consumers’ mobile phones, in violation of the Telephone Consumer Protection
Act ("TCPA") and the Illinois Automatic Telephone Dialers Act ("ATDA"). Plaintiff sought an injunction requiring
Oasis to cease all unsolicited calling activities, an award of statutory and trebled damages under the TCPA and the
ATDA, as well as costs and attorney’s fees. The parties have reached a class settlement on behalf of Oasis and other
affiliated brands in the amount of $7.0 million, which received final court approval on February 6, 2020. Settlement
claims’ administration has commenced.
Richardson et. al. v. Verde Energy USA, Inc. is a purported class action filed on November 25, 2015 in the United
States District Court for the Eastern District of Pennsylvania alleging that the Verde Companies violated the
Telephone Consumer Protection Act ("TCPA") by placing marketing calls using an automatic telephone dialing
system ("ATDS") or a prerecorded voice to the purported class members’ cellular phones without prior express
consent and by continuing to make such calls after receiving requests for the calls to cease. Following discovery
and dispositive motions, the Verde Companies received a favorable ruling on summary judgment with the court
agreeing with the Verde Companies that the call system used in this case was not an ATDS as defined by the TCPA.
Plaintiffs subsequently amended their petition eliminating their ATDS claim and including a class based on failure
to comply with the National Do Not Call registry. As part of an agreement in connection with the acquisition of the
Verde Companies, the original owners of the Verde Companies are handling this matter. The parties reached a
settlement in this matter. On January 17, 2020, the court approved the Parties’ preliminary settlement and settlement
claims’ administration has commenced. The Company believes it has full indemnity coverage, net of tax benefit, for
the settlement exposure in this case.
Corporate Matter Lawsuits
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., is a lawsuit filed on October 17, 2017 in the United States District
Court for the Southern District of New York asserting claims of fraudulent inducement against NG&E, breach of
contract against NG&E and Spark, and tortious interference with contract against Spark related to a membership
interest purchase agreement, subsequent dropdown, and associated earnout agreements with the Major Energy
Companies' former owners. The relief sought includes unspecified compensatory and punitive damages,
prejudgment and post-judgment interest, and attorneys’ fees. On September 24, 2018, the court granted Defendants’
motion to dismiss in part and dismissed Plaintiffs’ fraudulent inducement claims. NG&E and Spark filed their
affirmative defenses and answer to the remaining claims on October 15, 2018. On January 14, 2019, Plaintiffs filed
a Motion for Partial Summary Judgment, which was subsequently denied by the Court on May 8, 2019. On March
25, 2019, Spark and NG&E filed a Motion for Sanctions in connection with deletion of electronically stored data by
plaintiff Saul Horowitz and co-seller Mark Wiederman after receiving a litigation hold notice, which the Court
granted in part on May 8, 2019, including an award of attorneys' fees and costs to Spark and NG&E in connection
with the Motion for Sanctions. On June 7, 2019, the parties jointly filed a letter agreement with the Court
confirming plaintiff’s payment of fees and costs, including costs associated with forensic analysis, in the amount of
less than $0.1 million to Spark and NG&E in connection with the Court’s ruling on their Motion for Sanctions. This
case is set for trial to commence on March 2, 2020. Spark and NG&E deny the allegations asserted by Plaintiffs and
intend to vigorously defend this matter.
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Regulatory Matters
Many state regulators have increased scrutiny on retail energy providers, across all industry providers. We are
subject to regular regulatory inquiries and preliminary investigations in the ordinary course of our business. Below
is a summary of our currently pending material state regulatory matters. The following state regulatory matters are
in various stages and are subject to substantial uncertainties concerning the outcome of material factual and legal
issues. Accordingly, we cannot currently predict the manner and timing of the resolution of these state regulatory
matters or estimate a range of possible losses or a minimum loss that could result from an adverse action.
Management does not currently expect that any currently pending state regulatory matters will have a material
adverse effect on our financial position or results of operations.
Connecticut. Spark Energy, LLC ("SE LLC") has been working with the Connecticut Public Utilities Regulatory
Authority ("PURA") regarding compliance with requirements implemented in 2016 that customer bills include any
changes to existing rates effective for the next billing cycle. SE LLC and other ESCOs in Connecticut have agreed
to submit to a proceeding offering amnesty to ESCOs that self-report violations and offer to voluntarily remit
refunds to customers. Spark has remitted its report of potential customers who would be eligible for refunds under
the amnesty program and submitted its confidential settlement proposal along with SE LLC’s commitment, subject
to certain conditions. SE LLC is awaiting PURA’s completion of a review and audit process after which SE LLC
expects PURA to issue a final decision on SE LLC’s offer of amnesty.
Illinois. The Illinois Attorney General brought action against Major Energy Electric Services, LLC ("Major") for
injunctive and other relief asserting claims that Major engaged in a pattern and practice of non-compliance with law
through door-to-door and telephone solicitations, in-person solicitations at retail establishments, advertisements on
its website and direct mail advertisements to sign up for electricity services. The complaint seeks injunctive relief
and monetary damages representing the amounts Illinois consumers have allegedly lost due to such non-compliant
marketing activities. The Attorney General also requested civil penalties. The parties resolved this matter on August
16, 2019. A final judgment and consent decree was entered into, which included Major paying $2.0 million in
refunds to consumers, and $0.1 million as a voluntary contribution to the Illinois Attorney General's Office. The
settlement also included a number of injunctive and reporting provisions with which Major must comply. Major has
made the refund payment.
In a separate matter, Spark Energy, LLC received a verbal inquiry from the Illinois Commerce Commission ("ICC")
and the Illinois Attorney General ("IAG") on January 1, 2020 seeking to understand an increase in complaints from
Illinois consumers. The Company met with the ICC and the IAG in February 2020 and plan to discuss a compliance
plan to ensure its sales are in compliance with Illinois regulations. The parties also discussed possible restitution
payments to any customers impacted by sales not in compliance with Illinois regulations.
