VIA RENEWABLES, INC.
10-Ks and 10-Qs
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-K
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ý
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended
December 31, 2017
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OR
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission File Number: 001-36559
Spark Energy, Inc.
(Exact name of registrant as specified in its charter)
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Delaware
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46-5453215
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(State or other jurisdiction of
incorporation or organization)
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(I.R.S. Employer
Identification No.)
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12140 Wickchester Ln, Suite 100
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(713) 600-2600
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Houston, Texas 77079
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(Address and zip code of principal executive offices)
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(Registrant’s telephone number, including area code)
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Securities registered pursuant to Section 12(b) of the Act:
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Title of each class
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Name of exchange on which registered
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Class A common stock, par value $0.01 per share
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The NASDAQ Global Select Market
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8.75% Series A Fixed-to-Floating Rate
Cumulative Redeemable Perpetual Preferred Stock, par value $0.01 per share
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The NASDAQ Global Select Market
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Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act
Yes
o
No
x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.
Yes
o
No
x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes
x
No
o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this Chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes
x
No
o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer
o
Accelerated filer
x
Non-accelerated filer
o
(Do not check if a smaller reporting company)
Smaller reporting company
o
Emerging Growth Company
x
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
x
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes
o
No
x
The aggregate market value of common stock held by non-affiliates of the registrant on June 30, 2017, the last business day of the registrant's most recently completed second fiscal quarter, based on the closing price on that date of
$18.80
, was approximately
$215 million
. The registrant, solely for the purpose of this required presentation, had deemed its Board of Directors and Executive Officers to be affiliates, and deducted their stockholdings in determining the aggregate market value.
There were
13,135,636
shares of Class A common stock,
21,485,126
shares of Class B common stock and 3,707,256 shares of Series A Preferred Stock outstanding as of
March 7, 2018
.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant's definitive Proxy Statement in connection with the 2018 Annual Meeting of Stockholders are incorporated by reference into Part III of this Form 10-K.
Table of Contents
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Page
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PART I
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Items 1 & 2.
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Business and Properties
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Item 1A.
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Risk Factors
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Item 1B.
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Unresolved Staff Comments
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Item 3.
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Legal Proceedings
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Item 4.
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Mine Safety Disclosures
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PART II
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Item 5.
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Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
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Stock Performance Graph
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Item 6.
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Selected Financial Data
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Item 7.
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Management’s Discussion and Analysis of Financial Condition and Results of Operations
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Overview
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Drivers of Our Business
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Factors Affecting Comparability of Historical Financial Results
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How We Evaluate Our Operations
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Consolidated Results of Operations
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Operating Segment Results
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Liquidity and Capital Resources
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Cash Flows
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Summary of Contractual Obligations
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Off-Balance Sheet Arrangements
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Related Party Transactions
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Critical Accounting Policies and Estimates
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Contingencies
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Item 7A.
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Quantitative and Qualitative Disclosures About Market Risk
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Item 8.
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Financial Statements and Supplementary Data
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Index to Consolidated Financial Statements
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Item 9.
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Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
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Item 9A.
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Controls and Procedures
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Item 9B.
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Other Information
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PART III
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Item 10.
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Directors, Executive Officers and Corporate Governance
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Item 11.
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Executive Compensation
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Item 12.
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Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
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Item 13.
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Certain Relationships and Related Transactions, and Director Independence
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Item 14.
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Principal Accounting Fees and Services
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PART IV
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Item 15.
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Exhibits, Financial Statement Schedules
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Item 16.
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Form 10-K Summary
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SIGNATURES
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EXHIBIT INDEX
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Glossary
CFTC.
The Commodity Futures Trading Commission.
CPUC.
California Public Utility Commission.
ERCOT
.
The Electric Reliability Council of Texas, the independent system operator and the regional coordinator of various electricity systems within Texas.
ESCO.
Energy service company.
FCC.
Federal Communications Commission.
FERC.
The Federal Energy Regulatory Commission, a regulatory body that regulates, among other things, the transmission and wholesale sale of electricity and the transportation of natural gas by interstate pipelines in the United States.
FTC.
Federal Trade Commission.
ISO.
An independent system operator. An ISO manages and controls transmission infrastructure in a particular region.
MMBtu.
One million British Thermal Units, a standard unit of heating equivalent measure for natural gas. A unit of heat equal to 1,000,000 Btus, or 1 MMBtu, is the thermal equivalent of approximately 1,000 cubic feet of natural gas.
MWh.
One megawatt hour, a unit of electricity equal to 1,000 kilowatt hours (kWh), or the amount of energy equal to one megawatt of constant power expended for one hour of time.
Non-POR Market.
A non-purchase of accounts receivable market.
NYPSC.
New York Public Service Commission.
POR Market.
A purchase of accounts receivable market.
REC.
Renewable Energy Credit.
RCE.
A residential customer equivalent, refers to a natural gas customer with a standard consumption of 100 MMBtus per year or an electricity customer with a standard consumption of 10 MWhs per year.
REP
.
A retail electricity provider.
RTO.
A regional transmission organization. A RTO, similar to an ISO, is a third party entity that manages transmission infrastructure in a particular region.
TCPA.
Telephone Consumer Protection Act of 1991.
Cautionary Note Regarding Forward Looking Statements
This Annual Report on Form 10-K (this "Annual Report") contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. These forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) can be identified by the use of forward-looking terminology including “may,” “should,” “likely,” “will,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” “plan,” “intend,” “projects,” or other similar words. All statements, other than statements of historical fact included
in this Annual Report, regarding strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans, objectives and beliefs of management are forward-looking statements. Forward-looking statements appear in a number of places in this Annual Report and may include statements about business strategy and prospects for growth, customer acquisition costs, ability to pay cash dividends, cash flow generation and liquidity, availability of terms of capital, competition and government regulation and general economic conditions. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we cannot give any assurance that such expectations will prove correct.
The forward-looking statements in this Annual Report are subject to risks and uncertainties. Important factors that could cause actual results to materially differ from those projected in the forward-looking statements include, but are not limited to:
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changes in commodity prices and the sufficiency of risk management and hedging policies;
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extreme and unpredictable weather conditions, and the impact of hurricanes and other natural disasters;
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federal, state and local regulation, including the industry's ability to address or adapt to potentially restrictive new regulations that may be enacted by the New York Public Service Commission;
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our ability to borrow funds and access credit markets and restrictions in our debt agreements and collateral requirements;
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credit risk with respect to suppliers and customers;
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changes in costs to acquire customers and actual customer attrition rates;
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accuracy of billing systems;
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whether our majority stockholder or its affiliates offer us acquisition opportunities on terms that are commercially acceptable to us;
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ability to successfully identify, complete, and efficiently integrate acquisitions into our operations;
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competition; and
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the “Risk Factors” in this Annual Report, and in our quarterly reports, other public filings and press releases.
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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.
6
Items 1 & 2. Business and Properties
General
We are a growing independent retail energy services company founded in 1999 and now organized as a Delaware corporation that provides residential and commercial customers in competitive markets across the United States with an alternative choice for their natural gas and electricity. We purchase our natural gas and electricity supply from a variety of wholesale providers and bill our customers monthly for the delivery of natural gas and electricity based on their consumption at either a fixed or variable-price. Natural gas and electricity are then distributed to our customers by local regulated utility companies through their existing infrastructure.
Our business consists of two operating segments:
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Retail Electricity Segment
. We purchase electricity supply through physical and financial transactions with market counterparts and independent system operators ("ISOs") and supply electricity to residential and commercial consumers pursuant to fixed-price and variable-price contracts. For the years ended
December 31, 2017
,
2016
and
2015
, approximately
82%
,
76%
and
64%
, respectively, of our retail revenue were derived from the sale of electricity.
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Retail Natural Gas Segment
. We purchase natural gas supply through physical and financial transactions with market counterparts and supply natural gas to residential and commercial consumers pursuant to fixed-price and variable-price contracts. For the years ended
December 31, 2017
,
2016
and
2015
, approximately
18%
,
24%
and
36%
, respectively, of our retail revenues were derived from the sale of natural gas. We also identify wholesale natural gas arbitrage opportunities in conjunction with our retail procurement and hedging activities, which we refer to as asset optimization.
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See Note
15 "Segment Reporting"
to the Company’s audited consolidated financial statements in this report for financial information relating to our operating segments.
Recent Developments
See “Management's Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments” for a discussion of recent developments affecting our business and operations.
Our Operations
As of
December 31, 2017
, we operated in
94
utility service territories across
19
states and the District of Columbia and had approximately
1,042,000
RCEs. An RCE, or residential customer equivalent, is an industry standard measure of natural gas or electricity usage with each RCE representing annual consumption of 100 MMBtu of natural gas or 10 MWh of electricity. We serve natural gas customers in
fifteen
states (Arizona, California, Colorado, Connecticut, Florida, Illinois, Indiana, Maryland, Massachusetts, Michigan, Nevada, New Jersey, New York, Ohio and Pennsylvania) and electricity customers in
twelve
states (Connecticut, Delaware, Illinois, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Ohio, Pennsylvania and Texas) and the District of Columbia using nine brands (Spark Energy, CenStar Energy, Electricity Maine, ENH Power, Major Energy, Oasis Energy, Provider Power Mass, Respond Power, and Verde Energy).
Customer Contracts and Product Offerings
Fixed and variable-price contracts
We offer a variety of fixed-price and variable-price service options to our natural gas and electricity customers. Under our fixed-price service options, our customers purchase natural gas and electricity at a fixed price over the
7
life of the customer contract, which provides our customers with protection against increases in natural gas and electricity prices. Our fixed-price contracts typically have a term of one to two years for residential customers and up to three years for commercial customers and most provide for an early termination fee in the event that the customer terminates service prior to the expiration of the contract term. In a typical market, we offer fixed-price electricity plans for 6, 12 and 24 months and fixed-price natural gas plans from 12 to 24 months, which may come with or without a monthly service fee and/or a termination fee. Our variable-price service options carry a month-to-month term and are priced based on our forecasts of underlying commodity prices and other market factors, including the competitive landscape in the market and the regulatory environment. We also offer variable-price natural gas and electricity plans that offer an introductory fixed price that is generally applied for a certain number of billing cycles, typically two billing cycles in our current markets, then switches to a variable price based on market conditions. Our variable plans may or may not provide for a termination fee, depending on the market and customer type.
As of
December 31, 2017
, approximately
54%
of our natural gas RCEs were fixed-price, and the remaining
46%
of our natural gas RCEs were variable-price. As of
December 31, 2017
, approximately
82%
of our electricity RCEs were fixed-price, and the remaining
18%
of our electricity RCEs were variable-price.
Green products and renewable energy credits
We offer renewable and carbon neutral (“green”) products in certain markets. Green energy products are a growing market opportunity and typically provide increased unit margins as a result of improved customer satisfaction and less competition. Renewable electricity products allow customers to choose electricity sourced from wind, solar, hydroelectric and biofuel sources, through the purchase of renewable energy credits (“RECs”). Carbon neutral gas products give customers the option to reduce or eliminate the carbon footprint associated with their energy usage through the purchase of carbon offset credits. These products typically provide for fixed or variable prices and generally follow the terms of our other products with the added benefit of carbon reduction and reduced environmental impact. We currently offer renewable electricity in all of our electricity markets and carbon neutral natural gas in several of our gas markets.
In addition to the RECs we purchase to satisfy our voluntary requirements under the terms of our green contracts with our customers, we must also purchase a specified amount of RECs based on the amount of electricity we sell in a state in a year pursuant to individual state renewable portfolio standards. We forecast the price for the required RECs at the end of each month and incorporate this cost component into our customer pricing models.
Customer Acquisition and Retention
8
Our customer acquisition strategy consists of customer growth obtained through traditional organic customer acquisitions, complemented by opportunistic acquisitions. We make decisions on how best to deploy capital on customer acquisitions based on a variety of factors, including cost to acquire customers, availability of opportunities and our view of attractive commodity pricing in particular regions. For example, we may seek to make an acquisition of a large number of customers in a particular group of markets even though the initial acquisition cost may be higher because long-term margins are higher. We expect to focus on organic growth through 2018.
Organic Growth
Our organic sales strategies are used to both maintain and grow our customer base by offering competitive pricing, price certainty, and/or green product offerings. We manage growth on a market-by-market basis by developing price curves in each of the markets we serve and comparing the market prices and the price the local regulated utility is offering. We then determine if there is an opportunity in a particular market based on our ability to create an attractive customer value proposition that is also able to enhance our profitability. The attractiveness of a product from a consumer’s standpoint is based on a variety of factors, including overall pricing, price stability, contract term, sources of generation and environmental impact and whether or not the contract provides for termination and other fees. Product pricing is also based on a several other factors, including the cost to acquire customers in the market, the competitive landscape and supply issues that may affect pricing.
Once a product has been created for a particular market, we then develop a marketing campaign using a combination of sales channels, with an emphasis on door-to-door and web-based marketing. We identify and acquire customers through a variety of additional sales channels, including our inbound customer care call center, online marketing, email, direct mail, brokers and direct sales. We typically employ multiple vendors under short-term contracts and have not entered into any exclusive marketing arrangements with sales vendors. Our marketing team continuously evaluates the effectiveness of each customer acquisition channel and makes adjustments in order to achieve targeted growth and customer acquisition costs. We attempt to maintain a disciplined approach to recovery of our customer acquisition costs within defined periods.
Acquisitions
We acquire both portfolios of customers as well as retail energy companies through some combination of cash, borrowings under the Senior Credit Facility, the issuance of common or preferred stock or other financing arrangements with our Founder and his affiliates. Historically, a significant component of our customer acquisition strategy has been the relationship and growth strategy structure with NG&E. See “—Relationship with our Founder and Majority Shareholder” for a discussion of this relationship.
The following table provides a summary of our acquisitions over the past five years, including the name of the retail energy company or an indication if the acquisition was a portfolio of customers, the date completed, the RCE count, the segment and the source of the acquisition:
9
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Company / Portfolio
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Date Completed
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RCEs
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Segment
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Acquisition Source
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Customer Portfolio
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February 28, 2015
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12,500
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Electricity
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Third Party
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CenStar Energy Corp.
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July 8, 2015
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65,000
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Natural Gas
Electricity
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Third Party
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Oasis Power Holdings, LLC
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July 31, 2015
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40,000
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Natural Gas
Electricity
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Founder / NG&E
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Customer Portfolio
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September 30, 2015
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9,500
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Natural Gas
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Third Party
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Provider Companies
(1)
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August 1, 2016
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121,000
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Electricity
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Third Party
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Major Energy Companies
(2)
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August 23, 2016
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220,000
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Natural Gas
Electricity
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Founder / NG&E
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Perigee Energy, LLC
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April 1, 2017
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17,000
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Natural Gas
Electricity
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Founder / NG&E
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Verde Companies
(3)
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July 1, 2017
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145,000
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Electricity
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Third Party
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Customer Portfolio
(4)
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October 31, 2017
(4)
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44,000
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Electricity
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Third Party
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HIKO Energy, LLC
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March 1, 2018
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29,000
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Natural Gas
Electricity
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Third Party
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Customer Portfolio
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(5)
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50,000
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Natural Gas
Electricity
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Founder / NG&E
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(1)
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Included Electricity Maine, LLC, Electricity N.H., LLC, Provider Power Mass, LLC (collectively, the “Provider Companies”).
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(2)
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Included Major Energy Services, LLC, Major Energy Electric Services, LLC, and Respond Power, LLC (collectively, the “Major Energy Companies”).
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(3)
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Included Verde Energy USA, Inc.; Verde Energy USA Commodities, LLC; Verde Energy USA Connecticut, LLC; Verde Energy USA DC, LLC; Verde Energy USA Illinois, LLC; Verde Energy USA Maryland, LLC; Verde Energy USA Massachusetts, LLC; Verde Energy USA New Jersey, LLC; Verde Energy USA New York, LLC; Verde Energy USA Ohio, LLC; Verde Energy USA Pennsylvania, LLC; Verde Energy USA Texas Holdings, LLC; Verde Energy USA Trading, LLC; and Verde Energy Solutions, LLC (collectively, the “Verde Companies”).
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(4)
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Includes customers transferred from April 2017 through October 2017 from the original owner of Perigee.
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(5)
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Customers will begin transferring to the Company in April 2018.
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Please see and Item 9B. “Other Information” and Note
3 "Acquisitions"
in the notes to our consolidated financial statements for a more detailed description of these acquisitions, including the purchase price, the source of funds and financing arrangements with our Founder and/or NG&E.
We are actively monitoring acquisition opportunities that may arise in the domestic acquisition market as smaller retailers face difficulties in managing risk and liquidity issues caused by the recent extreme weather patterns. Our ability to grow at historic levels may be constrained if the market for acquisition candidates is limited and we are unable to make acquisitions of portfolios of customers and retail energy companies on commercially reasonable terms. Please see “Risk Factors
—
Risks Related to Our Business and Our Industry
—
We may be subject to risks in connection with acquisitions, which could cause us to fail to realize many of the anticipated benefits of such acquisition” and “Risk Factors
—
Risks Related to Our Capital Stock
—
We engage in transaction with our affiliates and expect to do so in the future. The terms of such transactions and the resolution of any conflict that may arise may not always be in our or our stockholders’ best interest.”
Growth Sources and Sales Channels
During the year ended
December 31, 2017
, our RCE acquisitions were generated from the following sources and sales channels:
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Indirect Sales Brokers
|
30
|
%
|
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Acquisitions
|
25
|
%
|
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Web Based
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14
|
%
|
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Door to Door
|
13
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%
|
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Outbound
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5
|
%
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Other
|
13
|
%
|
10
In 2017, we grew our commercial and industrial (“C&I”) customer base. C&I customers typically have larger natural gas and electricity volume requirements, but at lower margins than residential customers. These C&I customers also typically have longer contract terms. After significant growth in our C&I customer count in 2017, management is rebalancing our mix of customers in the first part of 2018 to focus on higher margin residential customers. At December 31, 2017, approximately
48%
of the Company’s RCEs were C&I customers.
Retaining customers and maximizing customer lifetime value
Following our acquisition of customers, management and marketing teams devote significant attention to customer retention. We have developed a disciplined renewal communication process, which is designed to effectively reach our customers prior to the end of the contract term, and employ a team dedicated to managing this renewal communications process. Customers are contacted in each utility prior to the expiration of the customer's contract. Spark may elect to contact the customer through additional channels such as outbound telephone calls and electronic mail communication. We encourage retention and promote renewals by means of each of these contact methods.
We also apply a proprietary evaluation and segmentation process to optimize value both to us and the customer. We analyze historical usage, attrition rates and consumer behaviors to specifically tailor competitive products that aim to maximize the total expected return from energy sales to a specific customer, which we refer to as customer lifetime value.
Investment in ESM
The Company and Spark HoldCo, together with eREX Co., Ltd., a Japanese company, are joint venture partners in eREX Spark Marketing Co., Ltd ("ESM"). Operations for ESM began on April 1, 2016 in connection with the deregulation of the Japanese power market. As of
December 31, 2017
, the Company has contributed
156.4 million
Japanese Yen, or
$1.4 million
, for a
20%
ownership interest in ESM. As of
December 31, 2017
, ESM has approximately
100,000
customers, which are currently excluded from our count of residential customer equivalents ("RCEs").
Asset Optimization
Part of our business includes asset optimization activities in which we identify opportunities in the natural gas wholesale marketplace in conjunction with our retail procurement and hedging activities. Many of the competitive pipeline choice programs in which we participate require us and other retail energy suppliers to take assignment of and manage natural gas transportation and storage assets upstream of their respective city-gate delivery points. With respect to our allocated storage assets, we are also obligated to buy and inject gas in the summer season (April through October) and sell and withdraw gas during the winter season (November through March). These purchase and injection obligations in our allocated storage assets require us to take a seasonal long position in natural gas. Our asset optimization group determines whether market conditions justify hedging these long positions through additional derivative transactions.
Our asset optimization group utilizes these allocated transportation and storage assets for retail customer usage and to effect transactions in the wholesale market based on market conditions and opportunities. Our asset optimization group also contracts with third parties for transportation and storage capacity in the wholesale market. We are responsible for reservation and demand charges attributable to both our allocated and third-party contracted transportation and storage assets. Our asset optimization group utilizes these allocated and third-party transportation and storage assets in a variety of ways to either improve profitability or optimize supply-side counterparty credit lines.
We frequently enter into spot market transactions in which we purchase and sell natural gas at the same point or we purchase natural gas at one point or pool and ship it using our pipeline reservations for sale at another point or pool, in each case if we are able to capture a margin. We view these spot market transactions as low risk because we enter
11
into the buy and sell transactions simultaneously on a back-to-back basis. We will also act as an intermediary for market participants who need assistance with short-term procurement requirements. Consumers and suppliers will contact us with a need for a certain quantity of natural gas to be bought or sold at a specific location. We are able to use our contacts in the wholesale market to source the requested supply, and we will capture a margin in these transactions.
The asset optimization group historically entered into long-term transportation and storage transactions. Our risk policies require that this business is limited to back-to-back purchase and sale transactions, or open positions subject to our aggregate net open position limits, which are not held for a period longer than two months. Furthermore, all additional capacity procured outside of a utility allocation of retail assets must be approved by our risk committee. Hedges on our firm transportation obligations are limited to two years or less and hedging of interruptible capacity is prohibited.
We also enter into back-to-back wholesale transactions to optimize our credit lines with third-party energy suppliers. With each of our third-party energy suppliers, we have certain contracted credit lines, within which we are able to purchase energy supply from these counterparties. If we desire to purchase supply beyond these credit limits, we are required to post collateral, in the form of either cash or letters of credit. As we begin to approach the limits of our credit line with one supplier, we may purchase energy supply from another supplier and sell that supply to the original counterparty in order to reduce our net buy position with that counterparty and open up additional credit to procure supply in the future. Our sales of gas pursuant to these activities also enable us to optimize our credit lines with third-party energy suppliers by decreasing our net buy position with those suppliers.
Commodity Supply
We hedge and procure our energy requirements from various wholesale energy markets, including both physical and financial markets and through short and long term contracts. Our in-house energy supply team is responsible for managing our commodity positions (including energy procurement, capacity, transmission, renewable energy, and resource adequacy requirements) within risk tolerances defined by our risk management policies. We procure our natural gas and electricity requirements at various trading hubs, city gates and load zones. When we procure commodities at trading hubs, we are responsible for delivery to the applicable local regulated utility for distribution.
We periodically adjust our portfolio of purchase/sale contracts in the wholesale natural gas market based upon continual analysis of our forecasted load requirements. Natural gas is then delivered to the local regulated utility city-gate or other specified delivery points where the local regulated utility takes control of the natural gas and delivers it to individual customers’ locations. Additionally, we hedge our natural gas price exposure with financial products. During the year ended
December 31, 2017
, we transacted physical and financial settlement of natural gas with approximately
93
wholesale counterparties.
In most markets, we typically hedge our electricity exposure with financial products and then purchase the physical power directly from the ISO for delivery. From time to time, we use a combination of physical and financial products to hedge our electricity exposure before buying physical electricity in the day-ahead and real-time market from the ISO. During the year ended
December 31, 2017
, we transacted physical and financial settlement of electricity with approximately
17
suppliers.
We are assessed monthly for ancillary charges such as reserves and capacity in the electricity sector by the ISOs. For example, the ISOs will charge all retail electricity providers for monthly reserves that the ISO determines are necessary to protect the integrity of the grid. We attempt to estimate such amounts, but they are difficult to estimate because they are charged in arrears by the ISOs and are subject to fluctuations based on weather and other market conditions. Many of the utilities we serve also allocate natural gas transportation and storage assets to us as a part of their competitive choice program. We are required to fill our allocated storage capacity with natural gas, which creates commodity supply and price risk. Sometimes we cannot hedge the volumes associated with these assets because they are too small compared to the much larger bulk transaction volumes required for trades in the wholesale market or it is not economically feasible to do so.
12
Risk Management
Our management team operates under a set of corporate risk policies and procedures relating to the purchase and sale of electricity and natural gas, general risk management and credit and collections functions. Our in-house energy supply team is responsible for managing our commodity positions (including energy procurement, capacity, transmission, renewable energy, and resource adequacy requirements) within risk tolerances defined by our risk management policies. We attempt to increase the predictability of cash flows by following our various hedging strategies.
The risk committee has control and authority over all of our risk management activities. The risk committee establishes and oversees the execution of our credit risk management policy and our commodity risk policy. The risk management policies are reviewed at least annually and the risk committee typically meets quarterly to assure that we have followed its policies. The risk committee also seeks to ensure the application of our risk management policies to new products that we may offer. The risk committee is comprised of our Chief Executive Officer and our Chief Financial Officer, who meet on a regular basis to review the status of the risk management activities and positions. Our risk team reports directly to our Chief Financial Officer and their compensation is unrelated to trading activity. Commodity positions are typically reviewed and updated daily based on information from our customer databases and pricing information sources. The risk policy sets volumetric limits on intra-day and end of day long and short positions in natural gas and electricity. With respect to specific hedges, we have established and approved a formal delegation of authority specifying each trader's authorized volumetric limits based on instrument type, lead time (time to trade flow), fixed price volume, index price volume and tenor (trade flow) for individual transactions. The risk team reports to the risk committee any hedging transactions that exceed these delegated transaction limits.
Commodity Price and Volumetric Risk
Because our contracts require that we deliver full natural gas or electricity requirements to many of our customers and because our customers’ usage can be impacted by factors such as weather, we may periodically purchase more or less commodity than our aggregate customer volumetric needs. In buying or selling excess volumes, we may be exposed to commodity price volatility. In order to address the potential volumetric variability of our monthly deliveries for fixed-price customers, we implement various hedging strategies to attempt to mitigate our exposure.