Maine. In early 2018, Staff of the Maine Public Utilities Commission (“Maine PUC”) issued letters to Electricity
Maine seeking information about customer complaints principally associated with door-to-door (“D2D”) sales
practices. In late July 2018, the Maine PUC issued an Order to Show Cause to which Electricity Maine filed a
detailed response in mid-August 2018. After a lengthy period of inactivity, the Commission scheduled a procedural
conference in early 2019 that resulted in no intervenors other than participation as a party by the Maine Office of
Public Advocate. At the conference, the parties agreed on a procedural schedule, including a one-day evidentiary
hearing. Following post-hearing discovery, Initial and Reply Briefs were filed on August 30, 2019 and September
10, 2019, respectively. The parties are awaiting a proposed ruling from the Maine PUC hearing examiner, after
which point the parties can either accept the ruling or take exception and argue the merits before the Maine PUC
Commissioners. While investigations of this nature may be resolved in a manner that allows the retail energy
supplier to continue operating in Maine with stipulations, there can be no assurances that Maine PUC will not take
more severe action.
New York. Prior to the purchase of Major Energy by the Company, in 2015, Major Energy Services, LLC and Major
Energy Electric Services were contacted by the Attorney General, Bureau of Consumer Frauds & Protection for
State of New York relating to their marketing practices. Major Energy has exchanged information in response to
various requests from the Attorney General. The Parties are in settlement negotiations at this time. While
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investigations of this nature may be resolved in a manner that allows the retail energy supplier to continue operating
in New York with stipulations, there can be no assurances that the New York Attorney General will not take more
severe action.
Ohio. Verde Energy USA Ohio, LLC (“Verde Ohio”) is the subject of a formal investigation by the Public Utilities
Commission of Ohio (“PUCO”) initiated on April 16, 2019. The investigation asserts that Verde Ohio may have
violated Ohio’s retail energy supplier regulations. Verde Ohio voluntary suspended door-to-door marketing in Ohio
in furtherance of settlement negotiations with the PUCO Staff. On September 6, 2019, Verde Ohio and PUCO Staff
executed and filed with PUCO a Joint Stipulation and Recommendation for PUCO’s review and approval which
sets forth agreed settlement terms, which includes a $1.7 million settlement amount. If approved by PUCO, the
Joint Stipulation and Recommendation would resolve all of the issues raised in the investigation. In addition, in
September of 2019, the Ohio Attorney General (“OAG”) alleged that Verde Ohio had violated its Consumer Sales
Practice Act and Do Not Call regulations. Verde Ohio is cooperating and responding to the OAG’s document
requests; however, at this time, the Company cannot predict the outcome of this matter.
Pennsylvania. Verde Energy USA, Inc. (“Verde”) is the subject of a formal investigation by the Pennsylvania Public
Utility Commission, Bureau of Investigation and Enforcement (“PPUC”) initiated on January 30, 2020. The
investigation asserts that Verde may have violated Pennsylvania retail energy supplier regulations. The Company
met with the PPUC in February 2020 to discuss the matter and work with the PPUC cooperatively. Verde is
cooperating and responding to the PPUC's requests for information. Currently, the Company cannot predict the
outcome at this time.
Indirect Tax Audits
We are undergoing various types of indirect tax audits spanning from years 2013 to 2018 for which we may have
additional liabilities arise. At the time of filing these consolidated financial statements, these indirect tax audits are
at an early stage and subject to substantial uncertainties concerning the outcome of audit findings and corresponding
responses.
As of December 31, 2019, we had accrued $29.2 million related to litigation and regulatory matters and $1.8
million related to indirect tax audits. The outcome of each of these may result in additional expense.
15. Transactions with Affiliates
Transactions with Affiliates
We enter into transactions with and pay certain costs on behalf of affiliates that are commonly controlled in order to
reduce risk, reduce administrative expense, create economies of scale, create strategic alliances and supply goods
and services to these related parties. We also sell and purchase natural gas and electricity with affiliates. We present
receivables and payables with the same affiliate on a net basis in the consolidated balance sheets as all affiliate
activity is with parties under common control. Affiliated transactions include certain services to the affiliated
companies associated with employee benefits provided through our benefit plans, insurance plans, leased office
space, administrative salaries, due diligence work, recurring management consulting, and accounting, tax, legal, or
technology services. Amounts billed are based on the services provided, departmental usage, or headcount, which
are considered reasonable by management. As such, the accompanying consolidated financial statements include
costs that have been incurred by us and then directly billed or allocated to affiliates, as well as costs that have been
incurred by our affiliates and then directly billed or allocated to us, and are recorded net in general and
administrative expense on the consolidated statements of operations with a corresponding accounts receivable—
affiliates or accounts payable—affiliates, respectively, recorded in the consolidated balance sheets. Transactions
with affiliates for sales or purchases of natural gas and electricity, are recorded in retail revenues, retail cost of
revenues, and net asset optimization revenues in the consolidated statements of operations with a corresponding
accounts receivable—affiliate or accounts payable—affiliate recorded in the consolidated balance sheets.
Master Service Agreement with Retailco Services, LLC
110
Prior to April 1, 2018, we were a party to a Master Service Agreement with an affiliated company owned by our
Founder. The Master Service Agreement provided us with operational support services such as: enrollment and
renewal transaction services; customer billing and transaction services; electronic payment processing services;
customer service, and information technology infrastructure and application support services. Effective April 1,
2018, we terminated the agreement, and these operational support services were transferred back to us. See "Cost
Allocations" below for further discussion of the fees paid to affiliates during the years ended December 31, 2019,
2018, and 2017 respectively.
Cost Allocations
Where costs incurred on behalf of the affiliate or us cannot be determined by specific identification for direct
billing, the costs are allocated to the affiliated entities or us based on estimates of percentage of departmental usage,
wages or headcount. The total net amount direct billed and allocated (to)/from affiliates was $(0.7) million, $10.3
million and $25.4 million for the years ended December 31, 2019, 2018 and 2017, respectively.