Our commodity risk management strategy is designed to hedge substantially all of our forecasted volumes on our fixed-price customer contracts, as well as a portion of the near-term volumes on our variable-price customer contracts. We use both physical and financial products to hedge our fixed-price exposure. The efficacy of our risk management program may be adversely impacted by unanticipated events and costs that we are not able to effectively hedge, including abnormal customer attrition and consumption, certain variable costs associated with electricity grid reliability, pricing differences in the local markets for local delivery of commodities, unanticipated events that impact supply and demand, such as extreme weather, and abrupt changes in the markets for, or availability or cost of, financial instruments that help to hedge commodity price.
Customer demand is also impacted by weather. We use utility-provided historical and/or forward projected customer volumes as a basis for our forecasted volumes and mitigate the risk of seasonal volume fluctuation for some customers by purchasing excess fixed-price hedges within our volumetric tolerances. Should seasonal demand exceed our weather-normalized projections, we may experience a negative impact on financial results.
In addition to our forward price risk management approach described above, we may take further measures to reduce price risk and optimize our returns by: (i) maximizing the use of storage in our daily balancing market areas in order to give us the flexibility to offset volumetric variability arising from changes in winter demand; (ii) entering into daily swing contracts in our daily balancing markets over the winter months to enable us to increase or decrease daily volumes if demand increases or decreases; and (iii) purchasing out-of-the-money call options for contract periods with the highest seasonal volumetric risk to protect against steeply rising prices if our
13
customer demands exceed our forecast. Being geographically diversified in our delivery areas also permits us, from time to time, to employ assets not being used in one area to other areas, thereby mitigating potential increased costs for natural gas that we otherwise may have had to acquire at higher prices to meet increased demand.
We utilize NYMEX-settled financial instruments to offset price risk associated with volume commitments under fixed-price contracts. The valuation for these financial instruments is calculated daily based on the NYMEX Exchange published closing price, and they are settled using the NYMEX Exchange’s published settlement price at their maturity.
Basis Risk
We are exposed to basis risk in our operations when the commodities we hedge are sold at different delivery points from the exposure we are seeking to hedge. For example, if we hedge our natural gas commodity price with Chicago basis but physical supply must be delivered to the individual delivery points of specific utility systems around the Chicago metropolitan area, we are exposed to basis risk between the Chicago basis and the individual utility system delivery points. These differences can be significant from time to time, particularly during extreme, unforecasted cold weather conditions. Similarly, in certain of our electricity markets, customers pay the load zone price for electricity, so if we purchase supply to be delivered at a hub, we may have basis risk between the hub and the load zone electricity prices due to local congestion that is not reflected in the hub price. We attempt to hedge basis risk where possible, but hedging instruments are sometimes not economically feasible or available in the smaller quantities that we require.
Customer Credit Risk
Our credit risk management policies are designed to limit customer credit exposure. Credit risk is managed through participation in purchase of receivables ("POR") programs in utility service territories where such programs are available. In these markets, we monitor the credit ratings of the local regulated utilities and the parent companies of the utilities that purchase our customer accounts receivable. We also periodically review payment history and financial information for the local regulated utilities to ensure that we identify and respond to any deteriorating trends. In non-POR markets, we assess the creditworthiness of new applicants, monitor customer payment activities and administer an active collections program. Using risk models, past credit experience and different levels of exposure in each of the markets, we monitor our aging, bad debt forecasts and actual bad debt expenses and continually adjust as necessary.
In many of the utility services territories where we conduct business, POR programs have been established, whereby the local regulated utility purchases our receivables, and then becomes responsible for billing the customer and collecting payment from the customer. This service results in substantially all of our credit risk being linked to the applicable utility and not to our end-use customer in these territories. For the year ended
December 31, 2017
, approximately
66%
of our retail revenues were derived from territories in which substantially all of our credit risk was directly linked to local regulated utility companies, all of which had investment grade ratings as of such date. During the same period, we paid these local regulated utilities a weighted average discount of approximately
1.1%
of total revenues for customer credit risk. In certain of the POR markets in which we operate, the utilities limit their collections exposure by retaining the ability to transfer a delinquent account back to us for collection when collections are past due for a specified period. If our collection efforts are unsuccessful, we return the account to the local regulated utility for termination of service. Under these service programs, we are exposed to credit risk related to payment for services rendered during the time between when the customer is transferred to us by the local regulated utility and the time we return the customer to the utility for termination of service, which is generally one to two billing periods. We may also realize a loss on fixed-price customers in this scenario due to the fact that we will have already fully hedged the customer’s expected commodity usage for the life of the contract.
In non-POR markets (and in POR markets where we may choose to direct bill our customers), we manage commercial customer credit risk through a formal credit review and manage residential customer credit risk through a variety of procedures, which may include credit score screening, deposits and disconnection for non-payment. We
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also maintain an allowance for doubtful accounts, which represents our estimate of potential credit losses associated with accounts receivable from customers within non-POR markets.
We assess the adequacy of the allowance for doubtful accounts through review of the aging of customer accounts receivable and general economic conditions in the markets that we serve. Our bad debt expense for the year ended
December 31, 2017
was
$6.6 million
, or
0.8%
of retail revenues. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Drivers of Our Business—Customer Credit Risk” for a more detailed discussion of our bad debt expense during the year ended
December 31, 2017
.
We have limited exposure to high concentrations of sales volumes to individual customers. For the year ended
December 31, 2017
, our largest customer accounted for less than
1%
of total retail energy sales volume.
Counterparty Credit Risk in Wholesale Market
We do not independently produce natural gas and electricity and depend upon third parties for our supply, which exposes us to wholesale counterparty credit risk in our retail and asset optimization activities. If the counterparties to our supply contracts are unable to perform their obligations, we may suffer losses, including as a result of being unable to secure replacement supplies of natural gas or electricity on a timely and cost-effective basis or at all. At
December 31, 2017
, approximately
84%
of our total exposure of
$34.2 million
was either with an investment grade customer or otherwise secured with collateral or a guarantee.
Operational Risk
As with all companies, the Company is at risk from cyber-attacks (breaches, unauthorized access, misuse, computer viruses, or other malicious code or other events) that could materially adversely affect our business, or otherwise cause interruptions or malfunctions in our operations.
We mitigate these risks through multiple layers of security controls including policy, hardware, and software security solutions. We also have engaged third parties to assist with both external and internal vulnerability scans and continue to enhance awareness with employee education and accountability. As of
December 31, 2017
, we have not experienced any material loss related to cyber-attacks or other information security breaches.
Relationship with our Founder and Majority Shareholder
Growth Support
We have historically leveraged our relationship with affiliates of our founder, chairman and majority shareholder, W. Keith Maxwell III (our "Founder"), to execute on our growth strategy, which includes sourcing of acquisitions, financing support, and operating cost efficiencies. To support this relationship, our Founder formed National Gas & Electric, LLC, an affiliate of the Company (“NG&E”), in 2015 for the purpose of purchasing retail energy companies and retail customer books that could ultimately be resold to the Company. This relationship affords us access to opportunities that might not otherwise be available to us due to our size and availability of capital.
On March 7, 2018, we entered into an asset purchase agreement with NG&E pursuant to which we will acquire approximately
50,000
RCEs from NG&E for a cash purchase price of
$250
for each RCE, or approximately
$12.5 million
in the aggregate. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments—Acquisition of Customers from NG&E.” For a summary of historical acquisitions with our Founder and NG&E, please see “—Customer Acquisition and Retention—Acquisitions.”
We may engage in additional transactions with NG&E in the future. We currently expect that we would fund any future transactions with NG&E with some combination of cash, subordinated debt, or the issuance of Class A common stock or Class B common stock to NG&E. However, actual consideration paid for the assets will depend, among other things, on our capital structure and liquidity at the time of any transaction.
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Given our Founder's significant economic interest in us, we believe that he is incentivized to offer us opportunities to grow through this drop-down structure. However, our Founder and his affiliates are under no obligation to offer us acquisition opportunities, and we are under no obligation to buy assets from them. Additionally, as we grow and our access to capital and opportunities improves, we may rely less upon NG&E as a source of acquisitions and seek to enter into more transactions directly with third parties. Any acquisition activity involving NG&E or any other affiliate of our Founder will be subject to negotiation and approval by a special committee of the Board of Directors consisting solely of independent directors. Please see “Risk Factors—Risks Related to Our Business and Our Industry—We may be subject to risks in connection with acquisitions, which could cause us to fail to realize many of the anticipated benefits of such acquisitions" and "Risk Factors—Risks Related to Our Capital Stock—We engage in transactions with our affiliates and expect to do so in the future. The terms of such transactions and resolution of any conflicts that may arise may not always be in our or our stockholders' best interest."
Master Service Agreement
We entered into a Master Service Agreement (the “Master Service Agreement”) effective January 1, 2016 with Retailco Services, LLC ("Retailco Services"), which is wholly owned by our Founder. The Master Service Agreement is for a one-year term and renews automatically for successive one-year terms unless the Master Service Agreement is terminated by either party. On January 1, 2018, the Master Service Agreement renewed automatically pursuant to its terms for a one year period ending on December 31, 2018.
Retailco Services provides us with operational support services such as: enrollment and renewal transaction services; customer billing and transaction services; electronic payment processing services; customer services and information technology infrastructure and application support services under the Master Service Agreement (collectively, the "Services"). Spark HoldCo pays Retailco Services a monthly fee consisting of a monthly fixed fee plus a variable fee per customer per month depending on market complexity. We meet with Retailco Services quarterly to discuss fees and Service Levels (as defined below) based on changes in assumptions; to date, we have not adjusted fees or the Service Levels. The Master Service Agreement provides that Retailco Services perform the Services in accordance with specified service levels (the “Service Levels”), and in the event Retailco Services fails to meet the Service Levels, Spark HoldCo receives a credit against invoices or a cash payment (the “Penalty Payment”). The amount of the Penalty Payment was initially limited to
$0.1 million
monthly, but adjusts annually based upon the amount of fees charged by Retailco Services for Services over the prior year. Furthermore, in the event that the Service Levels are not satisfied and Spark HoldCo suffers damages in excess of
$0.5 million
as a result of such failure, Retailco Services will make a payment (the “Damage Payment”) to Spark HoldCo for the amount of the damages (less the amount of any Penalty Payments also due). The Master Service Agreement provides that in no event may the Penalty Payments and Damage Payments exceed
$2.5 million
in any twelve-month period.
In connection with the Master Service Agreement, certain of Spark HoldCo’s employees who previously provided services similar to those to be provided under the Master Service Agreement became employees of Retailco Services, and certain contracts, assets, and intellectual property were assigned to Retailco Services. In addition, in order to facilitate the Services, Spark HoldCo granted Retailco Services a non-transferable, non-exclusive, royalty-free, revocable and non-sub-licensable license to use certain of its intellectual property.
Either Spark HoldCo or Retailco Services is permitted to terminate the Master Service Agreement: (a) upon 30 days prior written notice for convenience and without cause; (b) upon a material breach and written notice to the breaching party when the breach has not been cured 30 days after such notice; (c) upon written notice if Retailco Services is unable for any reason to resume performance of the services within 60 days following the occurrence of an event of force majeure; and (d) upon certain events of insolvency, assignment for the benefit of creditors, cessation of business, or filings of petitions for bankruptcy or insolvency proceedings by the other party. In the event the Master Service Agreement is terminated for any reason, Retailco Services will provide certain transition services to Spark HoldCo following the termination, not to exceed six months at the then-current fees.
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Retailco Services and Spark HoldCo have agreed to indemnify each other from: (a) willful misconduct or negligence of the other; (b) bodily injury or death of any person or damage to real and/or tangible personal property caused by the acts or omission of the other; (c) any breach of any representation, warranty, covenant or other obligation of the other party under the Master Service Agreement, and (d) other standard matters. Subject to certain exceptions (including indemnification obligations, the obligations to pay fees and the Damage Payments and Penalty Payments), each parties’ liability is limited to
$2.5 million
of direct damages. NuDevco Retail has entered into the Master Service Agreement for the limited purpose of guarantying payments that Retailco Services may be required to make under the Master Service Agreement up to a maximum of
$2.0 million
.
During the year ended
December 31, 2017
and
2016
, the Company recorded general and administrative expenses of
$22.0 million
and
$14.7 million
, respectively,
in connection with the Master Service Agreement. For the years ended
December 31, 2017
and
2016
, Penalty Payments totaled
$0.1 million
, and Damage Payments totaled
zero
and
$1.4 million
, respectively. Additionally, under the Master Service Agreement, we capitalized
$0.7 million
and
$1.3 million
, respectively, during the years ended
December 31, 2017
and
2016
of property and equipment for software and consultant time used in the application, development and implementation of various systems including customer billing and resource management systems.
On March 7, 2018, we, Retailco Services and NuDevco Retail mutually agreed to terminate the Master Services Agreement, effective April 1, 2018. Please see “Management’s Discussion of Analysis of Financial Condition and Results of Operations—Recent Developments—Termination of Master Service Agreement” and “Risk Factors—The termination of the Master Service Agreement subjects us to a variety of risks.”
Competition
The markets in which we operate are highly competitive. In markets that are open to competitive choice of retail energy suppliers, our primary competition comes from the incumbent utility and other independent retail energy companies. In the electricity sector, these competitors include larger, well-capitalized energy retailers such as Direct Energy, Inc., FirstEnergy Solutions, Inc., Just Energy Group, Inc. and NRG Energy, Inc. We also compete with small local retail energy providers in the electricity sector that are focused exclusively on certain markets. Each market has a different group of local retail energy providers. With respect to natural gas, our national competitors are primarily Direct Energy and Constellation Energy. Our national competitors generally have diversified energy platforms with multiple marketing approaches and broad geographic coverage similar to us. Competition in each market is based primarily on product offering, price and customer service. The number of competitors in our markets varies. In well-established markets in the Northeast and Texas we have hundreds of competitors, while in others the competition is limited to several participants.
The competitive landscape differs in each utility service area and within each targeted customer segment. Over the last several years, a number of utilities have spun off their retail marketing arms as part of the opening of retail competition in these markets. Markets that offer POR programs are generally more competitive than those markets in which retail energy providers bear customer credit risk. Market participants are significantly shielded from bad debt expense, thereby allowing easier entry into the POR markets. In these markets, we face additional competition as barriers to entry are less onerous.
Our ability to compete by increasing our market share depends on our ability to convince customers to switch to our products and services, and our ability to offer products at attractive prices. Many local regulated utilities and their affiliates may possess the advantages of name recognition, long operating histories, long-standing relationships with their customers and access to financial and other resources, which could pose a competitive challenge to us. As a result of these advantages, many customers of these local regulated utilities may decide to stay with their longtime energy provider if they have been satisfied with their service in the past. In addition, competitors may choose to offer more attractive short-term pricing to increase their market share.
Seasonality of our Business
17
Our overall operating results fluctuate substantially on a seasonal basis depending on: (i) the geographic mix of our customer base; (ii) the relative concentration of our commodity mix; (iii) weather conditions, which directly influence the demand for natural gas and electricity and affect the prices of energy commodities; and (iv) variability in market prices for natural gas and electricity. These factors can have material short-term impacts on monthly and quarterly operating results, which may be misleading when considered outside of the context of our annual operating cycle.
Our accounts payable and accounts receivable are impacted by seasonality due to the timing differences between when we pay our suppliers for accounts payable versus when we collect from our customers on accounts receivable. We typically pay our suppliers for purchases of natural gas on a monthly basis and electricity on a weekly basis. However, it takes approximately two months from the time we deliver the electricity or natural gas to our customers before we collect from our customers on accounts receivable attributable to those supplies. This timing difference could affect our cash flows, especially during peak cycles in the winter and summer months.
Natural gas accounted for approximately
18%
of our retail revenues for the year ended
December 31, 2017
, which exposes us to a high degree of seasonality in our cash flows and income earned throughout the year as a result of the high concentration of heating load in the winter months. We utilize a considerable amount of cash from operations and borrowing capacity to fund working capital, which includes inventory purchases from April through October each year. We sell our natural gas inventory during the months of November through March of each year. We expect that the significant seasonality impacts to our cash flows and income will continue in future periods.
Regulatory Environment
We operate in the highly regulated natural gas and electricity retail sales industry in all of our respective jurisdictions. We must comply with the legislation and regulations in these jurisdictions in order to maintain our licensed status and to continue our operations, and to obtain the necessary licenses in jurisdictions in which we plan to compete. Licensing requirements vary by state, but generally involve regular, standardized reporting in order to maintain a license in good standing with the state commission responsible for regulating retail electricity and gas suppliers. There is potential for changes to state legislation and regulatory measures addressing licensing requirements that may impact our business model in the applicable jurisdiction. In addition, as further discussed below, our marketing activities and customer enrollment procedures are subject to rules and regulations at the state and federal level, and failure to comply with requirements imposed by federal and state regulatory authorities could impact our licensing in a particular market.
As of October 2015, the state of Connecticut no longer allows retail energy providers to offer variable rate plans even after the customer rolls off of a fixed rate plan. As a result of this change, we now offer customers who end their fixed terms with another fixed term of no less than four billing cycles. This regulatory change did not have a significant impact on our results of operations, and we expect that we can continue to manage the renewals in these markets to maintain profitability. Other states are currently examining the effectiveness of implementing such a restriction.
On February 23, 2016, the New York State Public Service Commission ("NYPSC") issued an order ("the Resetting Order") resetting retail energy markets that, among other things, would have limited the types of competitive products that energy service companies ("ESCOs"), such as us, could offer in New York. The Resetting Order stated that all new customer enrollments or expiring agreements for mass market (residential and certain small commercial) customers must enroll or re-enroll in a contract that offers either: (i) a guarantee that the customer will pay no more than what the customer would pay as a full service utility customer, or (ii) an electricity product that is at least 30% derived from specific renewable sources either in the State of New York or in adjacent market areas. On July 22, 2016, most of the Resetting Order, including the provisions previously noted, was vacated by a New York state court.
On July 27, 2017, the New York State Supreme Court, Appellate Division, Third Department ruled to uphold the lower court’s ruling overturning portions of the Resetting Order because the NYPSC did not follow the proper
18
process in issuing the Resetting Order. However, the court also determined that the NYPSC has authority to set ESCO rates and take other action consistent with the Resetting Order as long as the proper administrative process is followed. The NYPSC conducted evidentiary proceedings to determine what the regulatory framework for ESCOs in New York will be going forward, which concluded in late 2017. Briefing on these hearings is due by April 30, 2018. We believe that the administrative law judges overseeing the proceeding will provide for settlement discussions before adjudication of the matter. There can be no assurance that settlement discussions between the NYPSC and ESCOs will occur, or if such discussions occur, that they will result in a commercially reasonable framework for ESCOs to operate in New York. See "Risk Factors—We face risks due to increasing regulation of the retail energy industry at the state level."
In addition, in connection with the Low-Income Order promulgated by the NYPSC in December of 2016, the New York State Supreme Court, Appellate Division, Third Department ruled in September 2017 that ESCOs must proceed with returning existing low-income customers to utility service and stop enrolling new low-income customers. The ESCO’s have effectively exhausted their legal remedies to appeal this matter and must now comply with the Low-Income Order. ESCOs may continue serving low income customers if those customers are enrolled in longer term gift-term or guaranteed savings arrangements (that were entered into prior to the effective date of the Low-Income Order) or if the ESCO receives a waiver from the NYPSC to provide low-income customers with guaranteed savings. The Company and its subsidiaries are dropping low-income customers to the applicable utilities in the next twelve months as they roll off of their contracts. These customers represent approximately less than
1%
of our total customer count as of
December 31, 2017
.
We are evaluating the potential impact of the NYPSC's Resetting Order on our New York operations while preparing to operate in compliance with any new requirements that may come as a result of any new order promulgated by the NYPSC. Given the uncertainty of the outcome of these matters and the final requirements that may be implemented, we are unable to predict at this time whether it will have a significant long-term impact on our operations in New York.
Our marketing efforts to consumers, including but not limited to telemarketing, door-to-door sales, direct mail and online marketing, are subject to consumer protection regulation including state deceptive trade practices acts, Federal Trade Commission ("FTC") marketing standards, and state utility commission rules governing customer solicitations and enrollments, among others. By way of example, telemarketing activity is subject to federal and state do-not-call regulation and certain enrollment standards promulgated by state regulators. Door-to-door sales are governed by the FTC’s “Cooling Off” Rule as well as state-specific regulation in many jurisdictions. In markets in which we conduct customer credit checks, these checks are subject to the requirements of the Fair Credit Reporting Act. Violations of the rules and regulations governing our marketing and sales activity could impact our license to operate in a particular market, result in suspension or otherwise limit our ability to conduct marketing activity in certain markets, and potentially lead to private actions against us. Moreover, there is potential for changes to legislation and regulatory measures applicable to our marketing measures that may impact our business models.
Recent interpretations of the Telephone Consumer Protection Act of 1991 (the "TCPA") by the Federal Communications Commission ("FCC") have introduced confusion regarding what constitutes an “autodialer” for purposes of determining compliance under the TCPA. Also, additional restrictions have been placed on wireless telephone numbers making compliance with the TCPA more costly. See “Risk Factors—Risks Related to Our Business and Our Industry—Liability under the TCPA has increased significantly in recent years, and we face risks if we fail to comply."
As compliance with the TCPA gets more costly and as door-to-door marketing becomes increasingly risky both from a regulatory compliance perspective and from the risk of such activities drawing class action litigation claims, we and our peers who rely on these sales channels will find it more difficult than in the past to engage in direct marketing efforts. In response to these risks, the Company is experimenting with new technologies such as ringless messaging and door-to-door sales using tablets, both of which expand opportunities to market directly to customers.
Our participation in natural gas and electricity wholesale markets to procure supply for our retail customers and hedge pricing risk is subject to regulation by the Commodity Futures Trading Commission, including regulation
19
pursuant to the Dodd-Frank Wall Street Reform and Consumer Protection Act. In order to sell electricity, capacity and ancillary services in the wholesale electricity markets, we are required to have market-based rate authorization, also known as “MBR Authorization”, from the Federal Energy Regulatory Commission ("FERC"). We are required to make status update filings to FERC to disclose any affiliate relationships and quarterly filings to FERC regarding volumes of wholesale electricity sales in order to maintain our MBR Authorization.
The transportation and sale for resale of natural gas in interstate commerce are regulated by agencies of the U.S. federal government, primarily FERC under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and regulations issued under those statutes. FERC regulates interstate natural gas transportation rates and service conditions, which affects our ability to procure natural gas supply for our retail customers and hedge pricing risk. Since 1985, FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. FERC’s orders do not attempt to directly regulate natural gas retail sales. As a shipper of natural gas on interstate pipelines, we are subject to those interstate pipelines tariff requirements and FERC regulations and policies applicable to shippers.
Changes in law and to FERC policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines, and we cannot predict what future action FERC will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas marketers and local regulated utilities with which we compete.
On December 26, 2007, FERC issued Order 704, a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing. Under Order 704, wholesale buyers and sellers of more than 2.2 million MMBtus of physical natural gas in the previous calendar year, including natural gas gatherers and marketers, are required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. Order 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting complies with FERC’s policy statement on price reporting. As a wholesale buyer and seller of natural gas, we are subject to the reporting requirements of Order 704.
Employees
We employed
176
people as of
December 31, 2017
. This number does not include employees of Retailco Services who provide services to us under the Master Service Agreement as described under “Relationship with Our Founder and Majority Shareholder—Master Service Agreement.”
We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We consider our relations with our employees to be satisfactory. We also utilize the services of independent contractors and vendors to perform various services.
Facilities
Our corporate headquarters is located in Houston, Texas. We believe that our facilities are adequate for our current operations. We share our corporate headquarters with certain of our affiliates. NuDevco Midstream Development, LLC, an indirect subsidiary of TxEx Energy Investments, LLC, is the lessee under the lease agreement covering these facilities. NuDevco Midstream Development, LLC pays the entire lease payment on behalf of the affiliates of TxEx Energy Investments, LLC, and we reimburse NuDevco Midstream Development, LLC for our share of the leased space.
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Available Information
Our principal executive offices are located at 12140 Wickchester Ln., Suite 100, Houston, Texas 77079, and our telephone number is (713) 600-2600. Our website is located at www.sparkenergy.com. We make available our periodic reports and other information filed with or furnished to the Securities and Exchange Commission (the “SEC”), free of charge through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Any materials that we have filed with the SEC may be read and copied at the SEC’s Public Reference Room at 100 F Street, NE, Washington D.C. 20549, or accessed by calling the SEC at 1-800-SEC-0330 or visiting the SEC’s website at www.sec.gov.
21
You should carefully consider the risks described below together with the other information contained in this Annual Report on Form 10-K. Our business, financial condition, cash flows, results of operation and ability to pay dividends on our Class A common stock and Series A Preferred Stock could be adversely impacted due to any of these risks.
Risks Related to Our Business and Our Industry
We are subject to commodity price risk.
Our financial results are largely dependent on the prices at which we can acquire the commodities we resell. The prevailing market prices for natural gas and electricity have historically, and may continue to, fluctuate substantially over relatively short periods of time. Changes in market prices for natural gas and electricity may result from many factors that are outside of our control, including the following:
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disruption of natural gas or electricity transmission or transportation infrastructure or other constraints or inefficiencies;
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reduction or unavailability of generating capacity, including temporary outages, mothballing, or retirements;
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the level of prices and availability of natural gas and competing energy sources, including the impact of changes in environmental regulations impacting suppliers;
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the creditworthiness or bankruptcy or other financial distress of market participants;
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changes in market liquidity;
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natural disasters, wars, embargoes, acts of terrorism and other catastrophic events;
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significant changes in the pricing methods in the wholesale markets in which we operate;
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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;
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federal, state, foreign and other governmental regulation and legislation; and
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demand side management, conservation, alternative or renewable energy sources.
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Changes to the prices we pay to acquire commodities and that we are not able to pass along to our customers could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
Our financial results may be adversely impacted by weather conditions.