Of the amounts directly billed and allocated from affiliates, we recorded general and administrative expense of zero,
$5.9 million, and $22.0 million for the years ended December 31, 2019, 2018 and 2017, respectively. Additionally,
we capitalized zero, 0.5 million, and $0.7 million of property and equipment for the application, development and
implementation of various systems during the years ended December 31, 2019, 2018 and 2017, respectively.
Accounts Receivable and Payable—Affiliates
As of December 31, 2019 and 2018, we had current accounts receivable—affiliates of $2.0 million and $2.6
million, respectively, and current accounts payable—affiliates of $1.0 million and $2.5 million, respectively.
Revenues and Cost of Revenues—Affiliates
Revenues recorded in net asset optimization revenues in the consolidated statements of operations for the years
ended December 31, 2019, 2018 and 2017 related to affiliated sales were $2.4 million, $2.4 million, and $1.3
million, respectively, and cost of revenues recorded in net asset optimization revenues in the consolidated
statements of operations for the years ended December 31, 2019, 2018 and 2017 related to affiliated purchases were
$0.1 million, $0.1 million and $0.1 million, respectively. These amounts are presented as net on the Consolidated
Statements of Operations.
Acquisitions from Related Parties
In 2017, we acquired Perigee from our affiliate, NG&E, for total consideration of approximately $4.1 million.
In connection with the Major Energy Companies acquisition, we issued 4,000,000 shares of Class B common stock
(and a corresponding number of Spark HoldCo units) to NG&E, valued at $40.0 million. In connection with the
financing of the Provider Companies acquisition, we issued 1,399,484 shares of Class B common stock (and a
corresponding number of Spark HoldCo units) to RetailCo, valued at $14.0 million.
In March 2018, we entered into an asset purchase agreement with an affiliate to acquire up to 50,000 RCEs for a
cash purchase price of $250 for each RCE, or up to $12.5 million in the aggregate. A total of $8.8 million was paid
in 2018 under the terms of the purchase agreement for approximately 35,000 RCEs, and no further material
payments are anticipated. The acquisition was treated as a transfer of assets between entities under common control,
and accordingly, the assets were recorded at their historical value at the date of transfer. The transaction resulted
in less than $0.1 million and $7.1 million recorded in equity as a net distribution to affiliate as of December 31,
2019 and 2018, respectively.
Distributions to and Contributions from Affiliates
111
During the years ended December 31, 2019, 2018 and 2017, we made distributions to affiliates of our Founder of
$15.1 million, $15.5 million and $15.6 million, respectively, for payments of quarterly distributions on their
respective Spark HoldCo units. During the years ended December 31, 2019, 2018 and 2017, we also made
distributions to these affiliates for gross-up distributions of $19.7 million, $16.5 million, and $18.2 million,
respectively, in connection with distributions made between Spark HoldCo and Spark Energy, Inc. for payment of
income taxes incurred by us and settlement of the TRA.
Proceeds from Disgorgement of Stockholder Short-swing Profits
During the years ended December 31, 2019, 2018 and 2017, we recorded $0.1 million, zero, and $0.7 million,
respectively, for the disgorgement of stockholder short-swing profits under Section 16(b) under the Exchange Act.
The amount was recorded as an increase to additional paid-in capital in our consolidated balance sheet as of
December 31, 2019, 2018 and 2017. We received $0.5 million cash during the year ended December 31, 2017 and
received $0.2 million cash in February 2018.
Subordinated Debt Facility
In June 2019, we and Spark HoldCo entered into a Subordinated Debt Facility with an affiliate owned by our
Founder, which allows the Company to borrow up to $25.0 million. The Subordinated Debt Facility allows us to
draw advances in increments of no less than $1.0 million per advance up to the maximum principal amount of the
Subordinated Debt Facility. Advances thereunder accrue interest at 5% per annum from the date of the advance. As
of December 31, 2019 and 2018, there was zero and $10.0 million, respectively, in outstanding borrowings under
the Subordinated Debt Facility. See Note 10 "Debt" for a further description of terms and conditions of the
Subordinated Debt Facility.
Tax Receivable Agreement
Prior to July 11, 2019, we were party to a TRA with affiliates. Effective July 11, 2019, the Company entered into a
TRA Termination and Release Agreement (the “Release Agreement”), which provided for a full and complete
termination of any further payment, reimbursement or performance obligation of the Company, Retailco and
NuDevco Retail under the TRA, whether past, accrued or yet to arise. Pursuant to the Release Agreement, the
Company made a cash payment of approximately $11.2 million on July 15, 2019 to Retailco and NuDevco Retail.
In connection with the termination of the TRA, Spark HoldCo made a distribution of approximately $16.3 million
on July 15, 2019 to Retailco and NuDevco Retail under the Spark HoldCo Third Amended and Restated Limited
Liability Company Agreement, as amended.
The TRA generally provided for the payment by us to affiliates of 85% of the net cash savings, if any, in U.S.
federal, state and local income tax or franchise tax that we realized or would realize (or were deemed to realize in
certain circumstances) in future periods as a result of (i) any tax basis increases resulting from the initial purchase
by us of Spark HoldCo units from entities owned by our Founder, (ii) any tax basis increases resulting from the
exchange of Spark HoldCo units for shares of Class A common stock pursuant to the Exchange Right (or resulting
from an exchange of Spark HoldCo units for cash pursuant to the Cash Option) and (iii) any imputed interest
deemed to be paid by us as a result of, and additional tax basis arising from, any payments we made under the TRA.
We retained the benefit of the remaining 15% of these tax savings. See Note 13 "Income Taxes" for further
discussion.
For the four-quarter periods ending September 30, 2016, 2017, and 2018, we met the threshold coverage ratio
required to fund the payments required under the TRA. Our affiliates, however, granted us the right to defer the
TRA payment related to the four-quarter period ending September 30, 2016 until May 2018. In April, May, and
December of 2018, we paid a total of $6.2 million related to our obligations under the TRA for the 2015, 2016, and
2017 tax years.
As of December 31, 2019 and 2018, we had a total liability related to the TRA of zero and $27.6 million, of which
zero and $1.7 million, respectively, were classified as current liabilities.
112
16. Segment Reporting
Our determination of reportable business segments considers the strategic operating units under which we make
financial decisions, allocate resources and assess performance of our business. Our reportable business segments are
retail electricity and retail natural gas. The retail electricity segment consists of electricity sales and transmission to
residential and commercial customers. The retail natural gas segment consists of natural gas sales to, and natural
gas transportation and distribution for, residential and commercial customers. Corporate and other consists of
expenses and assets of the retail electricity and natural gas segments that are managed at a consolidated level such
as general and administrative expenses. Asset optimization activities are also included in Corporate and other.
For the years ended December 31, 2019, 2018 and 2017, we recorded asset optimization revenues of $62.8 million,
$113.7 million and $178.3 million and asset optimization cost of revenues of $60.0 million, $109.2 million and
$179.0 million, respectively, which are presented on a net basis in asset optimization revenues.
The acquisitions of Perigee and the Verde Companies in 2017 and the acquisition of HIKO in 2018 had no impact
on our reportable business segments as the portions of those acquisitions related to retail natural gas and retail
electricity have been included in those existing business segments.
We use retail gross margin to assess the performance of our operating segments. Retail gross margin is defined as
operating income (loss) plus (i) depreciation and amortization expenses and (ii) general and administrative
expenses, less (i) net asset optimization revenues (expenses), (ii) net gains (losses) on non-trading derivative
instruments, and (iii) net current period cash settlements on non-trading derivative instruments. We deduct net gains
(losses) on non-trading derivative instruments, excluding current period cash settlements, from the retail gross
margin calculation in order to remove the non-cash impact of net gains and losses on these derivative instruments.
Retail gross margin should not be considered an alternative to, or more meaningful than, operating income (loss), as
determined in accordance with GAAP.
Below is a reconciliation of retail gross margin to income (loss) before income tax expense (in thousands):
(in thousands)
Reconciliation of Retail Gross Margin to Income (loss) before taxes
Income (loss) before income tax expense
Change in Tax Receivable Agreement Liability
Gain on disposal of eRex
Total other income/(expense)
Interest expense
Operating income (loss)
Depreciation and amortization
General and administrative
Less:
Net asset optimization revenue (expenses)
Net, (losses) gain on non-trading derivative instruments
Net, Cash settlements on non-trading derivative instruments
Years Ended December 31,
2018
2017
2019
$
21,470
$
—
(4,862)
(1,250)
8,621
23,979
40,987
133,534
2,771
(67,955)
42,944
(12,315) $
—
—
(749)
9,410
(3,654)
52,658
111,431
4,511
(19,571)
(9,614)
113,809
(22,267)
—
(256)
11,134
102,420
42,341
101,127
(717)
5,588
16,508
Retail Gross Margin
$
220,740
$
185,109
$
224,509
Financial data for business segments are as follows (in thousands):
113
Net asset optimization revenue
—
—
2,771
Net asset optimization expense
—
—
4,511
Total Revenues
Retail cost of revenues
Less:
Net, Losses on non-trading derivative
instruments
Current period settlements on non-
trading derivatives
Retail gross margin
Total Assets
Goodwill
Total Revenues
Retail cost of revenues
Less:
Net, Losses on non-trading derivative
instruments
Current period settlements on non-
trading derivatives
Retail gross margin
Total Assets
Goodwill
Total Revenues
Retail cost of revenues
Less:
Net asset optimization expense
Net, Gains on non-trading derivative
instruments
Current period settlements on non-
trading derivatives
Retail gross margin
Total Assets
Goodwill
Significant Customers
Year Ended December 31, 2019
Retail
Electricity
Retail
Natural Gas
Corporate
and Other
Eliminations Consolidated
$
688,451
$
122,503
$
2,771
$
— $
552,250
62,975
—
(66,180)
(1,775)
—
41,841
160,540
2,524,884
117,813
$
$
$
$
$
$
1,103
60,200
820,601
2,530
$
$
$
—
— $
$
341,411
—
— $
(3,263,928) $
— $
— $
Year Ended December 31, 2018
Retail
Electricity
Retail
Natural Gas
Corporate
and Other
Eliminations Consolidated
$
863,451
$
762,771
$
137,966
82,722
$
4,511
—
— $
—
1,005,928
845,493
—
—
—
—
—
813,725
615,225
2,771
(67,955)
42,944
220,740
422,968
120,343
4,511
(19,571)
(9,614)
185,109
488,738
(15,200)
(4,371)
—
(8,788)
124,668
1,857,790
117,813
$
$
$
$
$
$
(826)
60,441
649,969
2,530
$
$
$
Year Ended December 31, 2017
—
— $
$
361,697
—
— $
(2,380,718) $
— $
— $
120,343
Retail
Electricity
Retail
Natural Gas
Corporate
and Other
Eliminations Consolidated
$
657,566
$
141,206
$
477,012
75,155
—
5,784
—
(196)
(717) $
—
(717)
—
— $
—
—
—
16,302
158,468
1,218,243
117,624
$
$
$
$
$
$
206
66,041
421,896
2,530
$
$
$
—
— $
$
281,176
—
— $
(1,417,574) $
— $
— $
798,055
552,167
(717)
5,588
16,508
224,509
503,741
120,154
114
For each of the years ended December 31, 2019, 2018 and 2017, we did not have any significant customers that
individually accounted for more than 10% of our consolidated retail revenue.
Significant Suppliers
For each of the years ended December 31, 2019, 2018 and 2017, we had one, two, and two significant suppliers that
individually accounted for more than 10% of our consolidated retail cost of revenues and net asset optimization
revenues. For each of the years ended December 31, 2019, 2018 and 2017, these suppliers accounted for 10%, 28%
and 20% of our consolidated cost of revenue.