Weather conditions directly influence the demand for and availability of natural gas and electricity and affect the prices of energy commodities. Generally, on most utility systems, demand for natural gas peaks in the winter and demand for electricity peaks in the summer. Typically, when winters are warmer or summers are cooler, demand for energy is lower than expected, resulting in less natural gas and electricity consumption than forecasted. When demand is below anticipated levels due to weather patterns, we may be forced to sell excess supply at prices below our acquisition cost, which could result in reduced margins or even losses.
Conversely, when winters are colder or summers are warmer, consumption may outpace the volumes of natural gas and electricity against which we have hedged, and we may be unable to meet increased demand with storage or swing supply. In these circumstances, we may experience reduced margins or even losses if we are required to purchase additional supply at higher prices. Our failure to accurately anticipate demand due to fluctuations in weather or to effectively manage our supply in response to a fluctuating commodity price environment could
22
materially and adversely affect our business, financial condition, cash flows and results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
Our risk management policies and hedging procedures may not mitigate risk as planned, and we may fail to fully or effectively hedge our commodity supply and price risk.
To provide energy to our customers, we purchase commodities in the wholesale energy markets, which are often highly volatile. Our commodity risk management strategy is designed to hedge substantially all of our forecasted volumes on our fixed-price customer contracts, as well as a portion of the near-term volumes on our variable-price customer contracts. We use both physical and financial products to hedge our exposure. The efficacy of our risk management program may be adversely impacted by unanticipated events and costs that we are not able to effectively hedge, including abnormal customer attrition and consumption, certain variable costs associated with electricity grid reliability, pricing differences in the local markets for local delivery of commodities, unanticipated events that impact supply and demand, such as extreme weather, and abrupt changes in the markets for, or availability or cost of, financial instruments that help to hedge commodity price.
We are exposed to basis risk in our operations when the commodities we hedge are sold at different delivery points from the exposure we are seeking to hedge. For example, if we hedge our natural gas commodity price with Chicago basis but physical supply must be delivered to the individual delivery points of specific utility systems around the Chicago metropolitan area, we are exposed to basis risk between the Chicago basis and the individual utility system delivery points. These differences can be significant from time to time, particularly during extreme, unforecasted cold weather conditions. Similarly, in certain of our electricity markets, customers pay the load zone price for electricity, so if we purchase supply to be delivered at a hub, we may have basis risk between the hub and the load zone electricity prices due to local congestion that is not reflected in the hub price. We attempt to hedge basis risk where possible, but hedging instruments are sometimes not economically feasible or available in the smaller quantities that we require.
Additionally, assumptions that we use in establishing our hedges may reduce the effectiveness of our hedging instruments. Considerations that may affect our hedging policies include, but are not limited to, human error, assumptions about customer attrition, the relationship of prices at different trading or delivery points, assumptions about future weather, and our load forecasting models.
In addition, we incur costs monthly for ancillary charges such as reserves and capacity in the electricity sector by ISOs. For example, the ISOs will charge all retail electricity providers for monthly reserves that the ISO determines are necessary to protect the integrity of the grid. We attempt to estimate such amounts but they are difficult to estimate because they are charged in arrears by the ISOs and are subject to fluctuations based on weather and other market conditions. We may be unable to fully pass the higher cost of ancillary reserves and reliability services through to our customers, and increases in the cost of these ancillary reserves and reliability services could negatively impact our results of operations.
Many of the natural gas utilities we serve allocate a share of transportation and storage capacity to us as a part of their competitive market operations. We are required to fill our allocated storage capacity with natural gas, which creates commodity supply and price risk. Sometimes we cannot hedge the volumes associated with these assets because they are too small compared to the much larger bulk transaction volumes required for trades in the wholesale market or it is not economically feasible to do so. In some regulatory programs or under some contracts, this capacity may be subject to recall by the utilities, which could have the effect of us being required to access the spot market to cover such recall.
If we are unable to effectively manage our risk management policies and hedging procedures, it could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
We face risks due to increasing regulation of the retail energy industry at the state level.
23
Some states are beginning to increase their regulation of their retail electricity and natural gas markets in an effort to eliminate deceptive marketing practices. For example, in 2015 the Connecticut Legislature passed legislation providing that licensed electric suppliers in Connecticut could no longer offer variable rate products.
Additionally, the New York Public Service Commission (the “NYPSC”) began an aggressive campaign in 2016 to limit the types of competitive products that ESCOs, such as us, can offer in New York. The NYPSC attempted to implement a market resetting order requiring that all new customer enrollments or expiring agreements for mass market (residential and certain small commercial) customers must enroll or re-enroll in a contract that offers either: (i) a guarantee that the customer will pay no more than what the customer would pay as a full service utility customer, or (ii) an electricity product that is at least 30% derived from specific renewable sources either in the State of New York or in adjacent market areas. Most of the original resetting order was vacated by a New York state court on July 22, 2016. However, the ESCOs lost an appeal on the matter of whether the NYPSC has jurisdiction over ESCO pricing of products. Currently, ESCOs and the NYPSC are involved in evidentiary proceedings that are addressing, among other things, whether the NYPSC has sufficient cause to implement another similar resetting order. In the event that all or significant components of the original resetting order are re-implemented, ESCOs, including us, could be obligated to drop customers to the utility or seek affirmative consent from their fixed and variable rate customers upon renewal, which may be very difficult to obtain. As of
December 31, 2017
, approximately
16%
of our customers on an RCE basis were located in New York.
The NYPSC has also successfully implemented a low-income order that requires ESCOs to return existing low-income customers to utility service and stop enrolling new low-income customers unless customers are enrolled in guaranteed savings arrangements (that were entered into prior to the effective date of the low-income order) or if the ESCO receives a waiver from the NYPSC to provide low-income customers with guaranteed savings. As a result of the low-income order, we are being required to drop low-income customers to the applicable utilities in the next twelve months, representing approximately less than
1%
of our total customer count as of
December 31, 2017
.
There can be no assurance that the NYPSC or state regulatory agencies to which we are subject will not continue trying to implement restrictive anti-competitive regulations on us. Any such regulations could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
The retail energy business is subject to a high level of federal, state and local regulations, which are subject to change.
Our costs of doing business may fluctuate based on changing state, federal and local rules and regulations. For example, many electricity markets have rate caps, and changes to these rate caps by regulators can impact future price exposure. Similarly, regulatory changes can result in new fees or charges that may not have been anticipated when existing retail contracts were drafted, which can create financial exposure. Our ability to manage cost increases that result from regulatory changes will depend, in part, on how the “change in law provisions” of our contracts are interpreted and enforced, among other factors. Accordingly, changing or additional regulations or restrictions could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
Liability under the TCPA has increased significantly in recent years, and we face risks if we fail to comply.
Our outbound telemarketing efforts and use of mobile messaging to communicate with our customers subjects us to regulation under the TCPA. Over the last several years, companies have been subject to significant liabilities as a result of violations of the TCPA, including penalties, fines and damages under class action lawsuits. In addition, the increased use by us and other consumer retailers of mobile messaging to communicate with our customers has created new issues of application of the TCPA to these communications. In 2015, the Federal Communications Commission issued several rulings that made compliance with the TCPA more difficult and costly. Our failure to effectively monitor and comply with our activities that are subject to the TCPA could result in significant penalties and the adverse effects of having to defend and ultimately suffer liability in a class action lawsuit related to such non-compliance.
24
We are also subject to liability under the TCPA for actions of our third party vendors who are engaging in outbound telemarketing efforts on our behalf. The issue of vicarious liability for the actions of third parties in violation of the TCPA remains unclear and has been the subject of conflicting precedent in the federal appellate courts. There can be no assurance that we may be subject to significant damages as a result of a class action lawsuit for actions of our vendors that we may not be able to control. If any violation of the TCPA were to occur, it could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
We are subject to risks of significant liability resulting from class action lawsuits.
In recent years, retail energy providers have been named as defendants in class action lawsuits relating to pricing and sales practices, among other matters. A number of these lawsuits have resulted in substantial jury awards or settlements. We are currently a defendant in several class action lawsuits involving sales practices or TCPA claims. A negative outcome could result in significant damages depending on whether a class is certified, and if so, the size of a such class. Future litigation relating to our pricing and sales practices may negatively impact us by requiring us to pay substantial awards or settlements, increasing our legal costs, diverting management attention from other business issues or harming our reputation with customers, which could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
Our business is dependent on retaining licenses in the markets in which we operate.
Our business model is dependent on continuing to be licensed in existing markets. If we have a license revoked or are not granted renewal of a license, or if our license is adversely conditioned or modified (e.g., by increased bond posting obligations), it could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
We may be subject to risks in connection with acquisitions, which could cause us to fail to realize many of the anticipated benefits of such acquisitions.
We intend to grow our business in part through strategic acquisition opportunities from third parties and potentially from affiliates of our majority shareholder. Achieving the anticipated benefits of these transactions will depend in part upon our ability to identify accretive acquisition targets, accurately assess the benefits and risks of the acquisition prior to undertaking it, and our ability to integrate the acquired businesses in an efficient and effective manner.
We intend to make acquisitions that are accretive to Adjusted EBITDA. We may be unable to identify attractive acquisition candidates or negotiate commercially acceptable terms for such acquisitions. Even if we identify a target, the successful acquisition of a business requires assessing several factors, including anticipated cash flow and accretive value, regulatory challenges, our ability to retain customers and assumed liabilities. The accuracy of these assessments is inherently uncertain and our assessments may turn out incorrect.
Furthermore, even if we make an acquisition, we may not be able to accomplish the integration process smoothly or successfully. The difficulties of integrating our acquisitions potentially will include, among other things:
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coordinating geographically separate organizations and addressing possible differences in corporate cultures and management philosophies;
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dedicating significant management resources to the integration of acquisitions, which may temporarily distract management's attention from the day-to-day business of the combined company;
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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;
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operating in states and markets where we have not previously conducted business;
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managing different and competing brands and retail strategies in the same markets;
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coordinating customer information and billing systems and determining how to optimize those systems on a consolidated level;
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ensuring our hedging strategy adequately covers a customer base that is managed through multiple systems; and
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successfully recognizing expected cost savings and other synergies in overlapping functions.
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In many of our acquisition agreements, we are entitled to indemnification from the counter party for various matters, including breaches of representations, warranties and covenants, tax matters, and litigation proceedings. We generally obtain security to provide assurances that the counterparty could perform its indemnification obligations, which may be in the form of escrow accounts, payment withholding or other methods. However, to the extent that we do not obtain security, or the security turns out to be inadequate, there is a risk that the counter-party may fail to perform its indemnification obligations, which could result in the losses being incurred by us.
If any of the risks above were to occur, it could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
Pursuant to our cash dividend policy, we distribute a significant portion of our cash through regular quarterly dividends, and our ability to grow and make acquisitions with cash on hand could be limited.
Pursuant to our cash dividend policy, we have been distributing, and intend to distribute, a significant portion of our cash through regular quarterly dividends to holders of our Class A common stock and dividends on our Series A Preferred Stock. As such, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations, and we may have to rely upon external financing sources, including the issuance of debt, equity securities, convertible subordinated notes and borrowings under our Senior Credit Facility and Subordinated Facility. If these sources are not available, our ability to grow and maintain our business may be limited, which could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
We may not be able to manage our growth successfully.
The growth of our operations will depend upon our ability to expand our customer base in our existing markets and to enter new markets in a timely manner at reasonable costs, organically or through acquisitions. In order for us to recover expenses incurred in entering new markets and obtaining new customers, we must attract and retain customers on economic terms and for extended periods. We may experience difficulty managing our growth and implementing new product offerings, integrating new customers and employees, and complying with applicable market rules and the infrastructure for product delivery.
Expanding our operations also may require continued development of our operating and financial controls and may place additional stress on our management and operational resources. If we are unable to manage our growth and development successfully, it could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
The termination of our Master Service Agreement subjects us to a variety of risks.
A significant portion of our operations, including enrollment and renewal transaction services, customer billing and transaction services, electronic payment processing services, customer services and information technology infrastructure and application support services, is currently provided to us by our affiliate, Retailco Services, LLC, for a fixed fee under the Master Service Agreement. The Master Service Agreement will terminate effective April 1, 2018, and we will be reintegrating the services previously provided to us by Retailco Services, LLC under the Master Service Agreement back into our operations. We may experience costs integrating these services back into our operations. Additionally, following the integration of those services back into our operations, we may
26
experience fluctuations in general and administrative costs that we did not experience under the fixed-fee arrangement of the Master Service Agreement. If any of the risks above were to occur, it could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
Our financial results fluctuate on a seasonal, quarterly and annual basis.
Our overall operating results fluctuate substantially on a seasonal, quarterly and annual basis depending on: (1) the geographic mix of our customer base; (2) the concentration of our product mix; (3) the impact of weather conditions on commodity pricing and demand; (4) variability in market prices for natural gas and electricity, and (5) changes in the cost of delivery of commodities through energy delivery networks. These factors can have material short-term impacts on monthly and quarterly operating results, which may be misleading when considered outside of the context of our annual operating cycle. In addition, our accounts payable and accounts receivable are impacted by seasonality due to the timing differences between when we pay our suppliers for accounts payable versus when we collect from our customers on accounts receivable. We typically pay our suppliers for purchases of natural gas on a monthly basis and electricity on a weekly basis. However, it takes approximately two months from the time we deliver the electricity or natural gas to our customers before we collect from our customers on accounts receivable attributable to those supplies. This timing difference could affect our cash flows, especially during peak cycles in the winter and summer months. Furthermore, as a result of the seasonality of our business, we may reserve a portion of our excess cash available for distribution in the first and fourth quarters in order to fund our second and third quarter distributions.
Additionally, we enter into a variety of financial derivative and physical contracts to manage commodity price risk, and we use mark-to-market accounting to account for this hedging activity. Under the mark-to-market accounting method, changes in the fair value of our hedging instruments that are not qualifying or not designated as hedges under accounting rules are recognized immediately in earnings. As a result of this accounting treatment, changes in the forward prices of natural gas and electricity cause volatility in our quarterly and annual earnings, which we are unable to fully anticipate.
We could also incur volatility from quarter to quarter associated with gains and losses on settled hedges relating to natural gas held in inventory if we choose to hedge the summer-winter spread on our retail allocated storage capacity. We typically purchase natural gas inventory and store it from April to October for withdrawal from November through March. Since a portion of the inventory is used to satisfy delivery obligations to our fixed-price customers over the winter months, we hedge the associated price risk using derivative contracts. Any gains or losses associated with settled derivative contracts are reflected in the statement of operations as a component of retail cost of sales and net asset optimization.
Accordingly, we may experience seasonal, quarterly and annual fluctuations, which could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
We may have difficulty retaining our existing customers or obtaining a sufficient number of new customers, due to competition and for other reasons.
The markets in which we compete are highly competitive, and we may face difficulty retaining our existing customers or obtaining new customers due to competition. We encounter significant competition from local regulated utilities or their retail affiliates and traditional and new retail energy providers. Many of these competitors or potential competitors are larger than us, have access to more significant capital resources, have more well-established brand names and have larger existing installed customer bases.
Additionally, existing customers may switch to other retail energy service providers during their contract terms in the event of a significant decrease in the retail price of natural gas or electricity in order to obtain more favorable prices. Although we generally have a right to collect a termination fee from each customer on a fixed-price contract
27
who terminates their contract early, we may not be able to collect the termination fees in full or at all. Our variable-price contracts can typically be terminated by our customers at any time without penalty.
If we are unable to obtain new customers or maintain our existing customers, due to competition or otherwise, it could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
Increased collateral requirements in connection with our supply activities may restrict our liquidity, which could limit our ability to grow our business or pay dividends.
Our contractual agreements with certain local regulated utilities and our supplier counterparties require us to maintain restricted cash balances or letters of credit as collateral for credit risk or the performance risk associated with the future delivery of natural gas or electricity. These collateral requirements may increase as we grow our customer base. Collateral requirements will increase based on the volume or cost of the commodity we purchase in any given month and the amount of capacity or service contracted for with the local regulated utility. Significant changes in market prices also can result in fluctuations in the collateral that local regulated utilities or suppliers require.
The effectiveness of our operations and future growth depend in part on the amount of cash and letters of credit available to enter into or maintain these contracts. The cost of these arrangements may be affected by changes in credit markets, such as interest rate spreads in the cost of financing between different levels of credit ratings. These liquidity requirements may be greater than we anticipate or are able to meet. If any of these risks were to occur, it could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
We are subject to direct credit risk for certain customers who may fail to pay their bills as they become due.
We bear direct credit risk related to our customers located in markets that have not implemented POR programs as well as indirect credit risk in those POR markets that pass collection efforts along to us after a specified non-payment period. For the year ended
December 31, 2017
, customers in non-POR markets represented approximately
34%
of our retail revenues. We generally have the ability to terminate contracts with customers in the event of non-payment, but in most states in which we operate we cannot disconnect their natural gas or electricity service. In POR markets where the local regulated utility has the ability to return non-paying customers to us after specified periods, we may realize a loss for one to two billing periods until we can terminate these customers’ contracts. We may also realize a loss on fixed-price customers in this scenario due to the fact that we will have already fully hedged the customer’s expected commodity usage for the life of the contract and we also remain liable to our suppliers of natural gas and electricity for the cost of our supply commodities. Furthermore, in the Texas market, we are responsible for billing the distribution charges for the local regulated utility and are at risk for these charges, in addition to the cost of the commodity, in the event customers fail to pay their bills. Changing economic factors, such as rising unemployment rates and energy prices also result in a higher risk of customers being unable to pay their bills when due.
The failure of our customers to pay their bills or our failure to maintain adequate billing and collection procedures could adversely affect our financial results and our ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
Our indebtedness could adversely affect our ability to raise additional capital to fund our operations or pay dividends. It could also expose us to the risk of increased interest rates and limit our ability to react to changes in the economy or our industry as well as impact our cash available for distribution.
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We have
$125.3 million
of indebtedness outstanding and
$47.2 million
in issued letters of credit under our Senior Credit Facility, and no indebtedness outstanding under our Subordinated Facility as of
December 31, 2017
. Debt we incur under our Senior Credit Facility, Subordinated Facility or otherwise could have negative consequences, including:
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increasing our vulnerability to general economic and industry conditions;
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requiring cash flow from operations to be dedicated to the payment of principal and interest on our indebtedness, therefore reducing our ability to pay dividends to holders of our Class A common stock and Series A Preferred Stock, or to use our cash flow to fund our operations, capital expenditures and future business opportunities;
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limiting our ability to fund future acquisitions or engage in other activities that we view as in our long-term best interest;
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restricting our ability to make certain distributions with respect to our capital stock and the ability of our subsidiaries to make certain distributions to us, in light of restricted payment and other financial covenants, including requirements to maintain certain financial ratios, in our credit facilities and other financing agreements;
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exposing us to the risk of increased interest rates because borrowings under our Senior Credit Facility are at variable rates of interest; and
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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.
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If we are unable to satisfy financial covenants in our debt instruments, it could result in an event of default that, if not cured or waived, may entitle the lenders to demand repayment or enforce their security interests. Our Senior Credit Facility will mature on May 19, 2019, and we cannot assure that we will be able to negotiate a new credit arrangement on commercially reasonable terms. The occurrence of any of the events above could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
We depend on the accuracy of data in our information management systems, which subjects us to risks.
We depend on the accuracy and timeliness of our information management systems for billing, collections, consumption and other important data. We rely on many internal and external sources for this information, including:
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our marketing, pricing and customer operations functions; and
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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:
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inaccurate and/or untimely bills sent to customers;
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incorrect tax remittances;
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reduced effectiveness and efficiency of our operations;
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inability to adequately hedge our portfolio;
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increased overhead costs;
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inaccurate accounting and reporting of customer revenues, gross margin and accounts receivable activity;
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inaccurate measurement of usage rates, throughput and imbalances;
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customer complaints; and
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increased regulatory scrutiny.
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We are also subject to disruptions in our information management systems arising out of events beyond our control, such as natural disasters, epidemics, failures in hardware or software, power fluctuations, telecommunications and
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other similar disruptions. In addition, our information management systems may be vulnerable to computer viruses, incursions by intruders or hackers and cyber terrorists and other similar disruptions. A successful cyber-attack on our information management systems could severely disrupt business operations, preventing us from billing and collecting revenues, and could result in significant expenses to investigate and repair security breaches or system damage, lead to litigation, fines, other remedial action, heightened regulatory scrutiny, diminished customer confidence and damage to our reputation. We do not maintain cyber-liability insurance that covers certain damage caused by cyber events.
Inaccurate data and disruptions of our information management systems to perform as anticipated for any reason could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
Our success depends on key members of our management, the loss of whom could disrupt our business operations.
We depend on the continued employment and performance of key management personnel. A number of our senior executives have substantial experience in consumer and energy markets that have undergone regulatory restructuring and have extensive risk management and hedging expertise. We believe their experience is important to our continued success. We do not maintain key life insurance policies for our executive officers. If our key executives do not continue in their present roles and are not adequately replaced, it could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
We rely on a third party vendor for our customer billing and transactions platform that exposes us to third party performance risk.
We have outsourced our back office customer billing and transactions functions to a third party, and we rely heavily on the continued performance of that vendor under the outsourcing agreement. Failure of our vendor to operate in accordance with the terms of the outsourcing agreement or the vendor’s bankruptcy or other event that prevents it from performing under our outsourcing agreement could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
A large portion of our current customers are concentrated in a limited number of states, making us vulnerable to customer concentration risks.
As of
December 31, 2017
, approximately
60%
of our RCEs were located in
five
states. Specifically,
16%
,
12%
,
12%
,
11%
and
9%
of our customers on an RCE basis were located in NY, PA, CT, MA, and NH, respectively. If we are unable to increase our market share across other competitive markets or enter into new competitive markets effectively, we may be subject to continued or greater customer concentration risk. In addition, if any of the states that contain a large percentage of our customers were to reverse regulatory restructuring or change the regulatory environment in a manner that causes us to be unable to economically operate in that state, it could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
Increases in state renewable portfolio standards or an increase in the cost of renewable energy credit and carbon offsets may adversely impact the price, availability and marketability of our products.
Pursuant to state renewable portfolio standards, we must purchase a specified amount of renewable energy credits, or RECs, based on the amount of electricity we sell in a state in a year. In addition, we have contracts with certain customers that require us to purchase RECs or carbon offsets. If a state increases its renewable portfolio standards, the demand for RECs within that state will increase and therefore the market price for RECs could increase. We attempt to forecast the price for the required RECs and carbon offsets at the end of each month and incorporate this forecast into our customer pricing models, but the price paid for RECs and carbon offsets may be higher than
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forecasted. We may be unable to fully pass the higher cost of RECs through to our customers, and increases in the price of RECs may decrease our results of operations and affect our ability to compete with other energy retailers that have not contracted with customers to purchase RECs or carbon offsets. Further, a price increase for RECs or carbon offsets may require us to decrease the renewable portion of our energy products, which may result in a loss of customers. A further reduction in benefits received by local regulated utilities from production tax credits in respect of renewable energy may adversely impact the availability to us, and marketability by us, of renewable energy under our brands. Accordingly, such decrease may result in reduced revenue and could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
Our access to marketing channels may be contingent upon the viability of our telemarketing and door-to-door agreements with our vendors.
Our vendors are essential to our telemarketing and door-to-door sales activities. Our ability to increase revenues in the future will depend significantly on our access to high quality vendors. If we are unable to attract new vendors and retain existing vendors to achieve our marketing targets, our growth may be materially reduced. There can be no assurance that competitive conditions will allow these vendors and their independent contractors to continue to successfully sign up new customers. Further, if our products are not attractive to, or do not generate sufficient revenue for our vendors, we may lose our existing relationships. In addition, the decline in landlines reduces the number of potential customers that may be reached by our telemarketing efforts and as a result our telemarketing sales channel may become less viable and we may be required to use more door-to-door marketing. Door-to-door marketing is continually under scrutiny by state regulators and legislators, which may lead to new rules and regulations that impact our ability to use these channels. If any of these risks were to occur, it could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
Our vendors may expose us to risks.
We are subject to reputational risks that may arise from the actions of our vendors and their independent contractors that are wholly or partially beyond our control, such as violations of our marketing policies and procedures as well as any failure to comply with applicable laws and regulations. If our vendors engage in marketing practices that are not in compliance with local laws and regulations, we may be in breach of applicable laws and regulations that may result in regulatory proceedings, disadvantageous conditioning of our energy retailer license, or the revocation of our energy retailer license. Unauthorized activities in connection with sales efforts by agents of our vendors, including calling consumers in violation of the TCPA and predatory door-to-door sales tactics and fraudulent misrepresentation could subject us to class action lawsuits against which we will be required to defend. Such defense efforts will be costly and time consuming. In addition, the independent contractors of our vendors may consider us to be their employer and seek compensation.
If any of these risks were to occur, it could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
Risks Related to Our Capital Stock
We cannot assure you that we will be able to continue paying our targeted quarterly dividend to the holders of our Class A common stock or dividends to the holders of our Series A Preferred Stock in the future.
The amount of our cash available for distribution principally depends upon the amount of cash we generate from our operations, which fluctuates from quarter to quarter based on, among other things:
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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;
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the level and timing of customer acquisition costs we incur;
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the level of our operating and general and administrative expenses;
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seasonal variations in revenues generated by our business;
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our debt service requirements and other liabilities;
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fluctuations in our working capital needs;
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our ability to borrow funds and access capital markets;
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restrictions contained in our debt agreements (including our Senior Credit Facility);
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— management of customer credit risk;
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abrupt changes in regulatory policies; and,
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other business risks affecting our cash flows.
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As a result of these and other factors, we cannot guarantee that we will have sufficient cash generated from operations to pay the dividends on our Series A Preferred Stock or to pay a specific level of cash dividends to holders of our Class A common stock.