17. Equity Method Investment
Investment in eREX Spark Marketing Co., Ltd
Prior to November 2019, we, together with eREX Co., Ltd., a Japanese company, were party to an agreement
("eREX JV Agreement") for a joint venture, eREX Spark Marketing Co., Ltd ("ESM"). As part of this agreement,
we made contributions of 156.4 million Japanese Yen, or $1.4 million, for a 20% ownership interest in ESM. We
were entitled to share in 30% of the dividends distributed by ESM for the first year a qualifying dividend was paid
and for the subsequent four years thereafter. After this period, dividends were to be distributed proportionately with
the equity ownership of ESM. ESM's board of directors consists of four directors, one of whom was appointed by
us. In November 2019, Spark HoldCo, LLC entered into a share purchase agreement with eREX Co., Ltd. In
accordance with the agreement, Spark HoldCo, LLC sold its shares which represented 20% ownership interest in
ESM for $8.4 million. The disposal of ESM resulted in a non-recurring gain of $4.9 million for the year ended
December 31, 2019. Based on our significant influence, as reflected by the 20% equity ownership and 25% control
of the ESM board of directors, we recorded the investment in ESM as an equity method investment.
Our investment in ESM was $3.1 million as of December 31, 2018, reflecting contributions made by us through
December 31, 2018 and our proportionate share of earnings as determined under the HLBV method as of
December 31, 2018, and recorded in other assets in the consolidated balance sheet. There were no basis differences
between our initial contribution and the underlying net assets of ESM. We recorded our proportionate share of
ESM's earnings of $0.8 million and $0.5 million in our consolidated statement of operations for the years ended
December 31, 2019 and 2018, respectively.
18. Subsequent Events
Declaration of Dividends
On January 21, 2020, we declared a quarterly dividend of $0.18125 per share to holders of record of our Class A
common stock on March 2, 2020, which will be paid on March 16, 2020.
We also declared a quarterly cash dividend in the amount of $0.546875 per share to holders of record of the Series
A Preferred Stock on April 1, 2020. The dividend will be paid on April 15, 2020.
115
Supplemental Quarterly Financial Data (unaudited)
Summarized unaudited quarterly financial data is as follows:
Total Revenues
Operating income (loss)
Net (loss) income
Net (loss) income attributable to Spark Energy,
Inc. stockholders
Net (loss) income attributable to stockholders of
Class A common stock
Net (loss) income attributable to Spark Energy,
Inc. per common share—basic
Net (loss) income attributable to Spark Energy,
Inc. per common share—diluted
Total Revenues
Operating (loss) income
Net (loss) income
Net (loss) income attributable to Spark Energy,
Inc. stockholders
Net (loss) income attributable to stockholders of
Class A common stock
Net income (loss) attributable to Spark Energy,
Inc. per common share—basic
Net income (loss) attributable to Spark Energy,
Inc. per common share—diluted
Quarter Ended
2019
December 31,
2019
September 30,
2019
June 30,
2019
March 31,
2019
(In thousands, except per share data)
$
186,183
$
207,087
$
177,749
$
242,706
633
(724)
(751)
(2,762)
(0.19)
(0.19)
46,095
37,676
15,534
13,508
0.94
0.93
(28,569)
(25,484)
(7,115)
5,820
2,745
782
(9,142)
(1,245)
(0.64)
(0.73)
(0.09)
(0.09)
Quarter Ended
2018
December 31,
2018
September 30,
2018
June 30,
2018
March 31,
2018
(In thousands, except per share data)
$
228,514
$
258,475
$
232,251
$
286,688
25,454
18,827
6,767
4,740
0.35
0.35
28,941
23,927
8,785
6,757
0.51
0.51
(46,254)
(41,831)
(11,105)
(13,132)
(1.00)
(1.04)
(11,795)
(15,315)
(5,633)
(7,660)
0.56
0.58
116
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
Our management, with the participation of our Chief Executive Officer and our Chief Financial Officer, has evaluated
the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Annual Report
on Form 10-K. The term “disclosure controls and procedures,” as defined in Rules 13a-15(e) and 15d-15(e) under the
Exchange Act, means controls and other procedures of a company that are designed to ensure that information required
to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed,
summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and
procedures include, without limitation, controls and procedures designed to ensure that information required to be
disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated
to the company’s management, including its principal executive and principal financial officers or persons performing
similar functions, as appropriate to allow timely decisions regarding required disclosure. Management recognizes that
any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of
achieving their objectives, and management necessarily applies its judgment in evaluating the cost benefit relationship
of possible controls and procedures. Based on this evaluation, management concluded that our disclosure controls and
procedures were effective as of December 31, 2019 at the reasonable assurance level.
Management's Annual Report on Internal Control Over Financial Reporting
See "Management's Report on Internal Control Over Financial Reporting" under Item 8 of this Annual Report on Form
10-K.
Attestation Report of the Independent Registered Public Accounting Firm
Our independent registered public accounting firm, Ernst & Young LLP, has provided an attestation report on the
Company’s internal control over financial reporting as of December 31, 2019.
Changes in Internal Control over Financial Reporting
There was no change in our internal control over financial reporting identified in connection with the evaluation
required by Rule 13a-15(d) and 15d-15(d) of the Exchange Act that occurred during the three months ended
December 31, 2019 that has materially affected, or is reasonably likely to materially affect, our internal control over
financial reporting.
Item 9B. Other Information
None.
117
Item 10. Directors, Executive Officers and Corporate Governance
PART III.
Information as to Item 10 will be set forth in the Proxy Statement for the 2020 Annual Meeting of Shareholders (the
“Annual Meeting”) and is incorporated herein by reference.
Item 11. Executive Compensation
Information as to Item 11 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein
by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management, and Related Stockholder
Matters
Except as provided below, information as to Item 12 will be set forth in the Proxy Statement for the Annual Meeting
and is incorporated herein by reference.
Equity Compensation Plan Information
The following table shows information about our Class A common stock that may be issued under the Spark
Energy, Inc. Amended and Restated Incentive Plan (the “Incentive Plan”) as of December 31, 2019.