Due to the seasonality of our retail natural gas business, we generate the substantial majority of our cash available for distribution in the first and fourth quarters of each year. As a result of seasonality and our customer acquisition costs, we may not have sufficient cash available for distribution to cover quarterly dividends for certain quarters.
The amount of cash available for distribution depends primarily on our cash flow, and is not solely a function of profitability, which is affected by non-cash items. We may incur other expenses or liabilities during a period that could significantly reduce or eliminate our cash available for distribution and, in turn, impair our ability to pay dividends to holders of our Class A common stock and Series A Preferred Stock during the period. Additionally, the dividends paid on Series A Preferred Stock reduce the amount of cash we have available to pay dividends on our Class A common stock.
Each new share of Class A common stock and Series A Preferred Stock issued increases the cash required to continue to pay cash dividends. Any Class A common stock or preferred stock (whether Series A Preferred Stock or a new series of preferred stock) that may in the future be issued to finance acquisitions, upon exercise of stock options or otherwise, would have a similar effect.
Finally, dividends to holders of our Class A common stock are paid at the discretion of our board of directors. Our board of directors may decrease the level of or entirely discontinue payment of dividends.
We could be prevented from paying cash dividends on the Class A common stock and Series A Preferred Stock.
Holders of shares of Class A common stock and Series A Preferred Stock do not have a right to dividends on such shares unless declared or set aside for payment by our board of directors. Under Delaware law, cash dividends on capital stock may only be paid from “surplus” or, if there is no “surplus,” from the corporation’s net profits for the then-current or the preceding fiscal year. Unless we operate profitably, our ability to pay cash dividends on the Class A common stock and Series A Preferred Stock would require the availability of adequate “surplus,” which is defined as the excess, if any, of net assets (total assets less total liabilities) over capital. Our business may not generate sufficient cash flow from operations to enable us to pay dividends on the Series A Preferred Stock when payable, and quarterly dividends on the Class A common stock. Further, even if adequate surplus is available to pay cash dividends on the Class A common stock and Series A Preferred Stock, we may not have sufficient cash to pay dividends on the Class A common stock or Series A Preferred Stock.
Furthermore, no dividends on Class A common stock or Series A Preferred Stock shall be authorized by our board of directors or paid, declared or set aside for payment by us at any time when the authorization, payment, declaration or setting aside for payment would be unlawful under Delaware law or any other applicable law, or when the terms and provisions of any documents limiting the payment of dividends prohibit the authorization, payment, declaration or setting aside for payment thereof or would constitute a breach or a default under such document.
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We are a holding company. Our sole material asset is our equity interest in Spark HoldCo and we are accordingly dependent upon distributions from Spark HoldCo to pay dividends on the Class A common stock and Series A Preferred Stock.
We are a holding company and have no material assets other than our equity interest in Spark HoldCo, and have no independent means of generating revenue. To the extent that we need funds and Spark HoldCo or its subsidiaries are restricted from making distributions to us under applicable law or regulation or under the terms of their financing arrangements, or are otherwise unable to provide such funds, it could materially and adversely affect our business, financial condition, cash flows, results of operations and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
The Class A common stock and Series A Preferred Stock are subordinated to our existing and future debt obligations.
The Class A common stock and Series A Preferred Stock are subordinated to all of our existing and future indebtedness (including indebtedness outstanding under the Senior Credit Facility). Therefore, if we become bankrupt, liquidate our assets, reorganize or enter into certain other transactions, assets will be available to pay our obligations with respect to the Series A Preferred Stock only after we have paid all of our existing and future indebtedness in full. The Class A common stock will only receive assets to the extent all existing and future indebtedness and obligations under the Series A Preferred Stock is paid in full. If any of these events were to occur, there may be insufficient assets remaining to make any payments to holders of the Series A Preferred Stock or Class A common stock.
Additionally, none of our subsidiaries has guaranteed or otherwise become obligated with respect to the Class A common stock or Series A Preferred Stock. As a result, the Class A common stock and Series A Preferred Stock effectively rank junior to all existing and future indebtedness and other liabilities of our subsidiaries, including our operating subsidiaries, and any capital stock of our subsidiaries not held by us. Accordingly, our right to receive assets from any of our subsidiaries upon our bankruptcy, liquidation or reorganization, and the right of holders of shares of Class A common stock and Series A Preferred Stock to participate in those assets, is also structurally subordinated to claims of that subsidiary’s creditors, including trade creditors. Even if we were a creditor of any of our subsidiaries, our rights as a creditor would be subordinate to any security interest in the assets of that subsidiary and any indebtedness of that subsidiary senior to that held by us.
Numerous factors may affect the trading price of the Class A common stock and Series A Preferred Stock.
The trading price of the Class A common stock and Series A Preferred Stock may depend on many factors, some of which are beyond our control, including:
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prevailing interest rates;
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the market for similar securities;
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— our issuance of debt or other preferred equity securities; and
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our financial condition, results of operations and prospects.
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One of the factors that will influence the price of the Class A common stock and Series A Preferred Stock will be the distribution yield of the securities (as a percentage of the then market price of the securities) relative to market interest rates. An increase in market interest rates, which are currently at low levels relative to historical rates, may lead prospective purchasers of shares of Class A common stock or Series A Preferred Stock to expect a higher distribution yield, and cause them to sell their Class A common stock or Series A Preferred Stock. Accordingly, higher market interest rates could cause the market price of the Class A common stock and Series A Preferred Stock to decrease.
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In addition, over the last several years, prices of equity securities in the U.S. trading markets have been experiencing extreme price fluctuations. As a result of these and other factors, investors holding our Class A common stock and Series A Preferred Stock may experience a decrease in the value of their securities, which could be substantial and rapid, and could be unrelated to our financial condition, performance or prospects.
There may not be an active trading market for the Class A common stock or Series A Preferred Stock, which may in turn reduce the market value and your ability to transfer or sell your shares of Class A common stock or Series A Preferred Stock.
There are no assurances that there will be an active trading market for our Class A common stock or Series A Preferred Stock. The liquidity of any market for the Class A common stock and Series A Preferred Stock will depend upon the number of stockholders, our results of operations and financial condition, the market for similar securities, the interest of securities dealers in making a market in the Class A common stock and Series A Preferred Stock, and other factors. To the extent that an active trading market is not maintained, the liquidity and trading prices for the Class A common stock and Series A Preferred Stock may be harmed.
Furthermore, because the Series A Preferred Stock does not have any stated maturity and is not subject to any sinking fund or mandatory redemption, stockholders seeking liquidity will be limited to selling their respective shares of Series A Preferred Stock in the secondary market. Active trading markets for the Series A Preferred Stock may not exist at such times, in which case the trading price of your shares of our Series A Preferred Stock could be reduced and your ability to transfer such shares could be limited.
Our Founder holds a substantial majority of the voting power of our common stock.
Holders of Class A common stock and Class B common stock vote together as a single class on all matters presented to our stockholders for their vote or approval, except as otherwise required by applicable law or our certificate of incorporation and bylaws. Our Founder controls
67.0%
of the combined voting power of the Class A common stock and Class B common stock as of
December 31, 2017
through his direct and indirect ownership, including Retailco, LLC, which is the holder of approximately
63.3%
of the combined voting power of the Class A common stock and Class B common stock.
Retailco, LLC is entitled to act separately in its own interest with respect to its investment in us. Retailco, LLC has the ability to elect all of the members of our board of directors, and thereby to control our management and affairs. In addition, Retailco, LLC is able to determine the outcome of all matters requiring Class A common stock and Class B common stock shareholder approval, including mergers and other material transactions, and is able to cause or prevent a change in the composition of our board of directors or a change in control of our company that could deprive our stockholders of an opportunity to receive a premium for their Class A common stock as part of a sale of our company. The existence of a significant shareholder, such as our Founder, may also have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other stockholders to approve transactions that they may deem to be in the best interests of our company.
So long as Retailco, LLC continues to control a significant amount of our common stock, it will continue to be able to strongly influence all matters requiring shareholder approval, regardless of whether other stockholders believe that a potential transaction is in their own best interests. In any of these matters, the interests of Retailco, LLC may differ or conflict with the interests of our other stockholders. Moreover, this concentration of stock ownership may also adversely affect the trading price of our Class A common stock or Series A Preferred Stock to the extent investors perceive a disadvantage in owning stock of a company with a controlling shareholder.
As a holder of Series A Preferred Stock, you have extremely limited voting rights.
Your voting rights as a holder of shares of Series A Preferred Stock are extremely limited. Our Class A common stock and our Class B common stock are the only classes of our securities carrying full voting rights. Holders of the Series A Preferred Stock generally have no voting rights.
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We are a “controlled company” under NASDAQ Global Select Market rules, and as such we are entitled to an exemption from certain corporate governance standards of the NASDAQ Global Select Market, and you may not have the same protections afforded to shareholders of companies that are subject to all of the NASDAQ Global Market corporate governance requirements.
We qualify as a “controlled company” within the meaning of NASDAQ Global Select Market corporate governance standards because Retailco, LLC controls more than 50% of our voting power. Under NASDAQ Global Select Market rules, a company of which more than 50% of the voting power is held by an individual, a group or another company is a “controlled company” and may elect not to comply with certain corporate governance requirements.
In light of our status as a controlled company, our board of directors has determined to take partial advantage of the controlled company exemption. Our board of directors has determined not to have a nominating and corporate governance committee and that our compensation committee will not consist entirely of independent directors. As a result, non-independent directors may among other things, appoint future members of our board of directors, resolve corporate governance issues, establish salaries, incentives and other forms of compensation for officers and other employees and administer our incentive compensation and benefit plans.
Accordingly, you may not have the same protections afforded to shareholders of companies that are subject to all of NASDAQ Global Select Market corporate governance requirements.
We engage in transactions with our affiliates and expect to do so in the future. The terms of such transactions and the resolution of any conflicts that may arise may not always be in our or our stockholders’ best interests.
We have engaged in transactions and expect to continue to engage in transactions with affiliated companies. We have acquired companies and books of customers from our affiliates and may do so in the future. We will continue to enter into back-to-back transactions for purchases of commodities and derivatives on behalf of our affiliate. We will also continue to pay certain expenses on behalf of several of our affiliates for which we will seek reimbursement. We will also continue to share our corporate headquarters with certain affiliates. We cannot assure that our affiliates will reimburse us for the costs we have incurred on their behalf or perform their obligations under any of these contracts.
Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our Class A common stock.
Our amended and restated certificate of incorporation authorizes our board of directors to issue preferred stock without shareholder approval. On October 7, 2016, we filed a registration statement under the Securities Act on Form S-3 allowing us to offer and sell, from time to time, shares of preferred stock. The registration statement was declared effective on October 20, 2016. The election by our board of directors to issue preferred stock with anti-takeover provisions could make it more difficult for a third party to acquire us.
In addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders. Among other things, our amended and restated certificate of incorporation and amended and restated bylaws:
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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;
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provide that the authorized number of directors may be changed only by resolution of the board of directors;
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provide that all vacancies in our board, including newly created directorships, may, except as otherwise required by law or, if applicable, the rights of holders of a series of preferred stock, be filled by the affirmative vote of a majority of directors then in office, even if less than a quorum;
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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;
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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);
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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);
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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;
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provide that our amended and restated bylaws can be amended by the board of directors; and
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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.
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In addition, in our amended and restated certificate of incorporation, we have elected not to be subject to the provisions of Section 203 of the Delaware General Corporation Law (the “DGCL”) regulating corporate takeovers until the date on which W. Keith Maxwell III no longer beneficially owns in the aggregate more than fifteen percent of the outstanding Class A common stock and Class B common stock. On and after such date, we will be subject to the provisions of Section 203 of the DGCL.
In addition, certain change of control events have the effect of accelerating the payment due under our Tax Receivable Agreement, which could be substantial and accordingly serve as a disincentive to a potential acquirer of our company.
Our amended and restated certificate of incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.
Our amended and restated certificate of incorporation provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim against us or any director or officer or other employee of ours arising pursuant to any provision of the DGCL, our amended and restated certificate of
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incorporation or our bylaws, or (iv) any action asserting a claim against us or any director or officer or other employee of ours that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of our amended and restated certificate of incorporation described in the preceding sentence. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our amended and restated certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.
Future sales of our Class A common stock and Series A Preferred Stock in the public market could reduce the price of the Class A common stock and Series A Preferred Stock, and may dilute your ownership in us.
On October 7, 2016, we filed a registration statement under the Securities Act on Form S-3 registering the primary offer and sale, from time to time, of Class A common stock, preferred stock, depositary shares and warrants. The registration statement also registers the Class A common stock held by Retailco and NuDevco (including Class A common stock that may be obtained upon conversion of Class B common stock). All of the shares of Class A common stock held by Retailco and NuDevco and registered on the registration statement may be immediately resold. The registration statement was declared effective on October 20, 2016.
We cannot predict the size of future issuances of our Class A common stock or securities convertible into Class A common stock or the effect, if any, that future issuances or sales of shares of our Class A common stock will have on the market price of our Class A common stock. Sales of substantial amounts of our Class A common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our Class A common stock.
We may also in the future sell additional shares of preferred stock, including shares of Series A Preferred Stock, on terms that may differ from those we have previously issued. Such shares could rank on parity with or, subject to the voting rights referred to above (with respect to issuances of new series of preferred stock), senior to the Series A Preferred Stock as to distribution rights or rights upon liquidation, winding up or dissolution. The subsequent issuance of additional shares of Series A Preferred Stock, or the creation and subsequent issuance of additional classes of preferred stock on parity with the Series A Preferred Stock, could dilute the interests of the holders of Series A Preferred Stock, and could affect our ability to pay distributions on, redeem or pay the liquidation preference on the Series A Preferred Stock. Any issuance of preferred stock that is senior to the Series A Preferred Stock would not only dilute the interests of the holders of Series A Preferred Stock, but also could affect our ability to pay distributions on, redeem or pay the liquidation preference on the Series A Preferred Stock.
Furthermore, subject to compliance with the Securities Act or exemptions therefrom, employees who have received Class A common stock as equity awards may also sell their shares into the public market.
We will be required to make payments under the Tax Receivable Agreement for certain tax benefits we may claim, and the amounts of such payments could be significant.
We are party to a Tax Receivable Agreement with Spark HoldCo, NuDevco Retail Holdings and NuDevco Retail. This agreement generally provides for the payment by us to Retailco, LLC (as successor to NuDevco Retail Holdings) and NuDevco Retail of
85%
of the net cash savings, if any, in U.S. federal, state and local income tax or franchise tax that we actually realize (or are deemed to realize in certain circumstances) in future periods as a result of (i) any tax basis increase resulting from the purchase by us of SparkHoldCo units from NuDevco Retail Holdings, (ii) any tax basis increases resulting from the exchange of Spark HoldCo units for shares of Class A common stock pursuant to the Exchange Right (or resulting from an exchange of Spark HoldCo units for cash pursuant to the Cash Option) and (iii) any imputed interest deemed to be paid by us as a result of, and additional tax basis arising from, any payments we make under the Tax Receivable Agreement. In addition, payments we make
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under the Tax Receivable Agreement will be increased by any interest accrued from the due date (without extensions) of the corresponding tax return. We retain the benefit of the remaining
15%
of these tax savings. See Note
12 "Income Taxes"
for further discussion.
Spark Energy, Inc. may be required to defer or partially defer any payment due to holders of rights under the Tax Receivable Agreement in certain circumstances during the five-year period commencing on October 1, 2014. Following the expiration of the five-year deferral period, Spark Energy, Inc. will be obligated to pay any outstanding deferred TRA Payments. While this payment obligation is subject to certain limitations, the obligation may nevertheless be significant and could adversely affect our liquidity and ability to pay dividends to the holders of our Class A common stock and Series A Preferred Stock.
The payment obligations under the Tax Receivable Agreement are our obligations and not obligations of Spark HoldCo. For purposes of the Tax Receivable Agreement, cash savings in tax generally are calculated by comparing our actual tax liability to the amount we would have been required to pay had we not been able to utilize any of the tax benefits subject to the Tax Receivable Agreement. The term of the Tax Receivable Agreement continues until all such tax benefits have been utilized or expired, unless we exercise our right to terminate the Tax Receivable Agreement by making the termination payment specified in the agreement.
The actual increase in tax basis, as well as the amount and timing of any payments under the Tax Receivable Agreement, will vary depending upon a number of factors, including the timing of the exchanges of Spark HoldCo units, the price of Class A common stock at the time of each exchange, the extent to which such exchanges are taxable, the amount and timing of the taxable income we generate in the future and the tax rate then applicable, and the portion of our payments under the Tax Receivable Agreement constituting imputed interest or depletable, depreciable or amortizable basis. We expect that the payments that we will be required to make under the Tax Receivable Agreement could be substantial.
The payments under the Tax Receivable Agreement will not be conditioned upon a holder of rights under the Tax Receivable Agreement having a continued ownership interest in either Spark HoldCo or us.
We did not meet the threshold coverage ratio required to fund the first payment to NuDevco Retail Holdings under the Tax Receivable Agreement during the four-quarter period ending September 30, 2015. As such, the initial payment under the Tax Receivable Agreement due in late 2015 was deferred pursuant to the terms thereof.
We met the threshold coverage ratio required to fund the second TRA Payment to Retailco and NuDevco Retail under the Tax Receivable Agreement during the four-quarter period ending September 30, 2016, resulting in an initial TRA Payment of
$1.4 million
becoming due in December 2016. On November 6, 2016, Retailco and NuDevco Retail granted us the right to defer the TRA Payment until May 2018. During the period of time when we have elected to defer the TRA Payment, the outstanding payment amount will accrue interest at a rate calculated in the manner provided for under the Tax Receivable Agreement.
We met the threshold coverage ratio required to fund the third TRA Payment to Retailco and NuDevco Retail under the Tax Receivable Agreement during the four-quarter period ended September 30, 2017. As such, the third payment under the Tax Receivable Agreement due in April 2018 has been classified as current in our consolidated balance sheet at December 31, 2017.
We expect to meet the threshold coverage ratio required to fund the fourth payment to Retailco and NuDevco Retail under the Tax Receivable Agreement during the four-quarter period ending September 30, 2018. The fourth payment under the Tax Receivable Agreement would be due in late 2018.
See also Note
14 "Transactions with Affiliates."
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In certain cases, payments under the Tax Receivable Agreement may be accelerated and/or significantly exceed the actual benefits, if any, we realize in respect of the tax attributes subject to the Tax Receivable Agreement.
If we elect to terminate the Tax Receivable Agreement early or it is terminated early due to certain mergers or other changes of control, we would be required to make an immediate payment equal to the present value of the anticipated future tax benefits subject to the Tax Receivable Agreement, which calculation of anticipated future tax benefits will be based upon certain assumptions and deemed events set forth in the Tax Receivable Agreement, including the assumption that we have sufficient taxable income to fully utilize such benefits and that any Spark HoldCo units that Retailco, LLC, NuDevco Retail, or their permitted transferees own on the termination date are deemed to be exchanged on the termination date. Any early termination payment may be made significantly in advance of the actual realization, if any, of such future benefits.
In these situations, our obligations under the Tax Receivable Agreement could have a substantial negative impact on our liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, other forms of business combinations or other changes of control due to the additional transaction cost a potential acquirer may attribute to satisfying such obligations. For example, if the Tax Receivable Agreement had been terminated as of
December 31, 2017
, the estimated contractual termination payment would be approximately
$52.4 million
(calculated using a discount rate equal to the one-year London Inter-Bank Offered Rate ("LIBOR"), plus
200
basis points). The foregoing number is merely an estimate and the actual payment could differ materially. There can be no assurance that we will be able to finance our obligations under the Tax Receivable Agreement.
Payments under the Tax Receivable Agreement will be based on the tax reporting positions that we will determine. The holders of rights under the Tax Receivable Agreement will not reimburse us for any payments previously made under the Tax Receivable Agreement if such basis increases or other benefits are subsequently disallowed, except that excess payments made to any such holder will be netted against payments otherwise to be made, if any, to such holder after our determination of such excess. As a result, in such circumstances, we could make payments that are greater than our actual cash tax savings, if any, and may not be able to recoup those payments, which could adversely affect our liquidity.
We have issued preferred stock and may continue to do so, and the terms of such preferred stock could adversely affect the voting power or value of our Class A common stock.
Our certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our Class A common stock respecting dividends and distributions, as our board of directors may determine. During the year ended December 31, 2017, we designated a class of preferred stock as Series A Preferred Stock and issued an aggregate of
94,339
shares of Series A Preferred Stock.
The terms of one or more classes or series of preferred stock we offer or sell could adversely impact the voting power or value of our Class A common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock, such as the Series A Preferred Stock, could affect the residual value of the Class A common stock.
For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements, including those relating to accounting standards and disclosure about our executive compensation, that apply to other public companies.
In April 2012, the Jumpstart Our Business Startups Act (the "JOBS Act") was signed into law. We are classified as an “emerging growth company” under the JOBS Act. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things, (i) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act, (ii) comply with any new
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requirements adopted by the PCAOB requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer, (iii) provide certain disclosure regarding executive compensation required of larger public companies or (iv) hold nonbinding advisory votes on executive compensation. We will remain an "emerging growth company" until as late as the last day of our 2019 fiscal year, or until the earliest of (i) the last day of the fiscal year in which we have
$1.07 billion
or more in annual revenues; (ii) the date on which we become a "large accelerated filer" (the fiscal year-end on which the total market value of our common equity securities held by non-affiliates is
$700 million
or more as of June 30); (iii) the date on which we issue more than $1.0 billion of non-convertible debt over a
three
-year period.
As a result of our election to avail ourselves of certain provisions of the JOBS Act, the information that we provide may be different than what you may receive from other public companies in which you hold an equity interest. To the extent that we rely on any of the exemptions available to emerging growth companies, you will receive less information about our executive compensation and internal control over financial reporting than issuers that are not emerging growth companies. If some investors find our securities to be less attractive as a result, there may be a less active trading market for our securities and the price may be more volatile.
Our amended and restated certificate of incorporation limits the fiduciary duties of one of our directors and certain of our affiliates and restricts the remedies available to our stockholders for actions taken by our Founder or certain of our affiliates that might otherwise constitute breaches of fiduciary duty.
Our amended and restated certificate of incorporation contains provisions that we renounce any interest in existing and future investments in other entities by, or the business opportunities of, NuDevco Partners, LLC, NuDevco Partners Holdings, LLC and W. Keith Maxwell III, or any of their officers, directors, agents, shareholders, members, affiliates and subsidiaries (other than a director or officer who is presented an opportunity solely in his capacity as a director or officer). Because of this provision, these persons and entities have no obligation to offer us those investments or opportunities that are offered to them in any capacity other than solely as an officer or director. If one of these persons or entities pursues a business opportunity instead of presenting the opportunity to us, we will not have any recourse against such person or entity for a breach of fiduciary duty.
The Series A Preferred Stock represent perpetual equity interests in us, and investors should not expect us to redeem the Series A Preferred Stock on the date the Series A Preferred Stock become redeemable by us or on any particular date afterwards.
The Series A Preferred Stock represent perpetual equity interests in us, and they have no maturity or mandatory redemption date and are not redeemable at the option of investors under any circumstances. As a result, unlike our indebtedness, the Series A Preferred Stock will not give rise to a claim for payment of a principal amount at a particular date. As a result, holders of the Series A Preferred Stock may be required to bear the financial risks of an investment in the Series A Preferred Stock for an indefinite period of time. In addition, the Series A Preferred Stock will rank junior to all our current and future indebtedness (including indebtedness outstanding under the Senior Credit Facility) and other liabilities. The Series A Preferred Stock will also rank junior to any other preferred stock ranking senior to the Series A Preferred Stock we may issue in the future with respect to assets available to satisfy claims against us.
The Series A Preferred Stock have not been rated.
We have not sought to obtain a rating for the Series A Preferred Stock, and the Series A Preferred Stock may never be rated. It is possible, however, that one or more rating agencies might independently determine to assign a rating to the Series A Preferred Stock or that we may elect to obtain a rating of the Series A Preferred Stock in the future. In addition, we may elect to issue other securities for which we may seek to obtain a rating. If any ratings are assigned to the Series A Preferred Stock in the future or if we issue other securities with a rating, such ratings, if they are lower than market expectations or are subsequently lowered or withdrawn, could adversely affect the market for or the market value of the Series A Preferred Stock. Ratings only reflect the views of the issuing rating agency or agencies and such ratings could at any time be revised downward or withdrawn entirely at the discretion
40
of the issuing rating agency. A rating is not a recommendation to purchase, sell or hold any particular security, including the Series A Preferred Stock. Ratings do not reflect market prices or suitability of a security for a particular investor and any future rating of the Series A Preferred Stock may not reflect all risks related to us and our business, or the structure or market value of the Series A Preferred Stock.
The Change of Control Conversion Right may make it more difficult for a party to acquire us or discourage a party from acquiring us.
The Change of Control Conversion Right of the Series A Preferred Stock provided in the Certificate of Designation may have the effect of discouraging a third party from making an acquisition proposal for us or of delaying, deferring or preventing certain of our change of control transactions under circumstances that otherwise could provide the holders of our Series A Preferred Stock with the opportunity to realize a premium over the then-current market price of such equity securities or that stockholders may otherwise believe is in their best interests.
If we are unable to redeem the Series A Preferred Stock on or after April 15, 2022, a substantial increase in the Three-Month LIBOR Rate could negatively impact our ability to pay dividends on the Series A Preferred Stock and Class A common stock.
If we do not repurchase or redeem our Series A Preferred Stock on or after April 15, 2022, a substantial increase in the Three-Month LIBOR Rate could negatively impact our ability to pay dividends on the Series A Preferred Stock. An increase in the dividends payable on our Series A Preferred Stock would negatively impact dividends on our and Class A common stock. We cannot assure you that we will have adequate sources of capital to repurchase or redeem the Series A Preferred Stock on or after April 15, 2022. If we are unable to repurchase or redeem the Series A Preferred Stock and our ability to pay dividends on the Series A Preferred Stock and Class A common stock is negatively impacted, the market value of the Series A Preferred Stock and Class A common stock could be materially adversely impacted.