Plan category
Equity compensation plans approved by the security holders
Equity compensation plans not approved by the security holders
Total
(a) Number of
securities to be
issued upon exercise
of outstanding
options, warrants
and rights (1)
(c) Number of securities
remaining available for
future issuance under
equity compensation
plans (excluding
securities reflected in
column (a)(2))
1,277,210
—
1,277,210
1,613,364
—
1,613,364
(1) This column reflects the maximum number of shares of Class A common stock that may be issued under outstanding and unvested
restricted stock units ("RSUs") at December 31, 2019. No stock options or warrants have been granted under the Incentive Plan.
(2) This column reflects the total number of shares of Class A common stock remaining available for issuance under the LTIP.
The Incentive Plan is the only plan under which our equity securities are authorized for issuance. The Incentive
Plan was approved by our shareholder prior to our initial public offering and was approved by our public
shareholders in 2019. Please read Note 12 to our consolidated financial statements, entitled "Stock-Based
Compensation" for a description of the Incentive Plan.
118
Item 13. Certain Relationships and Related Transactions, and Director Independence
Information as to Item 13 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein
by reference.
Item 14. Principal Accounting Fees and Services
Information as to Item 14 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein
by reference.
119
Item 15. Exhibits, Financial Statement Schedules
PART IV.
(1) The consolidated financial statements of Spark Energy, Inc. and its subsidiaries and the report of the
independent registered public accounting firm are included in Part II, Item 8 of this Annual Report.
(2) All schedules have been omitted because they are not required under the related instructions, are not applicable
or the information is presented in the consolidated financial statements or related notes.
(3) The exhibits listed on the accompanying Exhibit Index are filed as part of, or incorporated by reference into, this
Annual Report.
120
INDEX TO EXHIBITS
Exhibit
Exhibit Description
2.1#
2.2#
2.3#
2.4#
2.5
2.6#
2.7#
2.8#
3.1
3.2
3.3
Membership Interest Purchase Agreement, by and among
Spark Energy, Inc., Spark HoldCo, LLC, Provider Power,
LLC, Kevin B. Dean and Emile L. Clavet, dated as of May
3, 2016.
Membership Interest Purchase Agreement, by and among
Spark Energy, Inc., Spark HoldCo, LLC, Retailco, LLC and
National Gas & Electric, LLC, dated as of May 3, 2016.
Amendment No. 1 to the Membership Interest Purchase
Agreement, dated as of July 26, 2016, by and among Spark
Energy, Inc., Spark HoldCo, LLC, Provider Power, LLC,
Kevin B. Dean and Emile L. Clavet.
Membership Interest and Stock Purchase Agreement, by and
among Spark Energy, Inc., CenStar Energy Corp. and Verde
Energy USA Holdings, LLC, dated as of May 5, 2017.
First Amendment to the Membership Interest and Stock
Purchase Agreement, dated July 1, 2017, by and among
Spark Energy, Inc., CenStar Energy Corp., and Verde
Energy USA Holdings, LLC.
Agreement to Terminate Earnout Payments, effective
January 12, 2018, by and among Spark Energy, Inc.,
CenStar Energy Corp., Woden Holdings, LLC (fka Verde
Energy USA Holdings, LLC), Verde Energy USA, Inc.,
Thomas FitzGerald, and Anthony Mench.
Asset Purchase Agreement, dated March 7, 2018, by and
between Spark HoldCo, LLC and National Gas & Electric,
LLC
Asset Purchase Agreement by and between Spark HoldCo,
LLC and Starion Energy Inc., Starion Energy NY Inc. and
Starion Energy PA Inc., dated October 19, 2018.
Amended and Restated Certificate of Incorporation of Spark
Energy, Inc.
Amended and Restated Bylaws of Spark Energy, Inc.
Certificate of Designations of Rights and Preferences of
8.75% Series A Fixed-to-Floating Rate Cumulative
Redeemable Perpetual Preferred Stock.
Incorporated by Reference
Form
Exhibit
Number Filing Date
SEC File
No.
10-Q
2.1
5/5/2016
001-36559
10-Q
2.2
5/5/2016
001-36559
8-K
2.1
8/1/2016
001-36559
10-Q
2.4
5/8/2017
001-36559
8-K
2.1
7/6/2017
001-36559
8-K
2.1
1/16/2018
001-36559
10-K
2.7
3/9/2018
001-36559
8-K
2.1
10/25/2018
001-36559
8-K
8-K
3.1
3.2
8/4/2014
001-36559
8/4/2014
001-36559
8-A
5
3/14/2017
001-36559
4.1*
Description of Capital Stock of Spark Energy, Inc.
4.2
4.3
4.4
Class A Common Stock Certificate
S-1
4.1
6/30/2014
333-196375
Convertible Subordinated Promissory Note of Spark
HoldCo, LLC and Spark Energy, Inc. dated July 8, 2015
payable to Retailco Acquisition Co, LLC
Convertible Subordinated Promissory Note of Spark
HoldCo, LLC and Spark Energy, Inc. dated July 31, 2015
payable to Retailco Acquisition Co, LLC
10-Q
10.8
8/13/2015
001-36559
10-Q
10.9
8/13/2015
001-36559
121
4.5
4.6
4.7
10.1
10.2
10.3
10.4
10.5
Promissory Note of CenStar Energy Corp., effective July 1,
2017, payable to Verde USA Holdings, LLC.
8-K
10.1
7/6/2017
001-36559
Amended and Restated Promissory Note of CenStar Energy
Corp., effective January 12, 2018, payable to Woden
Holdings, LLC.
8-K
10.2
1/16/2018
001-36559
Promissory Note of CenStar Energy Corp., effective January
12, 2018, payable to Woden Holdings, LLC.
8-K
10.1
1/16/2018
001-36559
Credit Agreement, dated as of May 19, 2017, among Spark
Energy, Inc., Spark HoldCo, LLC, Spark Energy, LLC,
Spark Energy Gas, LLC, CenStar Energy Corp, CenStar
Operating Company, LLC, Oasis Power, LLC, Oasis Power
Holdings, LLC, Electricity Maine, LLC, Electricity N.H.,
LLC, Provider Power Mass, LLC, Major Energy Services
LLC, Major Energy Electricity Services LLC, Respond
Power LLC and Perigee Energy, LLC as Co-Borrowers,
Coöperatieve Rabobank U.A., New York Branch, as
Administrative Agent, an Issuing Bank and a Bank, and
Coöperatieve Rabobank U.A., New York Branch and BBVA
Compass, as Joint Lead Arrangers and Sole Bookrunner, and
the Other Financial Institutions Signatory Thereto.