We may not have sufficient earnings and profits in order for dividends on the Series A Preferred Stock to be treated as dividends for U.S. federal income tax purposes.
The dividends payable by us on the Series A Preferred Stock may exceed our current and accumulated earnings and profits, as calculated for U.S. federal income tax purposes. If that occurs, it will result in the amount of the dividends that exceed such earnings and profits being treated for U.S. federal income tax purposes first as a return of capital to the extent of the beneficial owner’s adjusted tax basis in the Series A Preferred Stock, and the excess, if any, over such adjusted tax basis as capital gain. Such treatment will generally be unfavorable for corporate beneficial owners and may also be unfavorable to certain other beneficial owners.
You may be subject to tax if we make or fail to make certain adjustments to the conversion rate of the Series A Preferred Stock even though you do not receive a corresponding cash dividend.
The Conversion Rate as defined in the Certificate of Designation for the Series A Preferred Stock is subject to adjustment in certain circumstances. A failure to adjust (or to adjust adequately) the Conversion Rate after an event that increases your proportionate interest in us could be treated as a deemed taxable dividend to you. If you are a non-U.S. holder, any deemed dividend may be subject to U.S. federal withholding tax at a 30% rate, or such lower rate as may be specified by an applicable treaty, which may be set off against subsequent payments on the Series A Preferred Stock. In April 2016, the Internal Revenue Service issued new proposed income tax regulations in regard to the taxability of changes in conversion rights that will apply to the Series A Preferred Stock when published in final form and may be applied to us before final publication in certain instances.
None.
41
We are the subject of lawsuits and claims arising in the ordinary course of business from time to time. Management cannot predict the ultimate outcome of such lawsuits and claims. While the lawsuits and claims are asserted for amounts that may be material, should an unfavorable outcome occur, management does not currently expect that any currently pending matters will have a material adverse effect on our financial position or results of operations except as described below. See Note
13 "Commitment and Contingencies"
to the audited consolidated financial statements, which are incorporated herein by reference to Part II, Item 8 “Financial Statements and Supplementary Data” of this Form 10-K.
The Company is the subject of the following lawsuits:
John Melville et al v. Spark Energy Inc. and Spark Energy Gas, LLC
is a purported class action filed on December 17, 2015 in the United States District Court for the District of New Jersey alleging, among other things, that (i) sales representatives engaged as independent contractors for Spark Energy Gas, LLC engaged in deceptive acts in violation of the New Jersey Consumer Fraud Act, and (ii) Spark Energy Gas, LLC breached its contract with plaintiff, including a breach of the covenant of good faith and fair dealing. On September 5, 2017, the parties reached a confidential settlement in this matter, which the Company expensed and paid in the fourth quarter of 2017.
Halifax-American Energy Company, LLC et al v. Provider Power, LLC, Electricity N.H., LLC, Electricity Maine, LLC, Emile Clavet and Kevin Dean
is a lawsuit initially filed on June 12, 2014, in the Rockingham County Superior Court, State of New Hampshire, alleging various claims related to the Provider Companies’ employment of a sales contractor formerly employed with one or more of the plaintiffs, including misappropriation of trade secrets and tortious interference with a contractual relationship. The relief sought included compensatory and punitive damages and attorney's fees. The dispute occurred prior to the Company's acquisition of the Provider Companies. Portions of the original claim proceeded to trial and on January 19, 2016, a jury found in favor of the plaintiffs. Damages totaling approximately
$0.6 million
and attorneys' fees totaling approximately
$0.3 million
were awarded to the plaintiffs. On May 4, 2016, following post-verdict motions, the defendants filed an appeal in the State of New Hampshire Supreme Court, appealing, among other things the failure of the trial court to direct a verdict for the defendants, to set aside the verdict, or grant judgment for the defendants, and the trial court's award of certain attorneys' fees. The appellate hearing was held on June 1, 2017. The New Hampshire Supreme Court decided the appeal on February 9, 2018, upholding the jury's verdict and the trial court's rulings in all respects. As of
December 31, 2017
, the Company has accrued approximately
$1.0 million
in contingent liabilities related to this litigation. Initial damages and attorneys' fees have been factored into the purchase price for the Provider Companies, and the Company believes it has full indemnity coverage for any actual exposure in this appeal.
Katherine Veilleux and Jennifer Chon, individually and on behalf of all other similarly situated v. Electricity Maine. LLC, Provider Power, LLC, Spark HoldCo, LLC, Kevin Dean and Emile Clavet
is a purported class action lawsuit filed on November 18, 2016 in the United States District Court of Maine, alleging that Electricity Maine, LLC, an entity acquired by Spark HoldCo, LLC in mid-2016, enrolled and re-enrolled customers through fraudulent and misleading advertising, promotions, and other communications prior to the acquisition. Plaintiffs further allege that some improper enrollment and re-enrollment practices have continued to the present date. Plaintiffs allege the following claims against all defendants: violation of the Maine Unfair Trade Practices Act, violation of RICO, negligence, negligent misrepresentation, fraudulent misrepresentation, unjust enrichment and breach of contract. Plaintiffs seek unspecified damages for themselves and the purported class, rescission of contracts with Electricity Maine, injunctive relief, restitution, and attorney’s fees. By order dated November 15, 2017, the Court, pursuant to Rule 12(b)(6), dismissed all claims against Spark HoldCo except the claims for violation of the Maine Unfair Trade Practices Act and for unjust enrichment. Discovery limited to issues relevant to class certification under Rule 23 of the Federal Rules of Civil Procedure has just begun. Spark HoldCo intends to vigorously defend this matter and the allegations asserted therein, including the request to certify a class. Given the early stages of this matter, we cannot predict the outcome or consequences of this case at this time. The Company believes it is fully indemnified for this litigation matter, subject to certain limitations.
42
Gillis et al. v. Respond Power, LLC
is a purported class action lawsuit that was originally filed on May 21, 2014 in the Philadelphia Court of Common Pleas. On June 23, 2014, the case was removed to the United States District Court for the Eastern District of Pennsylvania. On September 15, 2014, the plaintiffs filed an amended class action complaint seeking a declaratory judgment that the disclosure statement contained in Respond Power, LLC’s variable rate contracts with Pennsylvania consumers limited the variable rate that could be charged to no more than the monthly rate charged by the consumers’ local utility company. The plaintiffs also allege that Respond Power, LLC (i) breached its variable rate contract with Pennsylvania consumers, and the covenant of good faith and fair dealing therein, by charging rates in excess of the monthly rate charged by the consumers’ local utility company; (ii) engaged in deceptive conduct in violation of the Pennsylvania Unfair Trade Practices and Consumer Protection Law; and (iii) engaged in negligent misrepresentation and fraudulent concealment in connection with purported promises of savings. The amount of damages sought is not specified. By order dated August 31, 2015, the district court denied class certification. The plaintiffs appealed the district court’s denial of class certification to the United States Court of Appeals for the Third Circuit. The United States Court of Appeals for the Third Circuit vacated the district court’s denial of class certification and remanded the matter to the district court for further proceedings. The district court ordered briefing on defendant’s motion to dismiss. Respond Power LLC filed a motion to dismiss the plaintiffs’ declaratory judgment and breach of contract claims (the class claims) on June 30, 2017. The motion is fully briefed and submitted, and the parties are awaiting a decision from the Court. The Company currently cannot predict the outcome or consequences of this case at this time. The Company believes it is fully indemnified for this litigation matter, subject to certain limitations.
Jurich v. Verde Energy USA, Inc
., is a purported class action originally filed on March 3, 2015 in the United States District Court for the District of Connecticut and subsequently re-filed on October 8, 2015 in the Superior Court of Judicial District of Hartford, State of Connecticut. The Amended Complaint asserts that the Verde Companies charged rates in violation of its contracts with Connecticut customers and alleges (i) violation of the Connecticut Unfair Trade Practices Act and (ii) breach of the covenant of good faith and fair dealing. Plaintiffs are seeking unspecified actual and punitive damages for the purported class and injunctive relief. The parties have exchanged initial discovery. Plaintiffs’ motion for class certification was briefed and the Verde Companies filed its opposition to plaintiffs’ motion for class certification on October 17, 2017. On December 6, 2017, the Court granted the plaintiffs’ class certification motion. However, the Court opted not to send out class notices, and instead directed the parties to submit briefing on legal issues that could result in a modification or decertification of the class. The parties have proposed to the Court that initial briefing on such motions would be due March 16, 2018. As part of an agreement in connection with the acquisition of the Verde Companies, the original owners of the Verde Companies are handling this matter. Given the early stage of this matter, we cannot predict the outcome or consequences of this case at this time. The Company believes it is fully indemnified for this litigation matter by the original owners of the Verde Companies, subject to certain limitations.
Richardson et al v. Verde Energy USA, Inc.
is a purported class action filed on November 25, 2015 in the United States District Court for the Eastern District of Pennsylvania alleging that the Verde Companies violated the Telephone Consumer Protection Act by placing marketing calls using an automatic telephone dialing system or a prerecorded voice to the purported class members’ cellular phones without prior express consent and by continuing to make such calls after receiving requests for the calls to cease. Plaintiffs are seeking statutory damages for the purported class and injunctive relief prohibiting Verde Companies' alleged conduct. Discovery on the claims of the named plaintiffs closed on November 10, 2017, and dispositive motions on the named plaintiffs’ claims was filed on November 24, 2017. Plaintiffs’ response to dispositive motions’ pleadings was filed on December 22, 2017 and Verde Companies’ reply briefs were filed on January 5, 2018. To date, no hearing has been set on these motions. As part of an agreement in connection with the acquisition of the Verde Companies, the original owners of the Verde Companies is handling this matter. Given the early stages of this matter, we cannot predict the outcome or consequences of this case at this time. The Company believes it is fully indemnified for this litigation matter by the original owners of the Verde Companies, subject to certain limitations.
Coleman v. Verde Energy USA Illinois, LLC
is a purported class action filed on January 23, 2017 in the United States District Court for the Southern District of Illinois alleging that the Verde Companies violated the Telephone Consumer Protection Act by placing marketing calls using an automatic telephone dialing system or a prerecorded
43
voice to the purported class members’ cellular phones without prior express consent. The parties have reached a confidential settlement in this matter that was paid in the fourth quarter of 2017.
Saul Horowitz, as Sellers’ Representative for the former owners of the Major Energy Companies v. National Gas & Electric, LLC (NG&E) and Spark Energy, Inc. (Spark)
, has filed a lawsuit asserting claims of fraudulent inducement against NG&E, breach of contract against NG&E and the Company, and tortious interference with contract against the Company related to the membership interest purchase, subsequent transfer, and associated earnout agreements with the Major Energy Companies' former owners. The relief sought includes unspecified compensatory and punitive damages, prejudgment and post judgment interest, and attorneys’ fees. The lawsuit was filed on October 10, 2017 in the United States District Court for the Southern District of New York, and after the Company and NG&E filed a motion to dismiss, Horowitz filed an Amended Complaint, asserting the same four claims. The Company and NG&E filed a motion to dismiss the fraud and tortious interference claims on January 15, 2018. Briefing on the motion to dismiss concluded on March 1, 2018, and the Court's decision to rule or schedule oral argument is pending as of the date these financial statements are issued. The Company and NG&E deny the allegations asserted and intend to vigorously defend this matter. Given the early stages of this matter, we cannot predict the outcome or consequences of this case at this time.
Not applicable.
44
Our Class A common stock is traded on the NASDAQ Global Select Market under the symbol “SPKE." There is no public market for our Class B common stock. On
March 7, 2018
, the closing price of our stock was
$8.85
, and we had one holder of record of our Class A common stock and two holders of record of our Class B common stock, excluding stockholders for whom shares are held in “nominee” or “street name.” The following table presents the high and low sales prices as reported on the NASDAQ for the periods presented.
|
2017
|
2016
|
|||
|
Quarter Ended
|
Low
|
High
|
Low
|
High
|
|
March 31
|
$12.25
|
$16.83
|
$8.85
|
$13.81
|
|
June 30
|
$14.18
|
$23.65
|
$8.91
|
$17.82
|
|
September 30
|
$14.50
|
$21.40
|
$11.29
|
$17.35
|
|
December 31
|
$10.70
|
$15.30
|
$11.53
|
$16.23
|
Dividends
We intend to pay a cash dividend each quarter to holders of our Class A common stock to the extent we have cash available for distribution and are permitted to do so under the terms of our Senior Credit Facility. Below is a summary of dividends paid on our Class A common stock for
2017
and
2016
.
|
2017
|
|||
|
Per Share Amount
|
Record Date
|
Payment Date
|
|
|
First Quarter
|
$0.18125
|
3/1/2017
|
3/16/2017
|
|
Second Quarter
|
$0.18125
|
5/30/2017
|
6/14/2017
|
|
Third Quarter
|
$0.18125
|
8/29/2017
|
9/14/2017
|
|
Fourth Quarter
|
$0.18125
|
11/29/2017
|
12/14/2017
|
|
2016
|
|||
|
Per Share Amount
|
Record Date
|
Payment Date
|
|
|
First Quarter
|
$0.18125
|
2/29/2016
|
3/14/2016
|
|
Second Quarter
|
$0.18125
|
5/31/2016
|
6/14/2016
|
|
Third Quarter
|
$0.18125
|
8/29/2016
|
9/13/2016
|
|
Fourth Quarter
|
$0.18125
|
12/1/2016
|
12/14/2016
|
Please see "Management's Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources —Sources of Liquidity —Senior Credit Facility" for a description of certain terms of our Senior Credit Facility that may impact our ability to pay dividends.
Issuer Purchases of Equity Securities
45
|
Period
|
Total Number of Class A Common Stock Purchased
|
Average Price Paid Per Share of Class A Common Stock
|
Total Number of Shares of Class A Common Stock Purchased as Part of Publicly Announced Program
(1)
|
Approximate Dollar Value of Class A Common Stock That May Yet Be Purchased Under the Program
(in thousands) (1)
|
||||||
|
October 1, 2017 through October 31, 2017
|
$
|
48,112
|
|
|||||||
|
November 1, 2017 through November 30, 2017
|
$
|
48,112
|
|
|||||||
|
December 1, 2017 through December 31, 2017
(2)
|
10,000
|
|
$
|
12.28
|
|
10,000
|
|
$
|
47,989
|
|
|
Total
|
10,000
|
|
$
|
12.28
|
|
10,000
|
|
$
|
47,989
|
|
(1) On May 24, 2017, the Company announced that the Board of Directors authorized a share repurchase program of up to $50.0 million of Class A common stock through December 31, 2017. The share repurchase program expired on December 31, 2017.
(2) During December 2017, the Company acquired
10,000
shares of Class A common stock at a weighted-average price of
$12.28
for a total purchase price of
$0.1 million
(including fees, commissions and expenses). The number of shares of Class A common stock purchased reflects trades that were settled in December 2017.
Recent Sales of Unregistered Equity Securities
We have not sold any unregistered equity securities since our IPO other than as previously reported.
Stock Performance Graph
The following graph compares, since the IPO, the quarterly performance of our Class A common stock to the NASDAQ Composite Index (NASDAQ Composite) and the Dow Jones U.S. Utilities Index (IDU). The chart assumes that the value of the investment in our Class A common stock and each index was $100 at July 29, 2014 (the date our Class A common stock began trading on the NASDAQ Global Select Market), and that all dividends were reinvested. The stock performance shown on the graph below is not indicative of future price performance.
46
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.
47
The following table sets forth selected historical financial information for each of the years in the five year period ended
December 31, 2017
.
This information is derived from our consolidated financial statements and should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Financial Statements and Supplementary Data."
|
(in thousands, except per share and volumetric data)
|
|
Year Ended December 31,
|
||||||||||||||||
|
|
2017
|
|
2016
|
|
2015
|
2014
|
2013
|
|||||||||||
|
Statement of Operations Data:
|
|
|
|
|
|
|
||||||||||||
|
Total Revenues
|
|
$
|
798,055
|
|
|
$
|
546,697
|
|
|
$
|
358,153
|
|
$
|
322,876
|
|
$
|
317,090
|
|
|
Operating income
|
|
102,420
|
|
|
84,001
|
|
|
29,905
|
|
(3,841
|
)
|
32,829
|
|
|||||
|
Net income
|
|
76,281
|
|
|
65,673
|
|
|
25,975
|
|
(4,265
|
)
|
31,412
|
|
|||||
|
Net Income (Loss) Attributable to Non-Controlling Interests
|
|
57,427
|
|
|
51,229
|
|
|
22,110
|
|
(4,211
|
)
|
—
|
|
|||||
|
Net income attributable to Spark Energy, Inc. stockholders
|
|
18,854
|
|
|
14,444
|
|
|
3,865
|
|
(54
|
)
|
31,412
|
|
|||||
|
Net income attributable to stockholders of Class A common stock
|
15,816
|
|
14,444
|
|
3,865
|
|
(54
|
)
|
31,412
|
|
||||||||
|
|
|
|
|
|
|
|
||||||||||||
|
Net income (loss) attributable to Spark Energy, Inc. per share of Class A common stock
|
|
|
|
|
|
|||||||||||||
|
Basic
|
|
$
|
1.20
|
|
|
$
|
1.27
|
|
|
$
|
0.63
|
|
$
|
(0.01
|
)
|
N/A
(1)
|
|
|
|
Diluted
|
|
$
|
1.19
|
|
|
$
|
1.11
|
|
|
$
|
0.53
|
|
$
|
(0.01
|
)
|
N/A
(1)
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
|
Weighted average common shares outstanding
|
|
|
|
|
|
|
|
|
|
|
||||||||
|
Basic
|
|
13,143
|
|
|
11,402
|
|
|
6,129
|
|
6,000
|
|
N/A
(1)
|
|
|||||
|
Diluted
|
|
13,346
|
|
|
12,690
|
|
|
6,655
|
|
6,000
|
|
N/A
(1)
|
|
|||||
|
|
|
|
|
|
|
|
||||||||||||
|
Balance Sheet Data:
|
|
|
|
|
|
|
||||||||||||
|
Current assets
|
|
$
|
296,738
|
|
|
$
|
197,983
|
|
|
$
|
102,680
|
|
$
|
105,989
|
|
$
|
101,291
|
|
|
Current liabilities
|
|
$
|
151,027
|
|
|
$
|
184,056
|
|
|
$
|
84,188
|
|
$
|
92,816
|
|
$
|
73,142
|
|
|
Total assets
|
|
$
|
505,949
|
|
|
$
|
375,230
|
|
|
$
|
162,234
|
|
$
|
138,397
|
|
$
|
109,073
|
|
|
Long-term liabilities
|
|
$
|
152,446
|
|
|
$
|
67,438
|
|
|
$
|
44,727
|
|
$
|
21,463
|
|
$
|
18
|
|
|
Cash Flow Data:
|
|
|
|
|
|
|
||||||||||||
|
Cash flows from operating activities
|
|
$
|
63,912
|
|
|
$
|
67,793
|
|
|
$
|
45,931
|
|
$
|
5,874
|
|
$
|
44,480
|
|
|
Cash flows used in investing activities
|
|
$
|
(97,757
|
)
|
|
$
|
(36,344
|
)
|
|
$
|
(41,943
|
)
|
$
|
(3,040
|
)
|
$
|
(1,481
|
)
|
|
Cash flows provided by (used in) financing activities
|
|
$
|
44,304
|
|
|
$
|
(16,963
|
)
|
|
$
|
(3,873
|
)
|
$
|
(5,664
|
)
|
$
|
(42,369
|
)
|
|
|
|
|
|
|
|
|
||||||||||||
|
Other Financial Data:
|
|
|
|
|
|
|
||||||||||||
|
Adjusted EBITDA
(2)
|
|
$
|
102,884
|
|
|
$
|
81,892
|
|
|
$
|
36,869
|
|
$
|
11,324
|
|
$
|
33,533
|
|
|
Retail gross margin
(2)
|
|
$
|
224,509
|
|
|
$
|
182,369
|
|
|
$
|
113,615
|
|
$
|
76,944
|
|
$
|
81,668
|
|
|
Distributions paid to Class B non-controlling unit holders and dividends paid to Class A common shareholders
|
|
$
|
(43,319
|
)
|
|
$
|
(43,297
|
)
|
|
$
|
(20,043
|
)
|
$
|
(3,305
|
)
|
$
|
—
|
|
|
Other Operating Data:
|
|
|
|
|
|
|||||||||||||
|
RCEs (thousands)
|
|
1,042
|
|
|
774
|
|
|
415
|
|
326
|
|
310
|
|
|||||
|
Electricity volumes (MWh)
|
|
6,755,663
|
|
|
4,170,593
|
|
|
2,075,479
|
|
1,526,652
|
|
1,829,657
|
|
|||||
|
Natural gas volumes (MMBtu)
|
|
18,203,684
|
|
|
16,819,713
|
|
|
14,786,681
|
|
15,724,708
|
|
16,598,751
|
|
|||||
(1) EPS and other per share data is not meaningful prior to the Company's IPO, effective August 1, 2014, as the Company operated under a sole-member ownership structure.
(2) Adjusted EBITDA and retail gross margin are non-GAAP financial measures. For a definition and reconciliation of each of Adjusted EBITDA and retail gross margin to their most directly comparable financial measures calculated and presented in accordance with GAAP, please see “Management's Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate Our Operations."
48
AND RESULTS OF OPERATIONS
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the consolidated financial statements and the related notes thereto included elsewhere in this Annual Report. In this Annual Report, the terms “Spark Energy,” “Company,” “we,” “us” and “our” refer collectively to Spark Energy, Inc. and its subsidiaries.
Overview
We are a growing independent retail energy services company founded in 1999 that provides residential and commercial customers in competitive markets across the United States with an alternative choice for their natural gas and electricity. We purchase our natural gas and electricity supply from a variety of wholesale providers and bill our customers monthly for the delivery of natural gas and electricity based on their consumption at either a fixed or variable-price. Natural gas and electricity are then distributed to our customers by local regulated utility companies through their existing infrastructure. As of
December 31, 2017
, we operated in
94
utility service territories across
19
states and the District of Columbia.
Our business consists of two operating segments:
|
•
|
Retail Electricity Segment
. We purchase electricity supply through physical and financial transactions with market counterparts and ISOs and supply electricity to residential and commercial consumers pursuant to fixed-price and variable-price contracts. For the years ended
December 31, 2017
,
2016
and
2015
, approximately
82%
,
76%
and
64%
, respectively, of our retail revenues were derived from the sale of electricity.
|
|
•
|
Retail Natural Gas Segment
. We purchase natural gas supply through physical and financial transactions with market counterparts and supply natural gas to residential and commercial consumers pursuant to fixed-price and variable-price contracts. For the years ended
December 31, 2017
,
2016
and
2015
, approximately
18%
,
24%
and
36%
, respectively, of our retail revenues were derived from the sale of natural gas. We also identify wholesale natural gas arbitrage opportunities in conjunction with our retail procurement and hedging activities, which we refer to as asset optimization.
|
Recent Developments
Acquisition of HIKO
On March 1, 2018, we entered into a Membership Interest Purchase Agreement pursuant to which we acquired all of the issued and outstanding membership interests of HIKO Energy, LLC, a New York limited liability company, for a total purchase price of
$6.0 million
in cash, plus working capital. HIKO Energy, LLC has a total of approximately
29,000
RCEs located in
42
markets in
7
states.
Acquisition of Customers from NG&E
On March 7, 2018, we entered into an asset purchase agreement with NG&E pursuant to which we will acquire approximately
50,000
RCEs from NG&E for a cash purchase price of
$250
for each RCE, or approximately
$12.5 million
in the aggregate. These customers are expected to begin transferring after April 1, 2018 and are located in
24
markets in
8
states. Please see “Item 9B—Other Information—Acquisition of Customers from NG&E” for a more detailed description.
Termination of Master Service Agreement
49
On March 7, 2018, we, Retailco Services and NuDevco Retail mutually agreed to terminate the Master Services Agreement, effective April 1, 2018. We believe that Retailco Services was able to recognize cost savings and stabilize operating costs related to the operational support services in 2016 and 2017. Under the terms of the termination agreement, operational support services will be transferred back to the Company, which may allow us to extract further savings by eliminating overhead attributable to managing and accounting for Retailco Services as a stand-alone business. Please see “Item 9B—Other Information—Termination of Master Service Agreement” for a more detailed description.
Series A Preferred Stock Offering
On
January 26, 2018
, we issued
2,000,000
shares of Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Stock ("Series A Preferred Stock") and received net proceeds from the offering of approximately
$48.9 million
(net of underwriting discounts, commissions and a structuring fee).
Termination of Verde Earnout
On January 12, 2018, we entered into an Agreement to Terminate Earnout Payments (the “Earnout Termination Agreement”) that terminated our obligation to make any required earnout payments under the agreement for our acquisition of the Verde Companies. Under the Earnout Termination Agreement, we issued a new promissory note to the prior owner of the Verde Companies in the amount of $5.9 million and amended the promissory note entered into at the closing of our acquisition of the Verde Companies to increase the interest rate. Please see “—Liquidity and Capital Resources—Verde Earnout Termination Notes.”
Expansion of Credit Facility
On January 11, 2018 and January 23, 2018, we exercised the accordion feature in the Senior Credit Facility, which when combined with prior exercises in 2017, increased the total commitments under the Senior Credit Facility from
$150.0 million
to
$200.0 million
. Please see “—Liquidity and Capital Resources—Senior Credit Facility.”