Amendment No. 1 to the Credit Agreement, dated as of
November 2, 2017, among Spark HoldCo, LLC, Spark
Energy, LLC, Spark Energy Gas, LLC, CenStar Energy
Corp, CenStar Operating Company, LLC, Oasis Power,
LLC, Oasis Electricity Maine, LLC, Electricity N.H., LLC,
Provider Power Mass, LLC, Major Energy Services, LLC,
Perigee Energy, LLC, Verde Energy USA, Inc. as Co-
Borrowers.
Amendment No. 2 to the Credit Agreement, dated as of July
17, 2018, by and among Spark Energy, Inc., the Co-
Borrowers, the Banks party thereto, and Brown Borthers
Harrisman & Co., as existing bank.
Amendment No. 3 to the Credit Agreement, dated as of June
13, 2019, by and among Spark Energy, Inc., the Co-
Borrowers, the Issuing Banks party thereto, Co?peratieve
Rabobank U.A., New York Branch, as agent, and the Banks
party thereto.
Tax Receivable Agreement, dated as of August 1, 2014, by
and among Spark Energy, Inc., Spark HoldCo LLC,
NuDevco Retail Holdings, LLC, NuDevco Retail, LLC and
W. Keith Maxwell III.
8-K
10.1
5/24/2017
001-36559
10-Q
10.1
11/3/2017
001-36559
8-K
10.1
7/20/2018
001-36559
8-K
10.1
6/18/2019
001-36559
8-K
10.2
8/4/2014
001-36559
10.6+
Master Service Agreement, effective as of January 1, 2016,
by and among Spark HoldCo, LLC, Retailco Services, LLC,
and NuDevco Retail,. LLC.
10-K
10.6
3/24/2016
001-36559
10.7†
Spark Energy, Inc. Long-Term Incentive Plan
S-8
4.3
7/31/2014
333-197738
10.8†
Spark Energy, Inc. Amended and Restated Long-Term
Incentive Plan.
10-Q
10.3
11/10/2016
001-36559
10.9†
Form of Restricted Stock Unit Agreement
10.10†
Form of Notice of Grant of Restricted Stock Unit
S-1
S-1
10.4
6/30/2014
333-196375
10.5
6/30/2014
333-196375
10.11†
Form of Notice of Grant of Restricted Stock Unit (Change
in Control Restricted Stock Units).
10-Q
10.5
8/3/2018
001-36559
122
10.12
10.13
10.14†
10.15†
10.16†
10.17†
10.18†
10.19†
10.20†
10.21†
10.22
10.23
10.24†
10.25†
10.26†
10.27†
10.28†
10.29†
10.30†
Spark HoldCo. Third Amended and Restated Limited
Liability Agreement, dated as of March 15, 2017, by and
among Spark Energy, Inc., Retailco, LLC and NuDevco
Retail, LLC.
Amendment No. 1, dated as of January 26, 2018, to Third
Amended and Restated Limited Liability Company
Agreement of Spark Holdco, LLC.
10-Q
10.1
5/8/2017
001-36559
8-K
10.1
1/26/2018
001-36559
Indemnification Agreement, dated August 1, 2014, by and
between Spark Energy, Inc. and W. Keith Maxwell III.
8-K
10.5
8/4/2014
001-36559
Indemnification Agreement, dated August 1, 2014, by and
between Spark Energy, Inc. and Nathan Kroeker.
8-K
10.6
8/4/2014
001-36559
Indemnification Agreement, dated August 1, 2014, by and
between Spark Energy, Inc. and Gil Melman.
8-K
10.9
8/4/2014
001-36559
Indemnification Agreement, dated August 1, 2014, by and
between Spark Energy, Inc. and James G. Jones II.
8-K
10.10
8/4/2014
001-36559
Indemnification Agreement, dated August 1, 2014, by and
between Spark Energy, Inc. and Kenneth M. Hartwick.
8-K
10.12
8/4/2014
001-36559
Indemnification Agreement, dated May 25, 2016, by and
between Spark Energy, Inc. and Jason Garrett.
8-K
10.2
5/27/2016
001-36559
Indemnification Agreement, dated May 25, 2016, by and
between Spark Energy, Inc. and Nick W. Evans, Jr.
8-K
10.1
5/27/2016
001-36559
Indemnification Agreement, dated June 2, 2016, by and
between Spark Energy, Inc. and Robert Lane.
8-K
10.3
6/3/2016
001-36559
Registration Rights Agreement, dated as of August 1, 2014,
by and among Spark Energy, Inc., NuDevco Retail
Holdings, LLC and NuDevco Retail LLC.
Transaction Agreement II, dated as of July 30, 2014, by and
among Spark Energy, Inc., Spark HoldCo, LLC, NuDevco
Retail LLC, NuDevco Retail Holdings, LLC, Spark Energy
Ventures, LLC, NuDevco Partners Holdings, LLC and
Associated Energy Services, LP.
8-K
10.4
8/4/2014
001-36559
8-K
4.1
8/4/2014
001-36559
Employment Agreement, dated April 15, 2015, by and
between Spark Energy, Inc. and Nathan Kroeker.
8-K
10.1
4/20/2015
001-36559
Employment Agreement, dated April 15, 2015, by and
between Spark Energy, Inc. and Gil Melman.
8-K
10.4
4/20/2015
001-36559
Employment Agreement, dated August 3, 2015, by and
between Spark Energy, Inc. and Jason Garrett.
8-K
10.1
8/4/2015
001-36559
Amended and Restated Employment Agreement, dated June
2, 2016, by and between Spark Energy, Inc. and Robert
Lane.
8-K
10.1
6/3/2016
001-36559
Amended Employment Agreement between Spark Energy,
Inc. and Nathan Kroeker dated August 1, 2018.