Residential Customer Equivalents
The following table shows our
residential customer equivalents ("RCEs")
as of
December 31, 2017
,
2016
and
2015
:
|
RCEs:
|
||||||
|
December 31,
|
December 31,
|
|||||
|
(In thousands)
|
2017
|
2016
|
% Increase (Decrease)
|
2016
|
2015
|
% Increase (Decrease)
|
|
Retail Electricity
|
868
|
571
|
52%
|
571
|
257
|
122%
|
|
Retail Natural Gas
|
174
|
203
|
(14)%
|
203
|
158
|
28%
|
|
Total Retail
|
1,042
|
774
|
35%
|
774
|
415
|
87%
|
The following table details our count of RCEs by geographical location as of
December 31, 2017
:
|
RCEs by Geographic Location:
|
||||||
|
(In thousands)
|
Electricity
|
% of Total
|
Natural Gas
|
% of Total
|
Total
|
% of Total
|
|
New England
|
394
|
46%
|
32
|
18%
|
426
|
41%
|
|
Mid-Atlantic
|
324
|
37%
|
72
|
42%
|
396
|
38%
|
|
Midwest
|
70
|
8%
|
45
|
26%
|
115
|
11%
|
|
Southwest
|
80
|
9%
|
25
|
14%
|
105
|
10%
|
|
Total
|
868
|
100%
|
174
|
100%
|
1,042
|
100%
|
50
The geographical regions noted above include the following states:
|
•
|
New England - Connecticut, Maine, Massachusetts, New Hampshire;
|
|
•
|
Mid-Atlantic - Delaware, Maryland (including the District of Columbia), New Jersey, New York and Pennsylvania;
|
|
•
|
Midwest - Illinois, Indiana, Michigan and Ohio; and
|
|
•
|
Southwest - Arizona, California, Colorado, Nevada, Texas and Florida.
|
Drivers of Our Business
Customer Growth
Customer growth is a key driver of our operations. Our customer growth strategy includes acquiring customers through acquisitions as well as organically.
Organic Growth
Our organic sales strategies are used to both maintain and grow our customer base by offering competitive pricing, price certainty, and/or green product offerings. We manage growth on a market-by-market basis by developing price curves in each of the markets we serve and comparing the market prices to the price the local regulated utility is offering. We then determine if there is an opportunity in a particular market based on our ability to create a competitive product on economic terms that satisfies our profitability objectives and provides customer value. We develop marketing campaigns using a combination of sales channels, with an emphasis on door-to-door marketing and outbound telemarketing given their flexibility and historical effectiveness. We identify and acquire customers through a variety of additional sales channels, including our inbound customer care call center, online marketing, email, direct mail, affinity programs, direct sales, brokers and consultants. Our marketing team continuously evaluates the effectiveness of each customer acquisition channel and makes adjustments in order to achieve desired growth and profitability targets.
In 2017, we emphasized growing our commercial and industrial (“C&I”) customer base. After significant growth in our C&I customer count in 2017, management is rebalancing our mix of customers in the first part of 2018 to focus on higher margin residential customers.
We believe we can continue to grow organically, however achieving significant organic growth rates has become increasingly more difficult given our size, much of which is attributable to recent acquisitions. Additionally, increasing regulatory pressure on marketing channels such as door-to-door and outbound telemarketing and the ability to manage customer acquisition costs are significant factors in our ability to grow organically.
Acquisitions
We independently acquire companies and portfolios of companies through some combination of cash, borrowings under the Senior Credit Facility, the issuance of common or preferred stock or other financing arrangements with our Founder and his affiliates. Additionally, our Founder formed National Gas & Electric, LLC, an affiliate of the Company ("NG&E"), in 2015 for the purpose of purchasing retail energy companies and retail customer books that could ultimately be resold to us. We currently expect that we would fund any future transaction with NG&E using some combination of cash, subordinated debt, or the issuance of Class A common stock or Class B common stock (and corresponding Spark HoldCo units) to NG&E. However, actual consideration will depend, among other things, on our capital structure and liquidity at the time of any transaction. There is no guarantee that NG&E will continue to offer us acquisition opportunities. Additionally, as we grow and our access to capital and opportunities improves, we may rely less upon NG&E as a source of acquisitions and seek to enter into more transactions directly with third parties. See “Business and Properties—Relationship with our Founder and Majority Shareholder” for further discussion.
51
Please see “—Recent Developments—Acquisition of HIKO” and “—Recent Developments—Acquisition of Customers from NG&E” for a description of our recent acquisitions of HIKO Energy, LLC and additional customers from NG&E. For a summary of other historical acquisitions, including those with our Founder and NG&E, please see “Business and Properties—Customer Acquisition and Retention—Acquisitions.”
We are actively monitoring acquisition opportunities that may arise in the domestic acquisition market as smaller retailers face difficulties in managing risk and liquidity issues caused by the recent extreme weather patterns.
Our ability to grow at historic levels may be constrained if the market for acquisition candidates is limited and we are unable to make acquisitions of portfolios of customers and retail energy companies on commercially reasonable terms.
Integration of Acquisitions
Effective integration of our acquisitions is a key driver of our business. We integrated both CenStar and Oasis and began recognizing synergies in 2015. We were able to integrate the Provider Companies and begin recognizing synergies in 2016. The integration of the Perigee acquisition is progressing well and synergies are being recognized as of December 31, 2017. As the Major Energy Companies Earnout extends over multiple years, the Company is not able to achieve full synergies at this time. We were able to terminate the earnout related to our acquisition of the Verde Companies, allowing us to begin integrating the Verde Companies in early 2018. See “—Recent Developments” above. For a summary of historical acquisitions, please see “Business and Properties—Customer Acquisition and Retention—Acquisitions.”
RCE Activity
The following table shows our RCE activity during the years ended
December 31, 2017
,
2016
and
2015
.
|
(In thousands)
|
Retail Electricity
|
Retail Natural Gas
|
Total
|
% Annual Increase (Decrease)
|
|
December 31, 2014
|
157
|
169
|
326
|
|
|
Additions
(1)
|
208
|
100
|
308
|
|
|
Attrition
|
(108)
|
(111)
|
(219)
|
|
|
December 31, 2015
|
257
|
158
|
415
|
27%
|
|
Additions
(2)
|
550
|
131
|
681
|
|
|
Attrition
|
(236)
|
(86)
|
(322)
|
|
|
December 31, 2016
|
571
|
203
|
774
|
87%
|
|
Additions
(3)
|
659
|
61
|
720
|
|
|
Attrition
|
(362)
|
(90)
|
(452)
|
|
|
December 31, 2017
|
868
|
174
|
1,042
|
35%
|
(1) Includes
40,000
RCEs from the acquisition of Oasis and
65,000
RCEs from the acquisition of CenStar.
(2) Includes
121,000
RCEs from the acquisition of Provider Companies and
220,000
RCEs from the acquisition of Major Energy Companies.
(3) Includes approximately
17,000
RCEs from the acquisition of Perigee and
145,000
RCEs from the acquisition of the Verde Companies.
Our
35%
net RCE growth in 2017 reflects our acquisition of Verde Companies and Perigee, which added approximately
162,000
RCEs, or
21%
net growth. The remaining
14%
net RCE growth in 2017 was the result of organic additions and customer portfolio acquisitions.
Our
87%
net RCE growth in
2016
reflects our acquisitions of Major and Provider, which added approximately 341,000 RCEs, or 82% net growth. The remaining 5% net RCE growth in 2016 was the result of organic additions.
52
Our
27%
net RCE growth in
2015
reflects our acquisitions of CenStar and Oasis, which resulted in an increase in the overall size of individual customers. This growth was partially offset by the slowing of organic additions as we shifted our focus to acquisitions and renegotiated our mass market vendor commission structure in the third quarter of 2015, which correlated commission payments with customer value. These efforts had the effect of resetting our vendor relationships, which in turn slowed organic growth as vendors adapted to the new structure.
Customer Acquisition Costs Incurred
|
|
|||||||||
|
(In thousands)
|
2017
|
2016
|
2015
|
||||||
|
Customer Acquisition Costs Incurred
|
$
|
25,874
|
|
$
|
24,934
|
|
$
|
19,869
|
|
Management of customer acquisition costs is a key component to our profitability. Customer acquisition costs are spending for organic customer acquisitions and does not include customer acquisitions through acquisitions of businesses or portfolios of customer contracts, which are recorded as customer relationships.
We attempt to maintain a disciplined approach to recovery of our customer acquisition costs within defined periods. We capitalize and amortize our customer acquisition costs over a two year period, which is based on the expected average length of a customer relationship. We factor in the recovery of customer acquisition costs in determining which markets we enter and the pricing of our products in those markets. Accordingly, our results are significantly influenced by our customer acquisition spending.
Customer acquisition costs incurred for the year ended
December 31, 2017
was approximately
$25.9 million
, inclusive of costs attributable to Perigee and the Verde Companies incurred subsequent to their respective acquisition dates.
Customer acquisition costs incurred for the year ended
December 31, 2016
was approximately
$24.9 million
, inclusive of costs attributable to the Provider Companies and Major Energy Companies incurred subsequent to their respective acquisition dates. During the first half of 2016, we reduced the amount we spent on organic customer acquisition costs in order to maintain, rather than grow, our current level of RCEs, and shifted our resources to acquiring companies and entire books of customers. During the second half of 2016, we increased our spending on organic customer acquisitions as we refocused on organic growth.
Our customer acquisition spending in the second half of
2015
slowed, resulting in customer acquisition costs of
$19.9 million
in 2015 as we shifted our focus to acquisitions and due to changes to our residential vendor commission payment structure to better align them with lifetime customer value.
Our Ability to Manage Customer Attrition
|
|
|||
|
Attrition on RCE basis
|
|||||
|
Year Ended
|
Quarter Ended
|
||||
|
December 31
|
December 31
|
September 30
|
June 30
|
March 31
|
|
|
2015
|
5.1%
|
4.5%
|
5.0%
|
5.2%
|
5.7%
|
|
2016
|
4.3%
|
4.8%
|
3.8%
|
4.1%
|
4.4%
|
|
2017
|
4.3%
|
4.9%
|
4.2%
|
4.1%
|
3.8%
|
Customer attrition is primarily due to: (i) customer initiated switches; (ii) residential moves and (iii) disconnection for customer payment defaults.
Customer attrition during the year ended
December 31, 2017
was in line with the previous year as we continued our focus on the acquisition of higher lifetime value customers. We also continued our customer win-back efforts, and
53
more aggressively pursued proactive renewals and other customer relationship strategies to maintain a low level of customer attrition.
Customer Credit Risk
|
Year Ended December 31
|
||||||
|
2017
|
2016
|
2015
|
||||
|
Total Non-POR Bad Debt as Percent of Revenue
|
2.5
|
%
|
0.6
|
%
|
5.0
|
%
|
During the year ended December 31, 2017, we experienced increased bad debt expense due to Hurricane Harvey.
An increased focus on collection efforts and timely billing along with tighter credit requirements for new enrollments in non-POR markets have led to a reduction in the bad debt expense in 2016 as compared to 2015. We have also been able to collect on debt that we had previously written off, which further reduced our bad debt expense during 2016.
Bad debt expense as a percentage of non-POR market retail revenues remained high in 2015 due to the negative impact of higher attrition in the Midwest natural gas markets and continued disconnections for non-payment from our Southern California portfolio, where we stopped selling in January 2015. In early 2016, we introduced upfront credit screening to many of our natural gas sales campaigns in order to proactively identify potential at-risk customers.
For the years ended
December 31, 2017
,
2016
and
2015
, approximately
66%
,
67%
and
56%
, respectively, of our retail revenues were derived from territories in which substantially all of our credit risk was directly linked to local regulated utility companies. As of
December 31, 2017
,
2016
and
2015
, respectively, all of these local regulated utility companies had investment grade ratings. During the same periods, we paid these local regulated utilities a weighted average discount of approximately
1.1%
,
1.3%
and
1.4%
, respectively, of total revenues for customer credit risk protection, respectively.
Weather Conditions
Weather conditions directly influence the demand for natural gas and electricity and affect the prices of energy commodities. Our hedging strategy is based on forecasted customer energy usage, which can vary substantially as a result of weather patterns deviating from historical norms. We are particularly sensitive to this variability because of our current substantial concentration and focus on growth in the residential customer segment in which energy usage is highly sensitive to weather conditions that impact heating and cooling demand. In the first three quarters of 2017, we experienced milder than anticipated weather conditions, which negatively impacted overall customer usage, but allowed us to optimize our costs of revenues as commodity prices fell. In the third quarter of 2017, Hurricane Harvey caused historic flooding, extensive damage and widespread power outages across the Gulf Coast of Texas. Although we did not suffer physical damage to our Houston offices, the hurricane negatively impacted our ability to serve our customers and deliver electricity in this region during the hurricane and for the following weeks. We recorded losses of approximately $0.7 million for the year ended December 31, 2017, directly attributable to Hurricane Harvey, primarily related to bad debt expense.
In late 2017 and early 2018, the Northeastern and Great Lake regions experienced extreme weather patterns. We expect excessive customer usage from this cold weather may negatively impact our results of operations.
In the first half of 2016, we experienced milder than anticipated weather conditions, which negatively impacted overall customer usage, but allowed us to optimize our costs of revenues as commodity prices fell. In the second half of 2016, we experienced marginally warmer than normal weather conditions.
54
In the early part of 2015, colder than anticipated weather increased volumes and thus positively impacted our first quarter earnings. Warmer than normal weather in the fourth quarter of 2015 in the Northeast negatively impacted natural gas volumes, while we also optimized our costs of revenues as commodity prices fell.
Asset Optimization
Our natural gas business includes opportunistic transactions in the natural gas wholesale marketplace in conjunction with our retail procurement and hedging activities. Asset optimization opportunities primarily arise during the winter heating season when demand for natural gas is the highest. As such, the majority of our asset optimization profits are made in the winter. Given the opportunistic nature of these activities we experience variability in our earnings from our asset optimization activities from year to year. As these activities are accounted for using mark-to-market accounting, the timing of our revenue recognition often differs from the actual cash settlement.
During each of the years ended
December 31, 2017
and
2016
, we were obligated to pay demand charges of approximately
$2.6 million
under certain long-term legacy transportation assets that our predecessor entity acquired prior to 2013. Although these demand payments will decrease over time, a portion of the related capacity agreements extend through 2028. Net asset optimization results were a loss of
$0.7 million
, a loss of
$0.6 million
and a gain of
$1.5 million
for the year ended
December 31, 2017
,
2016
and
2015
, respectively.
55
Factors Affecting Comparability of Historical Financial Results
Tax Receivable Agreement.
We entered into the Tax Receivable Agreement between us and Spark Holdco, NuDevco Retail Holdings and NuDevco Retail concurrently with the IPO, which provides for the payment by us to Retailco, LLC (as successor to NuDevco Retail Holdings) and NuDevco Retail of
85%
of the net cash savings, if any, in U.S. federal, state and local income tax or franchise tax that we actually realize (or are deemed to realize in certain circumstances) in future periods as a result of certain events. On December 22, 2017, the President signed the Tax Cuts and Jobs Act (“U.S. Tax Reform”), which enacts a wide range of changes to the U.S. Corporate income tax system, including a reduction in the U.S. corporate tax rate to 21% effective in 2018. The revised corporate income tax rate reduces the amount of net cash savings to be realized in future periods. Therefore, we have reduced the Tax Receivable Agreement liability ("TRA liability") as of December 31, 2017 by $22.3 million to reflect the effect of the U.S. Tax Reform and recorded this adjustment through Other Income. In addition, payments we make under the Tax Receivable Agreement are increased by any interest accrued from the due date (without extensions) of the corresponding tax return. We have recorded
85%
of the estimated tax benefit as an increase to amounts payable under the Tax Receivable Agreement as a liability. We retain the benefit of the remaining
15%
of these tax savings. As a result of new federal tax laws going into effect in 2018, the Company has re-valued its deferred tax asset and deferred tax liability relating to the Tax Receivable Agreement on its balance sheet as of December 31, 2017. The effect of these downward adjustments is a net increase in income tax expense for the year ended December 31, 2017. See Note
12 "Income Taxes"
for further discussion.
Executive Compensation Programs.
Periodically the Company grants restricted stock units to our officers, employees, non-employee directors and certain employees of our affiliates who perform services for the Company. The restricted stock unit awards vest over approximately one year for non-employee directors and ratably over approximately three or four years for officers, employees and employees of affiliates, with the initial vesting date occurring in May of the subsequent year, and include tandem dividend equivalent rights that will vest upon the same schedule as the underlying restricted stock unit.
Financing
. We are party to the Senior Credit Facility. Historical borrowings under the Senior Credit Facility may not provide an accurate indication of what we need to operate our natural gas and electricity business. For a description of our current Senior Credit Facility, please see "—Liquidity and Capital Resources—Sources of Liquidity."
How We Evaluate Our Operations
|
|
Year Ended December 31,
|
||||||||||
|
(in thousands)
|
2017
|
2016
|
2015
|
||||||||
|
Adjusted EBITDA
|
$
|
102,884
|
|
$
|
81,892
|
|
$
|
36,869
|
|
||
|
Retail Gross Margin
|
$
|
224,509
|
|
$
|
182,369
|
|
$
|
113,615
|
|
||
Adjusted EBITDA
. We define “Adjusted EBITDA” as EBITDA less (i) customer acquisition costs incurred in the current period, (ii) net gain (loss) on derivative instruments, and (iii) net current period cash settlements on derivative instruments, plus (iv) non-cash compensation expense, and (v) other non-cash and non-recurring operating items. EBITDA is defined as net income (loss) before provision for income taxes, interest expense and depreciation and amortization.
We deduct all current period customer acquisition costs (representing spending for organic customer acquisitions) in the Adjusted EBITDA calculation because such costs reflect a cash outlay in the year in which they are incurred, even though we capitalize such costs and amortize them over two years in accordance with our accounting policies. The deduction of current period customer acquisition costs is consistent with how we manage our business, but the comparability of Adjusted EBITDA between periods may be affected by varying levels of customer acquisition costs. For example, our Adjusted EBITDA is lower in periods of organic customer growth reflecting larger customer acquisition spending.
56
We do not deduct the cost of customer acquisitions through acquisitions of businesses or portfolios of customers in calculating Adjusted EBITDA.
We deduct our net gains (losses) on derivative instruments, excluding current period cash settlements, from the Adjusted EBITDA calculation in order to remove the non-cash impact of net gains and losses on derivative instruments. We also deduct non-cash compensation expense as a result of restricted stock units that are issued under our long-term incentive plan.
We believe that the presentation of Adjusted EBITDA provides information useful to investors in assessing our liquidity and financial condition and results of operations and that Adjusted EBITDA is also useful to investors as a financial indicator of our ability to incur and service debt, pay dividends and fund capital expenditures. Adjusted EBITDA is a supplemental financial measure that management and external users of our consolidated financial statements, such as industry analysts, investors, commercial banks and rating agencies, use to assess the following:
|
•
|
our operating performance as compared to other publicly traded companies in the retail energy industry, without regard to financing methods, capital structure or historical cost basis;
|
|
•
|
the ability of our assets to generate earnings sufficient to support our proposed cash dividends; and
|
|
•
|
our ability to fund capital expenditures (including customer acquisition costs) and incur and service debt.
|
Retail Gross Margin.
We define retail gross margin as operating income plus (i) depreciation and amortization expenses and (ii) general and administrative expenses, less (iii) net asset optimization revenues, (iv) net gains (losses) on non-trading derivative instruments, and (v) net current period cash settlements on non-trading derivative instruments. Retail gross margin is included as a supplemental disclosure because it is a primary performance measure used by our management to determine the performance of our retail natural gas and electricity business by removing the impacts of our asset optimization activities and net non-cash income (loss) impact of our economic hedging activities. As an indicator of our retail energy business’ operating performance, retail gross margin should not be considered an alternative to, or more meaningful than, operating income, its most directly comparable financial measure calculated and presented in accordance with GAAP.
We believe retail gross margin provides information useful to investors as an indicator of our retail energy business's operating performance.
The GAAP measures most directly comparable to Adjusted EBITDA are net income and net cash provided by operating activities. The GAAP measure most directly comparable to Retail Gross Margin is operating income (loss). Our non-GAAP financial measures of Adjusted EBITDA and Retail Gross Margin should not be considered as alternatives to net income (loss), net cash provided by operating activities, or operating income (loss). Adjusted EBITDA and Retail Gross Margin are not presentations made in accordance with GAAP and have important limitations as analytical tools. You should not consider Adjusted EBITDA or Retail Gross Margin in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA and Retail Gross Margin exclude some, but not all, items that affect net income (loss), net cash provided by operating activities, and operating income (loss), and are defined differently by different companies in our industry, our definition of Adjusted EBITDA and Retail Gross Margin may not be comparable to similarly titled measures of other companies.
Management compensates for the limitations of Adjusted EBITDA and Retail Gross Margin as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these data points into management’s decision-making process.
The following table presents a reconciliation of Adjusted EBITDA to net income for each of the periods indicated.
57
|
|
Year Ended December 31,
|
||||||||||
|
(in thousands)
|
2017
|
2016
|
2015
|
||||||||
|
Reconciliation of Adjusted EBITDA to Net Income:
|
|||||||||||
|
Net income
|
$
|
76,281
|
|
|
$
|
65,673
|
|
$
|
25,975
|
|
|
|
Depreciation and amortization
|
42,341
|
|
|
32,788
|
|
25,378
|
|
||||
|
Interest expense
|
11,134
|
|
|
8,859
|
|
2,280
|
|
||||
|
Income tax expense
|
37,528
|
|
|
10,426
|
|
1,974
|
|
||||
|
EBITDA
(1)
|
167,284
|
|
|
117,746
|
|
55,607
|
|
||||
|
Less:
|
|
|
|
|
|||||||
|
Net, Gains (losses) on derivative instruments
|
5,008
|
|
|
22,407
|
|
(18,497
|
)
|
||||
|
Net, Cash settlements on derivative instruments
|
16,309
|
|
|
(2,146
|
)
|
20,547
|
|
||||
|
Customer acquisition costs
|
25,874
|
|
|
24,934
|
|
19,869
|
|
||||
|
Plus:
|
|
|
|
|
|
|
|
||||
|
Non-cash compensation expense
|
5,058
|
|
|
5,242
|
|
3,181
|
|
||||
|
Contract termination charge related to Major Energy
Companies change of control |
—
|
|
|
4,099
|
|
—
|
|
||||
|
Change in Tax Receivable Agreement liability
(1)
|
(22,267
|
)
|
|
—
|
|
—
|
|
||||
|
Adjusted EBITDA
(2)
|
$
|
102,884
|
|
|
$
|
81,892
|
|
$
|
36,869
|
|
|
(1) Represents the change in the value of the Tax Receivable Agreement liability due to U.S. Tax Reform. See discussion in Note
12 "Income Taxes."
(2) Includes
$9.6 million
and
$1.1 million
related to the change in fair value as the result of the revaluation of the Major Earnout liability at
December 31, 2017
and
2016
. Refer to Note
9 "Fair Value Measurements"
for further discussion of the revaluation of the Major Earnout.
58
The following table presents a reconciliation of Adjusted EBITDA to net cash provided by (used in) operating activities for each of the periods indicated.
|
|
Year Ended December 31,
|
||||||||||
|
(in thousands)
|
2017
|
2016
|
2015
|
||||||||
|
Reconciliation of Adjusted EBITDA to net cash provided by operating activities:
|
|||||||||||
|
Net cash provided by operating activities
|
$
|
63,912
|
|
|
$
|
67,793
|
|
$
|
45,931
|
|
|
|
Amortization of deferred financing costs
|
(1,035
|
)
|
|
(668
|
)
|
(412
|
)
|
||||
|
Allowance for doubtful accounts and bad debt expense
|
(6,550
|
)
|
|
(1,261
|
)
|
(7,908
|
)
|
||||
|
Interest expense
|
11,134
|
|
|
8,859
|
|
2,280
|
|
||||
|
Income tax expense
|
37,528
|
|
|
10,426
|
|
1,974
|
|
||||
|
Change in Tax Receivable Agreement liability
(1)
|
(22,267
|
)
|
|
—
|
|
—
|
|
||||
|
Changes in operating working capital
|
|
|
|
|
|||||||
|
Accounts receivable, prepaids, current assets
|
31,905
|
|
|
12,135
|
|
(18,820
|
)
|
||||
|
Inventory
|
718
|
|
|
542
|
|
4,544
|
|
||||
|
Accounts payable and accrued liabilities
|
(13,672
|
)
|
|
(17,653
|
)
|
13,008
|
|
||||
|
Other
|
1,211
|
|
|
1,719
|
|
(3,728
|
)
|
||||
|
Adjusted EBITDA
|
$
|
102,884
|
|
|
$
|
81,892
|
|
$
|
36,869
|
|
|
|
Cash Flow Data:
|
|||||||||||
|
Cash flows provided by operating activity
|
$
|
63,912
|
|
|
$
|
67,793
|
|
$
|
45,931
|
|
|
|
Cash flows used in investing activity
|
$
|
(97,757
|
)
|
|
$
|
(36,344
|
)
|
$
|
(41,943
|
)
|
|
|
Cash flows provided by (used in) financing activity
|
$
|
44,304
|
|
|
$
|
(16,963
|
)
|
$
|
(3,873
|
)
|
|
(1) Represents the change in the value of the Tax Receivable Agreement liability due to U.S. Tax Reform. See discussion in Note
12 "Income Taxes."
The following table presents a reconciliation of Retail Gross Margin to operating income for each of the periods indicated.
|
|
Year Ended December 31,
|
||||||||||
|
(in thousands)
|
2017
|
2016
|
2015
|
||||||||
|
Reconciliation of Retail Gross Margin to Operating Income (Loss):
|
|||||||||||
|
Operating income
|
$
|
102,420
|
|
|
$
|
84,001
|
|
$
|
29,905
|
|
|
|
Depreciation and amortization
|
42,341
|
|
|
32,788
|
|
25,378
|
|
||||
|
General and administrative
|
101,127
|
|
|
84,964
|
|
61,682
|
|
||||
|
Less:
|
|
|
|
|
|||||||
|
Net asset optimization (expenses) revenues
|
(717
|
)
|
|
(586
|
)
|
1,494
|
|
||||
|
Net, Gains (losses) on non-trading derivative instruments
|
5,588
|
|
|
22,254
|
|
(18,423
|
)
|
||||
|
Net, Cash settlements on non-trading derivative instruments
|
16,508
|
|
|
(2,284
|
)
|
20,279
|
|
||||
|
Retail Gross Margin
|
$
|
224,509
|
|
|
$
|
182,369
|
|
$
|
113,615
|
|
|
|
Retail Gross Margin - Retail Electricity Segment
|
$
|
158,468
|
|
|
$
|
118,136
|
|
$
|
60,255
|
|
|
|
Retail Gross Margin - Retail Natural Gas Segment
|
$
|
66,041
|
|
|
$
|
64,233
|
|
$
|
53,360
|
|
|
59
Consolidated Results of Operations
Year Ended December 31, 2017
Compared to
Year Ended December 31, 2016
|
In Thousands
|
Year Ended December 31,
|
|
|||||||||
|
|
2017
|
2016
|
Change
|
||||||||
|
Revenues:
|
|
|
|
|
|||||||
|
Retail revenues
|
$
|
798,772
|
|
$
|
547,283
|
|
$
|
251,489
|
|
||
|
Net asset optimization revenues
|
(717
|
)
|
(586
|
)
|
(131
|
)
|
|||||
|
Total Revenues
|
798,055
|
|
546,697
|
|
251,358
|
|
|||||
|
Operating Expenses:
|
|
|
|
|
|
|
|||||
|
Retail cost of revenues
|
552,167
|
|
344,944
|
|
207,223
|
|
|||||
|
General and administrative
|
101,127
|
|
84,964
|
|
16,163
|
|
|||||
|
Depreciation and amortization
|
42,341
|
|
32,788
|
|
9,553
|
|
|||||
|
Total Operating Expenses
|
695,635
|
|
462,696
|
|
232,939
|
|
|||||
|
Operating income
|
102,420
|
|
84,001
|
|
18,419
|
|
|||||
|
Other (expense)/income:
|
|
|
|
|
|
|
|||||
|
Interest expense
|
(11,134
|
)
|
(8,859
|
)
|
(2,275
|
)
|
|||||
|
Change in Tax Receivable Agreement liability
(1)
|
22,267
|
|
|
—
|
|
22,267
|
|
||||
|
Interest and other income
|
256
|
|
957
|
|
(701
|
)
|
|||||
|
Total other (expenses)/income
|
11,389
|
|
(7,902
|
)
|
19,291
|
|
|||||
|
Income before income tax expense
|
113,809
|
|
76,099
|
|
37,710
|
|
|||||
|
Income tax expense
|
37,528
|
|
10,426
|
|
27,102
|
|
|||||
|
Net income
|
$
|
76,281
|
|
$
|
65,673
|
|
$
|
10,608
|
|
||
|
Adjusted EBITDA
(2)
|
$
|
102,884
|
|
$
|
81,892
|
|
$
|
20,992
|
|
||
|
Retail Gross Margin
(2)
|
224,509
|
|
182,369
|
|
42,140
|
|
|||||
|
Customer Acquisition Costs
|
25,874
|
|
24,934
|
|
940
|
|
|||||
|
RCE Attrition
|
4.3
|
%
|
4.3
|
%
|
—
|
|
|||||
|
Distributions paid to Class B non-controlling unit holders and dividends paid to Class A common shareholders
|
$
|
(43,319
|
)
|
$
|
(43,297
|
)
|
$
|
(22
|
)
|
||
(1) Represents the change in the value of the Tax Receivable Agreement liability due to U.S. Tax Reform. See discussion in Note
12 "Income Taxes."
(2) Adjusted EBITDA and Retail Gross Margin are non-GAAP financial measures. See “
—
How We Evaluate Our Operations” for a reconciliation of Adjusted EBITDA and Retail Gross Margin to their most directly comparable financial measures presented in accordance with GAAP.
Total Revenues.
Total revenues for the
year ended
December 31, 2017
were approximately
$798.1 million
,
an increase
of approximately
$251.4 million
, or
46%
, from approximately
$546.7 million
for the
year ended
December 31, 2016
. This
increase
was primarily due to an increase in electricity and natural gas volumes driven by full year results of the Major Energy Companies and the Provider Companies, and the acquisition of the Verde Companies, partially offset by decreased electricity pricing.
|
Change in electricity volumes sold
|
$
|
258.6
|
|
|
Change in natural gas volumes sold
|
10.7
|
|
|
|
Change in electricity unit revenue per MWh
|
(18.2
|
)
|
|
|
Change in natural gas unit revenue per MMBtu
|
0.4
|
|
|
|
Change in net asset optimization revenue (expense)
|
(0.1
|
)
|
|
|
Change in total revenues
|
$
|
251.4
|
|
60
Retail Cost of Revenues
. Total retail cost of revenues for the
year ended
December 31, 2017
was approximately
$552.2 million
,
an increase
of approximately
$207.3 million
, or
60%
, from approximately
$344.9 million
for the
year ended
December 31, 2016
. This
increase
was primarily due to additional volumes driven by full year results of the Major Energy Companies and the Provider Companies, and the acquisition of the Verde Companies, which resulted in higher electricity and natural gas supply costs, offset by a decrease in the value of our retail derivative portfolio.
|
Change in electricity volumes sold
|
$
|
185.4
|
|
|
Change in natural gas volumes sold
|
5.4
|
|
|
|
Change in electricity unit cost per MWh
|
14.6
|
|
|
|
Change in natural gas unit cost per MMBtu
|
4.0
|
|
|
|
Change in value of retail derivative portfolio
|
(2.1
|
)
|
|
|
Change in retail cost of revenues
|
$
|
207.3
|
|
General and Administrative Expense
. General and administrative expense for the
year ended
December 31, 2017
was approximately
$101.1 million
,
an increase
of approximately
$16.1 million
, or
19%
, as compared to
$85.0 million
for the
year ended
December 31, 2016
. This
increase
was primarily due to increased billing and other variable costs associated with increased RCEs, including those added as a result of full year results of the Major Energy Companies and the Provider Companies and the acquisition of the Verde Companies, as well as costs related to the acquisition of customers by the Verde Companies that we cannot capitalize, partially offset by a net decrease in fair value of earnout liabilities, which decreased general and administrative expenses.
Depreciation and Amortization Expense
. Depreciation and amortization expense for the
year ended
December 31, 2017
was approximately
$42.3 million
,
an increase
of approximately
$9.5 million
, or
29%
, from approximately
$32.8 million
for the
year ended
December 31, 2016
. This
increase
was primarily due to the increased amortization expense associated with customer intangibles from full year results of the Major Energy Companies and the Provider Companies and the acquisition of the Verde Companies.
Customer Acquisition Cost
. Customer acquisition cost for the
year ended
December 31, 2017
was approximately
$25.9 million
,
an increase
of approximately
$1.0 million
, or
4%
from approximately
$24.9 million
for the
year ended
December 31, 2016
. This
increase
was primarily due to customer acquisition costs of the Major Energy Companies, the Provider Companies and Verde Companies offset by decreased organic sales in the second half of the year as we devoted resources to the acquisition of the Verde Companies.
61
Year Ended December 31, 2016
Compared to
Year Ended December 31, 2015
|
In Thousands
|
Year Ended December 31,
|
||||||||||
|
2016
|
2015
|
Change
|
|||||||||
|
Revenues:
|
|||||||||||
|
Retail revenues
|
$
|
547,283
|
|
$
|
356,659
|
|
$
|
190,624
|
|
||
|
Net asset optimization revenues
|
(586
|
)
|
1,494
|
|
(2,080
|
)
|
|||||
|
Total Revenues
|
546,697
|
|
358,153
|
|
188,544
|
|
|||||
|
Operating Expenses:
|
|
|
|||||||||
|
Retail cost of revenues
|
344,944
|
|
241,188
|
|
103,756
|
|
|||||
|
General and administrative
|
84,964
|
|
61,682
|
|
23,282
|
|
|||||
|
Depreciation and amortization
|
32,788
|
|
25,378
|
|
7,410
|
|
|||||
|
Total Operating Expenses
|
462,696
|
|
328,248
|
|
134,448
|
|
|||||
|
Operating income
|
84,001
|
|
29,905
|
|
54,096
|
|
|||||
|
Other (expense)/income:
|
|
|
|||||||||
|
Interest expense
|
(8,859
|
)
|
(2,280
|
)
|
(6,579
|
)
|
|||||
|
Interest and other income
|
957
|
|
324
|
|
633
|
|
|||||
|
Total other (expenses)/income
|
(7,902
|
)
|
(1,956
|
)
|
(5,946
|
)
|
|||||
|
Income before income tax expense
|
76,099
|
|
27,949
|
|
48,150
|
|
|||||
|
Income tax expense
|
10,426
|
|
1,974
|
|
8,452
|
|
|||||
|
Net income
|
$
|
65,673
|
|
$
|
25,975
|
|
$
|
39,698
|
|
||
|
Adjusted EBITDA
(1)
|
$
|
81,892
|
|
$
|
36,869
|
|
$
|
45,023
|
|
||
|
Retail Gross Margin
(1)
|
$
|
182,369
|
|
$
|
113,615
|
|
$
|
68,754
|
|
||
|
Customer Acquisition Costs
|
$
|
24,934
|
|
$
|
19,869
|
|
$
|
5,065
|
|
||
|
RCE Attrition
|
4.3
|
%
|
5.1
|
%
|
(0.8
|
)%
|
|||||
|
Distributions paid to Class B non-controlling unit holders and dividends paid to Class A common shareholders
|
$
|
(43,297
|
)
|
$
|
(20,043
|
)
|
$
|
(23,254
|
)
|
||
(1) Adjusted EBITDA and Retail Gross Margin are non-GAAP financial measures. See “
—
How We Evaluate Our Operations” for a reconciliation of Adjusted EBITDA and Retail Gross Margin to their most directly comparable financial measures presented in accordance with GAAP.
Total Revenues.
Total revenues for the year ended
December 31, 2016
were approximately
$546.7 million
,
an increase
of approximately
$188.5 million
, or
53%
, from approximately
$358.2 million
for the year ended
December 31, 2015
. This increase was primarily due to an increase in electricity and natural gas volumes driven by acquisitions of the Provider Companies and Major Energy Companies, partially offset by decreased electricity pricing and natural gas pricing.
|
Change in electricity volumes sold
|
$
|
231.7
|
|
|
Change in natural gas volumes sold
|
17.5
|
|
|
|
Change in electricity unit revenue per MWh
|
(44
|
)
|
|
|
Change in natural gas unit revenue per MMBtu
|
(14.6
|
)
|
|
|
Change in net asset optimization revenue (expense)
|
(2.1
|
)
|
|
|
Change in total revenues
|
$
|
188.5
|
|
Retail Cost of Revenues
. Total retail cost of revenues for the year ended
December 31, 2016
was approximately
$344.9 million
,
an increase
of approximately
$103.7 million
, or
43%
, from approximately
$241.2 million
for the year ended
December 31, 2015
. This increase was primarily due to additional volumes driven by the acquisitions of the Provider Companies and Major Energy Companies, partially offset by lower electricity and natural gas supply costs and decrease in the value of our retail derivative portfolio.
62
|
Change in electricity volumes sold
|
$
|
170.8
|
|
|
Change in natural gas volumes sold
|
10.1
|
|
|
|
Change in electricity unit cost per MWh
|
(41.0
|
)
|
|
|
Change in natural gas unit cost per MMBtu
|
(18.1
|
)
|
|
|
Change in value of retail derivative portfolio
|
(18.1
|
)
|
|
|
Change in retail cost of revenues
|
$
|
103.7
|
|
General and Administrative Expense
. General and administrative expense for the year ended
December 31, 2016
was approximately
$85.0 million
,
an increase
of approximately
$23.3 million
or
38%
, as compared to
$61.7 million
for the year ended
December 31, 2015
. This increase was primarily due to increased billing and other variable costs associated with increased RCEs, including those added as a result of the acquisitions of Provider Companies and Major Energy Companies, increased stock-based compensation associated with higher stock prices and additional equity awards, and additional litigation expense. This increase was partially offset by cost reductions from the Master Service Agreement with Retailco Services and lower bad debt expense as we had better than anticipated collections as a result of new collection initiatives, and as the impact of attrition in the Southern California market was limited to 2015.
Depreciation and Amortization Expense
. Depreciation and amortization expense for the year ended
December 31, 2016
was approximately
$32.8 million
,
an increase
of approximately
$7.4 million
, or
29%
, from approximately
$25.4 million
for the year ended
December 31, 2015
. This increase was primarily due to the increased amortization expense associated with customer intangibles from the acquisitions of Provider Companies and Major Energy Companies.
Customer Acquisition Cost.
Customer acquisition cost for the year ended
December 31, 2016
was approximately
$24.9 million
,
an increase
of approximately
$5.0 million
, or
25%
from approximately
$19.9 million
for the year ended
December 31, 2015
. This
increase
was primarily due to customer acquisition costs of the Major Energy Companies of $7.0 million. The increase was partially offset by decreased organic sales in the first half of 2016 as we shifted our focus to growth through acquisitions.
63
Operating Segment Results
|
|
Year Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
2015
|
|||||||
|
|
(in thousands, except volume and per unit operating data)
|
||||||||||
|
Retail Electricity Segment
|
|
|
|||||||||
|
Total Revenues
|
$
|
657,561
|
|
|
$
|
417,229
|
|
$
|
229,490
|
|
|
|
Retail Cost of Revenues
|
477,012
|
|
|
286,795
|
|
170,684
|
|
||||
|
Less: Net Asset Optimization Revenues
|
(5
|
)
|
|
—
|
|
—
|
|
||||
|
Less: Net Gains (Losses) on non-trading derivatives, net of cash settlements
|
22,086
|
|
|
12,298
|
|
(1,449
|
)
|
||||
|
Retail Gross Margin
(1)
—Electricity
|
$
|
158,468
|
|
|
$
|
118,136
|
|
$
|
60,255
|
|
|
|
Volumes—Electricity (MWhs)
|
6,755,663
|
|
|
4,170,593
|
|
2,075,479
|
|
||||
|
Retail Gross Margin
(2)
—Electricity per MWh
|
$
|
23.46
|
|
|
$
|
28.33
|
|
$
|
29.03
|
|
|
|
Retail Natural Gas Segment
|
|
|
|
||||||||
|
Total Revenues
|
$
|
140,494
|
|
|
$
|
129,468
|
|
$
|
128,663
|
|
|
|
Retail Cost of Revenues
|
75,155
|
|
|
58,149
|
|
70,504
|
|
||||
|
Less: Net Asset Optimization Revenues
|
(712
|
)
|
|
(586
|
)
|
1,494
|
|
||||
|
Less: Net Gains (Losses) on non-trading derivatives, net of cash settlements
|
10
|
|
|
7,672
|
|
3,305
|
|
||||
|
Retail Gross Margin
(1)
—Gas
|
$
|
66,041
|
|
|
$
|
64,233
|
|
$
|
53,360
|
|
|
|
Volumes—Gas (MMBtus)
|
18,203,684
|
|
|
16,819,713
|
|
14,786,681
|
|
||||
|
Retail Gross Margin
(2)
—Gas per MMBtu
|
$
|
3.63
|
|
|
$
|
3.82
|
|
$
|
3.61
|
|
|
(1) Reflects the Retail Gross Margin attributable to our Retail Natural Gas Segment or Retail Electricity Segment, as applicable. Retail Gross Margin is a non-GAAP financial measure. See “—How We Evaluate Our Operations” for a reconciliation of Adjusted EBITDA and Retail Gross Margin to their most directly comparable financial measures presented in accordance with GAAP.
(2) Reflects the Retail Gross Margin for the Retail Natural Gas Segment or Retail Electricity Segment, as applicable, divided by the total volumes in MMBtu or MWh, respectively.
Year Ended December 31, 2017
Compared to the
Year Ended December 31, 2016
Retail Electricity Segment
Total revenues for the Retail Electricity Segment for the year ended
December 31, 2017
were approximately
$657.6 million
,
an increase
of approximately
$240.4 million
, or
58%
, from approximately
$417.2 million
for the year ended
December 31, 2016
. This
increase
was primarily due to an increase in volume from the acquisitions of the Major Energy Companies, the Provider Companies and the Verde Companies and the addition of several higher volume commercial customers in the East, which resulted in an increase in revenues of
$258.6 million
. This increase was partially offset by a decrease in electricity pricing, driven by the lower electricity pricing environment from milder than anticipated weather, which resulted in a decrease of
$18.2 million
.
Retail cost of revenues for the Retail Electricity Segment for the year ended
December 31, 2017
was approximately
$477.0 million
,
an increase
of approximately
$190.2 million
, or
66%
, from approximately
$286.8 million
for the year ended
December 31, 2016
. This
increase
was primarily due to an increase in volume as a result of the acquisitions of the Major Energy Companies, the Provider Companies and the Verde Companies and the addition of higher volume commercial customers in the East, which resulted in an increase of
$185.4 million
, increased electricity prices, which resulted in an increase in retail cost of revenues of
$14.6 million
. Additionally, there was a decrease of
$9.8 million
due to a change in the value of our retail derivative portfolio used in hedging.
64
Retail gross margin for the Retail Electricity Segment for the year ended
December 31, 2017
was approximately
$158.5 million
,
an increase
of approximately
$40.4 million
, or
34%
, as compared to
$118.1 million
for the year ended
December 31, 2016
as indicated in the table below (in millions).
|
Change in volumes sold
|
$
|
73.2
|
|
|
Change in unit margin per MWh
|
(32.8
|
)
|
|
|
Change in retail electricity segment retail gross margin
|
$
|
40.4
|
|
Unit margins were negatively impacted as a result of the higher volumes from our commercial customers.
The volumes of electricity sold
increased
from
4,170,593
MWh for the year ended
December 31, 2016
to
6,755,663
MWh for the year ended
December 31, 2017
. This
increase
was primarily due to full year results of the Major Energy Companies and the Provider Companies, the addition of customers through the acquisition of the Verde Companies, and an increased number of higher volume C&I customers.
Retail Natural Gas Segment
Total revenues for the Retail Natural Gas Segment for the year ended
December 31, 2017
were approximately
$140.5 million
,
an increase
of approximately
$11.0 million
, or
9%
, from approximately
$129.5 million
for the year ended
December 31, 2016
. This
increase
was attributable to an increase in customer sales volume resulting from full year results of the Major Energy Companies and the acquisition of the Verde Companies, which increased total revenues by
$10.7 million
.
Retail cost of revenues for the Retail Natural Gas Segment for the year ended
December 31, 2017
were approximately
$75.2 million
,
an increase
of approximately
$17.1 million
, or
29%
, from approximately
$58.1 million
for the year ended
December 31, 2016
. This
increase
was due to a
$7.7 million
change in the fair value of our retail derivative portfolio used for hedging, an increase of
$5.4 million
related to increased volume resulting from full year results of the Major Energy Companies, the acquisition of the Verde Companies, and increased supply costs of
$4.0 million
.
Retail gross margin for the Retail Natural Gas Segment for the year ended
December 31, 2017
was approximately
$66.0 million
,
an increase
of approximately
$1.8 million
, or
3%
from approximately
$64.2 million
for the year ended
December 31, 2016
, as indicated in the table below (in millions).
|
Change in volumes sold
|
$
|
5.3
|
|
|
Change in unit margin per MMBtu
|
(3.5
|
)
|
|
|
Change in retail natural gas segment retail gross margin
|
$
|
1.8
|
|
Unit margins were negatively impacted as a result of increase in higher volume commercial customers.
The volumes of natural gas sold
increased
from
16,819,713
MMBtu for the year ended
December 31, 2016
to
18,203,684
MMBtu for the year ended
December 31, 2017
. This
increase
was primarily due to our full year results of the Major Energy Companies and an increased number of higher volume C&I customers.
Year Ended December 31, 2016
Compared to the
Year Ended December 31, 2015
Retail Electricity Segment
Retail revenues for the Retail Electricity Segment for the year ended December 31, 2016 was approximately $417.2 million, an increase of approximately $187.7 million, or 82%, from approximately $229.5 million for the year ended December 31, 2015. This increase was primarily due to an increase in volume from the acquisitions of the Major Energy Companies and the Provider Companies and the addition of several higher volume commercial
65
customers in the East, which resulted in an increase in revenues of $231.7 million. This increase was partially offset by a decrease in electricity pricing, driven by the lower commodity pricing environment from milder than anticipated weather, which resulted in a decrease of $44.0 million.
Retail cost of revenues for the Retail Electricity Segment for the year ended December 31, 2016 was approximately $286.8 million, an increase of approximately $116.1 million, or 68%, from approximately $170.7 million for the year ended December 31, 2015. This increase was primarily due to an increase in volume as a result of the acquisitions of the Major Energy Companies and the Provider Companies, as well as organic growth in the East, resulting in an increase of $170.8 million. This increase was partially offset by a decrease of $13.7 million due to a change in the value of our retail derivative portfolio used for hedging and decreased commodity prices, resulting in a decrease in retail cost of revenues of $41.0 million.
Retail gross margin for the Retail Electricity Segment for the year ended December 31, 2016 was approximately $118.1 million, an increase of approximately $57.8 million, or 96%, as compared to $60.3 million for the year ended December 31, 2015 as indicated in the table below (in millions).
|
Change in volumes sold
|
$
|
60.8
|
|
|
Change in unit margin per MWh
|
(3.0
|
)
|
|
|
Change in retail electricity segment retail gross margin
|
$
|
57.8
|
|
Gross margins were positively impacted by an increase in volume as a result of the acquisitions of the Major Energy Companies and the Provider Companies.
The volumes of electricity sold increased from 2,075,479 MWh for the year ended December 31, 2015 to 4,170,593 MWh for the year ended December 31, 2016. This increase was primarily due to addition of customers through the acquisitions of Major Energy Companies and Provider Companies and organic growth in the East.
Retail Natural Gas Segment
Total revenues for the Retail Natural Gas Segment for the year ended December 31, 2016 were approximately $129.5 million, an increase of approximately $0.8 million, or 1%, from approximately $128.7 million for the year ended December 31, 2015. This increase was primarily attributable to an increase in customer sales volumes resulting from the acquisition of Major Energy Companies, which increased total revenues by $17.5 million. This increase was largely offset by lower rates driven by the lower commodity pricing environment, which resulted in a decrease in total revenues of $14.6 million, and a decrease of $2.1 million in net optimization revenues.
Retail cost of revenues for the Retail Natural Gas Segment for the year ended December 31, 2016 were approximately $58.1 million, a decrease of approximately $12.4 million, or 18%, from approximately $70.5 million for the year ended December 31, 2015. This decrease was due to decreased supply costs, which resulted in a decrease of $18.1 million, and a decrease of $4.4 million in the value of our retail derivative portfolio used for hedging. These decreases were partially offset by an increase of $10.1 million related to increased volume resulting from the acquisition of the Major Energy Companies.
Retail gross margin for the Retail Natural Gas Segment for the year ended December 31, 2016 was approximately $64.2 million, an increase of approximately $10.8 million, or 20% from approximately $53.4 million for the year ended December 31, 2015, as indicated in the table below (in millions).
|
Change in volumes sold
|
$
|
7.3
|
|
|
Change in unit margin per MMBtu
|
3.5
|
|
|
|
Change in retail natural gas segment retail gross margin
|
$
|
10.8
|
|
Unit margins were positively impacted by the overall lower commodity price environment.
66
The volumes of natural gas sold increased from 14,786,681 MMBtu for the year ended December 31, 2015 to 16,819,713 MMBtu for the year ended December 31, 2016. This increase was primarily due to our acquisition of Major Energy Companies.
Liquidity and Capital Resources
Overview
Our principal liquidity requirements are to meet our financial commitments, finance current operations, fund organic growth and acquisitions, service debt and pay dividends. Our liquidity requirements fluctuate with our customer acquisition costs, acquisitions, collateral posting requirements on our derivative instruments portfolio, distributions, the effects of the timing between payments of payables and receipts of receivables, including bad debt receivables, weather conditions, and our general working capital needs for ongoing operations.
Our primary sources of liquidity are cash generated from operations and borrowings under our Senior Credit Facility. We believe that cash generated from these sources will be sufficient to sustain current operations and to pay required taxes and quarterly cash distributions including the quarterly dividends to the holders of the Class A common stock and the Series A Preferred Stock for the next twelve months. We believe that the financing of any additional growth through acquisitions of businesses in 2018, other than those transactions described in “—Recent Developments,” may require further equity financing and/or further expansion of our Senior Credit Facility. Estimating our liquidity requirements is highly dependent on then-current market conditions, including forward prices for natural gas and electricity, and market volatility.
Liquidity Position
The following table details our total liquidity as of the date presented:
|
|
December 31,
|
||
|
($ in thousands)
|
2017
|
||
|
Cash and cash equivalents
|
$
|
29,419
|
|
|
Senior Credit Facility Availability
(1)
|
12,501
|
|
|
|
Subordinated Debt Availability
(2)
|
25,000
|
|
|
|
Total Liquidity
|
$
|
66,920
|
|
(1) Subject to Senior Credit Facility borrowing base and covenant restrictions. See "
__
Sources of Liquidity
__
Senior Credit Facility."
(2) The availability of the Subordinated Facility is dependent on our Founder's financial position and liquidity. See "
__
Subordinated Debt Facility."
In order to finance the acquisition of the Verde Companies during the year ended December 31, 2017, we borrowed
$44.0 million
under our Senior Credit Facility and
$15.0 million
under the Subordinated Facility. During the year ended December 31, 2017, we paid down the outstanding debt under our Subordinated Facility. Remaining availability under the Senior Credit Facility and the Subordinated Facility as of
December 31, 2017
is
$12.5 million
and
$25.0 million
, respectively.