10-Q
10.2
8/3/2018
001-36559
Amended and Restated Employment Agreement between
Spark Energy, Inc. and Jason Garrett dated August 1, 2018.
10-Q
10.3
8/3/2018
001-36559
Amended and Restated Employment Agreement between
Spark Energy, Inc. and Gil Melman dated August 1, 2018.
10-Q
10.4
8/3/2018
001-36559
123
10.31†
10.32
Transition and Resignation Agreement and Mutual Release
of Claims, by and between Spark Energy, Inc. and Gil
Melman, dated December 13, 2018.
Termination Agreement, dated March 7, 2018, by and
among Spark HoldCo, LLC, Retailco Services, LLC and
NuDevco Retail, LLC.
10-Q
10.1
12/14/2018
001-36559
10-K
10.43
3/9/2018
001-36559
10.33†
Spark Energy, Inc. Second Amended and Restated Long
Term Incentive Plan.
8-K
10.1
5/23/2019
001-36559
10.34
Amended and Restated Subordinated Promissory Note of
Spark HoldCo, LLC and Spark Energy, Inc., dated June 13,
2019.
8-K
10.2
6/18/2019
001-36559
10.35†
Employment Agreement, dated June 14, 2019, by and
between Spark Energy, Inc. and James G. Jones II.
8-K
10.3
6/18/2019
001-36559
10.36
TRA Termination and Release Agreement, dated July 11,
2019, by and among Spark Energy, Inc., Spark HoldCo,
LLC, Retailco, LLC, NuDevco Retail, LLC and W. Keith
Maxwell III.
8-K
10.1
7/17/2019
001-36559
10.37 †
Indemnification Agreement, dated August 29, 2019, by and
among Spark Energy, Inc. and Amanda Bush
8-K
10.1
8/30/2019
001-36559
10.38
16.1
21.1*
23.1*
Transition and Resignation Agreement and Mutual Release
of Claims, by and between Spark Energy, Inc. and Jason
Garrett, dated September 25, 2019
8-K
10.1
9/27/2019
001-36559
Letter of KPMG LLP, dated August 16, 2018 to the SEC
8-K
16.1
8/16/2018
001-36559
List of Subsidiaries of Spark Energy, Inc.
Consent of EY
23.2 *
Consent of KPMG
31.1*
31.2*
Certification of Chief Executive Officer pursuant to Rule
13a-14(a) under the Securities Exchange Act of 1934.
Certification of Chief Financial Officer pursuant to Rule
13a-14(a) under the Securities Exchange Act of 1934.
32**
Certifications pursuant to 18 U.S.C. Section 1350.
101.INS* XBRL Instance Document.
101.SCH* XBRL Schema Document.
101.CAL* XBRL Calculation Document.
101.LAB* XBRL Labels Linkbase Document.
101.PRE* XBRL Presentation Linkbase Document.
101.DEF* XBRL Definition Linkbase Document.
* Filed herewith
** Furnished herewith
† Compensatory plan or arrangement
124
+ Portions of this exhibit have been omitted and filed separately with the SEC pursuant to an order granting
confidential treatment.
# The registrant agrees to furnish supplementally a copy of any omitted schedule to the Commission upon request.
125
Item 16. Form 10-K Summary
None.
Pursuant to the requirements of section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the registrant
has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
SIGNATURES
March 5, 2020
Spark Energy, Inc.
By:
/s/ James G. Jones II
James G. Jones II
Chief Financial Officer (Principal
Financial Officer and Principal
Accounting Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following
persons on behalf of the registrant in the capacities indicated on March 5, 2020:
By:
/s/ Nathan Kroeker
Nathan Kroeker
President and Chief Executive Officer
(Principal Executive Officer)
/s/ W. Keith Maxwell III
W. Keith Maxwell III
Chairman of the Board of Directors,
Director
/s/ James G. Jones II
James G. Jones II
Chief Financial Officer (Principal
Financial Officer and Principal
Accounting Officer)
/s/ Nick Evans Jr.
Nick Evans Jr.
Director
/s/ Kenneth M. Hartwick
Kenneth M. Hartwick
Director
/s/ Amanda Bush
Amanda Bush
Director
126
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Our Service
Territory
Company Information
Corporate Headquarters
12140 Wickchester Lane, Suite 100
Houston, Texas 77079
http://ir.sparkenergy.com/
Investor Relations Contact
Mike Barajas
ir@sparkenergy.com
832-200-3727
NASDAQ: "SPKE" - Class A Common Stock
NASDAQ: "SPKEP" - Series A Preferred Stock
W. Keith Maxwell III
Interim Chief Executive Officer
James Jones II
Chief Financial Officer
Kevin McMinn
Chief Operating Officer
Board Of Directors
W. Keith Maxwell Ill
Chairman of the Board
Amanda Bush
Independent Director and Audit Committee Chairman
Kenneth M. Hartwick
Independent Director and
Compensation Committee Chairman
Nick W. Evans Jr.
Independent Director and Nominating and Corporate
Governance Committee Chairman
FORWARD-LOOKING
CAUTIONARY NOTE REGARDING
STATEMENTS
We have made in this report,
and may from time to time otherwise
forward-looking
concerning
the use of forward-looking
terminology
future
discuss
These statements
information.
"forward-looking"
that such expectations
give no assurance
"may,"
contain
expectations,
our operations,
including
we believe
will be realized.
economic
"will,"
statements
Although
projections
"believe,"
of results
make in other public
performance
"expect,"
and financial
"anticipate,"
condition.
"estimate,"
filings,
press releases
and discussions
by management,
by
can be identified
These statements
"continue,"
or include
statements
or other similar
other
condition
words.
of operations
or financial
that the expectations
reflected
in such forward-looking
are reasonable,
we can
These forward-looking
expectations
December
include, but are not limited
statements
31, 2019, filed with the United States Securities
and Exchange Commission.
involve
Important
risks and uncertainties.
factors
that could cause actual
results
from our
to differ materially
to, the risks and uncertainties outlined
in our Annual Report on Form 10-K for the year ended