Our borrowings under the Senior Credit Facility are subject to material variations on a seasonal basis due to the timing of commodity purchases to satisfy natural gas inventory purchases and to meet customer demands during periods of peak usage. Please see "—Sources of Liquidity—Senior Credit Facility" for a description of our Senior Credit Facility, and "—Sources of Liquidity—Subordinated Debt Facility" for a description of the Subordinated Facility.
In the third quarter of 2017, Hurricane Harvey caused historic flooding, extensive damage and widespread power outages across the Gulf Coast of Texas. Additionally, during the first quarter of 2018, the northeast experienced colder than normal weather conditions. This weather event created increased collateral requirements in the Northeast for us. As a result, we took steps to increase our liquidity during late 2017 and early 2018, including
67
exercising the accordion feature under our Senior Credit Facility. See “—Recent Developments—Expansion of Credit Facility” above.
On March 7, 2018, we and Retailco Services mutually agreed to terminate the Master Services Agreement, effective April 1, 2018. We may incur capital resources integrating the operational support services back into our operations. See “—Recent Developments—Termination of Master Services Agreement” and “Risk Factors—Risks Related to Our Business and Our Industry—The termination of the Master Service Agreement subjects us to a variety of risks.”
Cash Flows
Year Ended
December 31, 2017
Compared to the
Year Ended
December 31, 2016
Our cash flows were as follows for the respective periods (in thousands):
|
|
Year Ended December 31,
|
||||||||||
|
|
2017
|
2016
|
Change
|
||||||||
|
Net cash provided by operating activities
|
$
|
63,912
|
|
$
|
67,793
|
|
$
|
(3,881
|
)
|
||
|
Net cash used in investing activities
|
$
|
(97,757
|
)
|
$
|
(36,344
|
)
|
$
|
(61,413
|
)
|
||
|
Net cash provided by (used in) financing activities
|
$
|
44,304
|
|
$
|
(16,963
|
)
|
$
|
61,267
|
|
||
Cash Flows Provided by Operating Activities
. Cash flows
provided by
operating activities for the year ended
December 31, 2017
decreased
by
$3.9 million
compared to the year ended
December 31, 2016
. The decrease was primarily the result of a decrease in the changes in working capital, offset by an increase in retail gross margin for the year ended
December 31, 2017
.
Cash Flows Used in Investing Activities
. Cash flows
used in
investing activities
increased
by
$61.4 million
for the year ended
December 31, 2017
, which was primarily due to the funding of the acquisition of the Verde Companies and the acquisitions of Perigee and other customers during the year ended
December 31, 2017
, as well as earnout payments made during the year ended
December 31, 2017
related to the Provider Companies and Major Energy Companies.
Cash Flows Provided by Financing Activities
. Cash flows
provided by
financing activities
increased
by
$61.3 million
for the year ended
December 31, 2017
primarily due to increased net utilization of our Senior Credit Facility and proceeds from the issuance of Series A Preferred Stock, offset by additional dividends and distributions, respectively, made to holders of our Class A common stock, holders of our Series A Preferred Stock, and holders of the Class B units of Spark HoldCo.
Year Ended
December 31, 2016
Compared to the
Year Ended
December 31, 2015
Our cash flows were as follows for the respective periods (in thousands):
|
|
Year Ended December 31,
|
||||||||||
|
|
2016
|
2015
|
Change
|
||||||||
|
|
|
|
|||||||||
|
Net cash provided by operating activities
|
$
|
67,793
|
|
$
|
45,931
|
|
$
|
21,862
|
|
||
|
Net cash used in investing activities
|
$
|
(36,344
|
)
|
$
|
(41,943
|
)
|
$
|
5,599
|
|
||
|
Net cash used in financing activities
|
$
|
(16,963
|
)
|
$
|
(3,873
|
)
|
$
|
(13,090
|
)
|
||
Cash Flows Provided by Operating Activities
. Cash flows provided by operating activities for the year ended
December 31, 2016
increased by
$21.9 million
compared to the year ended
December 31, 2015
. The increase was primarily due to an increase in retail gross margin in 2016 as a result of the acquisitions of the Provider Companies and the Major Energy Companies.
68
Cash Flows Used in Investing Activities
. Cash flows used in investing activities decreased by
$5.6 million
for the year ended
December 31, 2016
, primarily driven by the decrease in cash used for acquisitions in 2016 compared to 2015.
Cash Flows Used in Financing Activities
. Cash flows used in financing activities increased by
$13.1 million
for the year ended
December 31, 2016
primarily due to additional dividends and distributions, respectively, made to holders of our Class A common stock and holders of the class B units of Spark HoldCo, partially offset by increased net utilization of our Senior Credit Facility and equity issuance to our affiliates of our Founder.
Sources of Liquidity and Capital Resources
Senior Credit Facility
On May 19, 2017 (the “Closing Date”), the Company, as guarantor, and Spark HoldCo (the “Borrower” and, together with SE, SEG, CenStar, CenStar Operating Company, LLC, Oasis, Oasis Power, LLC, the Provider Companies, the Major Energy Companies and Perigee Energy, LLC, each subsidiaries of Spark HoldCo, the “Co-Borrowers”), entered into a senior secured borrowing base credit facility (the “Senior Credit Facility”) in an aggregate amount of
$120.0 million
. The Verde Companies became Co-Borrowers upon the completion of our acquisition of the Verde Companies. On November 2, 2017, the Company and Co-Borrowers entered into an amendment to the Senior Credit Facility, which entitles the Co-Borrowers to elect to increase total commitments under the Senior Credit Facility to
$200.0 million
. In connection with any such increase in commitments, the various limits on advances for Working Capital Loans, Letters of Credit and Bridge Loans increased accordingly. On November 30, 2017, we exercised the accordion feature in the Senior Credit Facility, expanding commitments to an aggregate amount of
$185.0 million
.
As of December 31, 2017, there was
$125.3 million
outstanding under the Senior Credit Facility, and there was approximately
$12.5 million
available borrowing capacity (which includes a
$47.2 million
reduction for outstanding letters of credit).
The Senior Credit Facility will mature on May 19, 2019, and all amounts outstanding thereunder will be payable on the maturity date. Borrowings under the Bridge Loan sublimit will be repaid
25%
per year on a quarterly basis (or
6.25%
per quarter), with the remainder due at maturity.
On January 11, 2018 and January 23, 2018, we exercised the accordion feature in the Senior Credit Facility for an additional
$10.0 million
and
$5.0 million
, respectively, in commitments by existing lenders. These exercises of the accordion feature of the Senior Credit Facility brought total commitments under the Senior Credit Facility to
$200.0 million
.
Subject to applicable sublimits and terms of the Senior Credit Facility, borrowings are available for the issuance of letters of credit (“Letters of Credit”), working capital and general purpose revolving credit loans up to
$200.0 million
(“Working Capital Loans”), and bridge loans up to
$50.0 million
(“Bridge Loans”) for the purpose of partial funding for acquisitions. Borrowings under the Senior Credit Facility may be used to refinance loans outstanding under the previous Senior Credit Facility, pay fees and expenses in connection with the current 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 the Company’s Class A common stock.
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
|
69
|
•
|
the 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
|
|
•
|
the 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 will pay a commitment fee of
0.50%
quarterly in arrears on the unused portion of the Senior Credit Facility. In addition, the Co-Borrowers will be 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 as follows:
|
•
|
Minimum Fixed Charge Coverage Ratio
. Spark Energy, Inc. 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 any Subordinated Debt but including interest in respect of that certain promissory note made by Censtar Energy Corp 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 of the Company), distributions, the aggregate amount of repurchases of the Company’s Class A common stock or commitments for such purchases, taxes and scheduled amortization payments.
|
|
•
|
Maximum Total Leverage Ratio
. Spark Energy, Inc. must maintain a ratio of total indebtedness (excluding eligible subordinated debt) to Adjusted EBITDA of no more than
2.00
to 1.00.
|
As of
December 31, 2017
, the Company was in compliance with these ratios.
The Senior Credit Facility contains various negative covenants that limit the Company’s ability to, among other things, do any of the following:
|
•
|
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 is secured by pledges of the equity of the portion of Spark HoldCo owned by the Company, 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.
Spark Energy, Inc. is 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 the Company’s
70
Class A common stock through one or more normal course open market purchases through NASDAQ so long as: (a) no default exists or would result therefrom; (b) the Co-Borrowers are in pro forma compliance with all financial covenants before and after giving effect thereto; and (c) the outstanding amount of all loans and letters of credit does not exceed the borrowing base limits.
The Senior Credit Facility contains certain customary representations and warranties and events of default. Events of default include, among other things, payment defaults, breaches of representations and warranties, covenant defaults, cross-defaults and cross-acceleration to certain indebtedness, certain events of bankruptcy, certain events under ERISA, material judgments in excess of
$5.0 million
, certain events with respect to material contracts, actual or asserted failure of any guaranty or security document supporting the Senior Credit Facility to be in full force and effect, failure of Nathan Kroeker to retain his position as President and Chief Executive Officer of the Company, and failure of W. Keith Maxwell III to retain his position as chairman of the board of directors. A default will also occur if at any time W. Keith Maxwell III ceases to, directly or indirectly, own at least
13,600,000
Class A and Class B shares on a combined basis (to be adjusted for any stock split, subdivisions or other stock reclassification or recapitalization), and a controlling percentage of the voting equity interest of the Company, and certain other changes in control. If such an event of default occurs, the lenders under the Senior Credit Facility would be entitled to take various actions, including the acceleration of amounts due under the facility and all actions permitted to be taken by a secured creditor.
In addition, the Senior Credit Facility contains affirmative covenants that are customary for credit facilities of this type. The covenants include delivery of financial statements, including any filings made with the SEC, maintenance of property and insurance, payment of taxes and obligations, material compliance with laws, inspection of property, books and records and audits, use of proceeds, payments to bank blocked accounts, notice of defaults and certain other customary matters.
Shelf Registration Statement
On October 7, 2016, we filed a registration statement under the Securities Act on Form S-3 covering offers and sales, from time to time, by us of up to
$200,000,000
of Class A common stock, preferred stock, depositary shares and warrants, and by the selling stockholders named therein of up to 22,679,126 shares of Class A common stock (the "Shelf Registration Statement"). The Shelf Registration Statement was declared effective on October 20, 2016.
Series A Preferred Stock Issuances
On January 26, 2018, the Company issued
2,000,000
shares of Series A Preferred Stock from the Shelf Registration Statement and received net proceeds from the offering of approximately
$48.9 million
(net of underwriting discounts, commissions and a structuring fee).
At-the-Market Sales Agreement
On July 21, 2017, the Company entered into an at-the-market sales agreement (the "ATM Agreement") to sell the Company’s Series A Preferred Stock, from time to time, having an aggregate offering price of up to
$50.0 million
under the Shelf Registration Statement. The Company intends to use the proceeds from any sales pursuant to the ATM Agreement, after deducting the sales agent’s commissions and the Company’s offering expenses, for general corporate purposes, which may include, among other things, funding working capital, capital expenditures, liquidity for operational contingencies, debt repayments and acquisitions.
Subordinated Debt Facility
On December 27, 2016, the Company and Spark HoldCo jointly issued to Retailco, an entity owned by our Founder, a
5%
subordinated note in the principal amount of up to
$25.0 million
. The subordinated note allows us and Spark HoldCo to draw advances in increments of no less than
$1.0 million
per advance up to the maximum principal amount of the subordinated note (the "Subordinated Facility"). The subordinated note matures approximately 3 ½ years following the date of issuance, and advances thereunder accrue interest at
5%
per annum
71
from the date of the advance. We have the right to capitalize interest payments under the subordinated note. The subordinated note is subordinated in certain respects to our Senior Credit Facility pursuant to a subordination agreement. We may pay interest and prepay principal on the subordinated note so long as we are in compliance with our covenants under the Senior Credit Facility, are not in default under the Senior Credit Facility and have minimum availability of
$5.0 million
under our borrowing base under the Senior Credit Facility. Payment of principal and interest under the subordinated note is accelerated upon the occurrence of certain change of control transactions.
We may use the Subordinated Facility from time to time to enhance short term liquidity, but we do not view the Subordinated Facility as a material source of liquidity. Further, any availability under the Subordinated Facility is dependent on the Founder’s financial position and liquidity. As of
December 31, 2017
, there were no outstanding borrowings under the Subordinated Facility.
Uses of Liquidity and Capital Resources
Repayment of Current Portion of Senior Credit Facility
Repayment of the
$7.5 million
current portion of our Senior Credit Facility that is due to be repaid in 2018 has been repaid with proceeds of the offering of our Series A Preferred Stock in January 2018. Please see "—Sources of Liquidity and Capital Resources—Series A Preferred Stock Issuances."
Customer Acquisitions
Our customer acquisition strategy consists of customer growth obtained through opportunistic acquisitions complemented by traditional organic customer acquisitions. Our customer acquisition strategy requires significant capital resources. We fund our acquisition strategy with some combination of cash on hand and borrowings under our Senior Credit Facility. Please see “Business and Properties—Customer Acquisition and Retention—Acquisitions” for a summary of financing sources in our recent acquisitions.
Capital Expenditures
Capital expenditures for the year ended December 31, 2017 included approximately
$25.9 million
for customer acquisitions and approximately
$1.7 million
related to information systems improvements.
Share Repurchase Program
On May 24, 2017, the Company authorized a share repurchase program of up to $50.0 million of Class A common stock through December 31, 2017. The share repurchase program expired on December 31, 2017, and the Board has not renewed the share repurchase program for 2018 as of the date of this Annual Report. Since inception of the share repurchase program in May 2017, the Company repurchased
99,446
shares of its Class A common stock for a total cost of approximately
$2.0 million
. The Company funded the program through availability under its Senior Credit Facility and cash balances, as well as future operating cash flows.
Dividends to Investors
The Spark HoldCo, LLC Agreement provides, to the extent cash is available, for distributions pro rata to the holders of Spark HoldCo units such that we receive an amount of cash sufficient to cover the estimated taxes payable by us, the targeted quarterly dividend we intend to pay to holders of our Class A common stock, the quarterly dividends on our Series A Preferred Stock, and payments under the Tax Receivable Agreement we have entered into with Spark HoldCo, Retailco and NuDevco Retail.
We paid dividends to holders of our Class A common stock for the year ended
December 31, 2017
of approximately
$0.725
per share or
$9.5 million
in the aggregate. On January 18, 2018, our Board of Directors declared a quarterly
72
dividend of $0.18125 per share to holders of the Class A common stock as of March 2, 2018. This dividend will be paid on March 16, 2018. Our ability to pay dividends in the future will depend on many factors, including the performance of our business in the future and restrictions under our Senior Credit Facility. The financial covenants included in the Senior Credit Facility require the Company to retain increasing amounts of working capital over time, which may have the effect of restricting our ability to pay dividends. Management does not currently believe that the financial covenants in the Senior Credit Facility will cause any such restrictions.
As of
December 31, 2017
, in order to pay our stated dividends to holders of our Class A common stock and corresponding distributions to holders of our non-controlling interest, Spark HoldCo generally is required to distribute approximately
$15.6 million
on an annualized basis to holders of its Spark HoldCo units. If our business does not generate enough cash for Spark HoldCo to make such distributions, we may have to borrow to pay our dividend. If our business generates cash in excess of the amounts required to pay an annual dividend of
$0.725
per share of Class A common stock, we currently expect to reinvest any such excess cash flows in our business and not increase the dividends payable to holders of our Class A common stock. However, our future dividend policy is within the discretion of our Board of Directors and will depend upon various factors, including the results of our operations, our financial condition, capital requirements and investment opportunities.
For the year ended
December 31, 2017
, the Company paid
$2.1 million
related to dividends to holders of Series A Preferred Stock. As of
December 31, 2017
, the Company had accrued
$0.9 million
related to dividends to holders of our Series A Preferred Stock. This dividend was paid on
January 15, 2018
. In accordance with the terms of the Series A Preferred Stock on January 18, 2018, our Board of Directors declared a quarterly cash dividend in the amount of
$0.546875
per share for the Series A Preferred Stock. The dividend will be paid on
April 16, 2018
to holders of record on
April 2, 2018
of the Series A Preferred Stock. For the year ended
December 31, 2017
, the Company declared dividends of
$1.73
per share or
$3.0 million
in the aggregate based on the Series A Preferred Stock outstanding as of December 31, 2017.
Tax Receivable Agreement
We expect to make payments pursuant to the Tax Receivable Agreement that we have entered into with Retailco LLC (as assignee of NuDevco Retail Holdings), NuDevco Retail and Spark HoldCo in connection with our IPO. Except in cases where we elect to terminate the Tax Receivable Agreement early (or the Tax Receivable Agreement is terminated early due to certain mergers or other changes of control) or we have available cash but fail to make payments when due, generally we may elect to defer payments due under the Tax Receivable Agreement for up to five years if we do not have available cash to satisfy our payment obligations under the Tax Receivable Agreement or if our contractual obligations limit our ability to make these payments. Any such deferred payments under the Tax Receivable Agreement generally will accrue interest. If we were to defer substantial payment obligations under the Tax Receivable Agreement on an ongoing basis, the accrual of those obligations would reduce the availability of cash for other purposes, but we would not be prohibited from paying dividends on our Class A common stock.
We did not meet the threshold coverage ratio required to fund the first payment to NuDevco Retail Holdings under the Tax Receivable Agreement during the four-quarter period ending September 30, 2015. As such, the initial payment under the Tax Receivable Agreement due in late 2015 was deferred pursuant to the terms thereof.
We met the threshold coverage ratio required to fund the second TRA Payment to Retailco and NuDevco Retail under the Tax Receivable Agreement during the four-quarter period ending September 30, 2016, resulting in an initial TRA Payment of
$1.4 million
becoming due in December 2016. On November 6, 2016, Retailco and NuDevco Retail granted us the right to defer the TRA Payment until May 2018. During the period of time when we have elected to defer the TRA Payment, the outstanding payment amount will accrue interest at a rate calculated in the manner provided for under the Tax Receivable Agreement. The initial payment of
$1.4 million
under the Tax Receivable Agreement due in May 2018 was classified as a current liability in our consolidated balance sheet at December 31, 2017.
73
We met the threshold coverage ratio required to fund the third TRA Payment to Retailco and NuDevco Retail under the Tax Receivable Agreement during the four-quarter periods ending September 30, 2017. As such, the third payment under the Tax Receivable Agreement due in April 2018 has been classified as current in our consolidated balance sheet at
December 31, 2017
.
We expect to meet the threshold coverage ratio required to fund the fourth payment to Retailco and NuDevco Retail under the Tax Receivable Agreement during the four-quarter period ending September 30, 2018. As such, the fourth payment under the Tax Receivable Agreement due in late 2018 has been classified as current in our consolidated balance sheet at
December 31, 2017
. See Note
14 "Transactions with Affiliates"
in the notes to our consolidated financial statements for additional details on the Tax Receivable Agreement. See also “Risk Factors—Risks Related to our Class A Common Stock” for risks related to the Tax Receivable Agreement.
On December 22, 2017, the President signed the Tax Cuts and Jobs Act (“U.S. Tax Reform”), which enacts a wide range of changes to the U.S. Corporate income tax system. The impact of U.S. Tax Reform primarily represents our estimates of revaluing 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. Based on our historical financial performance, at December 31, 2017 we have a significant net deferred tax asset position that we have remeasured at the lower corporate rate of 21% and recognized a tax expense to adjust net deferred tax assets to the reduced value.
Verde Companies Promissory Note
In connection with the financing of the Verde Companies acquisition, on July 1, 2017, CenStar issued a promissory note in the aggregate principal amount of
$20.0 million
(the "Verde Promissory Note") for a portion of the purchase price. The Verde Promissory Note required
18
monthly installments beginning on August 1, 2017, and accrued interest at
5%
per annum from the date of issuance. The Verde Promissory Note, including principal and interest, was unsecured, but is guaranteed by the Company. Payment of principal and interest under the Verde Promissory Note was accelerated upon the occurrence of certain events of default. As of
December 31, 2017
, there was
$14.6 million
outstanding under the Verde Promissory Note, of which
$13.4 million
is due in 2018.
On January 12, 2018, CenStar issued to the Seller an amended and restated promissory note (the “Amended and Restated Verde Promissory Note”), which amended and restated the Verde Promissory Note in connection with the termination of our earnout obligations under the purchase agreement for the Verde Companies. The Amended and Restated Verde Promissory Note, effective January 12, 2018, retains the same maturity date as the Verde Promissory Note. The Amended and Restated Verde Promissory Note bears interest at a rate of 9% per annum beginning January 1, 2018. Principal and interest remain payable monthly on the first day of each month in which the Amended and Restated Verde Promissory Note is outstanding. CenStar will continue to deposit a portion of each
payment under the Amended and Restated Verde Promissory Note into an escrow account, which serves as security for certain indemnification claims and obligations under the purchase agreement. The amount deposited into the escrow account has been increased from the Verde Promissory Note. All principal and interest payable under the Amended and Restated Verde Promissory Note remains subject to acceleration upon the occurrence of certain events of default, including the failure to pay any principal or interest when due under the Amended and Restated Verde Promissory Note.
Verde Earnout Termination Note
On January 12, 2018, we entered into an Agreement to Terminate Earnout Payments (the “Earnout Termination Agreement”) that terminates our obligation to make any required earnout payments under the purchase agreement for our acquisition of the Verde Companies in exchange for CenStar’s issuance to the Seller of a promissory note in the principal amount of
$5.9 million
(the “Verde Earnout Termination Note”). The Verde Earnout Termination Note, effective January 12, 2018, matures on June 30, 2019 (subject to early maturity upon certain events) and bears interest at a rate of
9%
per annum. CenStar is permitted to withhold amounts otherwise due at maturity related to certain indemnifiable matters under the purchase agreement for our acquisition of the Verde Companies. Interest is
74
payable monthly on the first day of each month in which the Verde Earnout Termination Note is outstanding, beginning on its issuance date. The principal and any outstanding interest is due on June 30, 2019. All principal and interest payable under the Verde Earnout Termination Note is accelerated upon the occurrence of certain events of default, including the failure to pay any principal or interest when due under the Verde Earnout Termination Note. The Company recorded the Verde Earnout Termination Note of
$5.9 million
as long-term debt as of
December 31, 2017
.
Ongoing Obligations in Connection with Acquisitions
The Company is obligated to make earnout and installment payments in connection with the acquisitions of the Major Energy Companies as more fully described in this Annual Report. In the case of the Major Energy Companies acquisition, these maximum payments under the original agreement could have been as much as
$35 million
depending upon operating results and the customer counts through 2019; however, given the results, payments are expected to be significantly less than the maximum. See further discussion related to the valuation of the earnouts in Note
9 "Fair Value Measurements"
to the Company's annual financial statements included herein.
Summary of Contractual Obligations
The following table discloses aggregate information about our contractual obligations and commercial commitments as of
December 31, 2017
(in millions):
|
|
Total
|
2018
|
2019
|
2020
|
2021
|
2022
|
> 5 years
|
||||||||||||||
|
Operating leases
(1)
|
$
|
4.6
|
|
$
|
1.8
|
|
$
|
1.5
|
|
$
|
1.0
|
|
$
|
0.2
|
|
$
|
0.1
|
|
$
|
—
|
|
|
Purchase obligations:
|
|
|
|
|
|
|
|
||||||||||||||
|
Natural gas and electricity related purchase obligations
(2)
|
4.3
|
|
4.3
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|||||||
|
Pipeline transportation agreements
|
12.5
|
|
6.7
|
|
0.8
|
|
0.6
|
|
0.6
|
|
0.6
|
|
3.2
|
|
|||||||
|
Other purchase obligations
(3)
|
13.4
|
|
5.6
|
|
3.6
|
|
2.6
|
|
1.6
|
|
—
|
|
—
|
|
|||||||
|
Total purchase obligations
|
$
|
34.8
|
|
$
|
18.4
|
|
$
|
5.9
|
|
$
|
4.2
|
|
$
|
2.4
|
|
$
|
0.7
|
|
$
|
3.2
|
|
|
Senior Credit Facility
|
$
|
125.3
|
|
$
|
7.5
|
|
$
|
117.8
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
|
Note payable
|
20.5
|
|
13.4
|
|
7.1
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|||||||
|
Debt
|
$
|
145.8
|
|
$
|
20.9
|
|
$
|
124.9
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
|
(1)
|
Included in the total amount are future minimum payments for leases for services and equipment to support our operations and office rent.
|
|
(2)
|
The amounts represent the notional value of capacity purchase contracts (electricity related) that are not accounted for as derivative financial instruments recorded at fair market value as capacity contracts do not meet the definition of a derivative, and therefore are not recognized as liabilities on the consolidated balance sheet.
|
|
(3)
|
The amounts presented here include contracts for billing services and other software agreements.
|
Tax Receivable Agreement
Concurrently with the closing of the IPO, the Company entered into a Tax Receivable Agreement with Spark HoldCo, NuDevco Retail Holdings and NuDevco Retail. This agreement generally provides for the payment by the Company to Retailco, LLC (as the successor to NuDevco Retail Holdings) and NuDevco Retail of
85%
of the net cash savings, if any, in U.S. federal, state and local income tax or franchise tax that the Company actually realizes (or is deemed to realize in certain circumstances) in future periods. The Company retains the benefit of the remaining
15%
of these tax savings. See Note
12 "Income Taxes"
and Note
14 "Transactions with Affiliates"
for further discussion.
As of
December 31, 2017
, the Company has recorded a Tax Receivable Liability of
$32.3 million
. Estimated timing of payments made under the Tax Receivable Agreement is imprecise by nature, uncertain, and dependent upon a variety of factors, as described in Note
14 "Transactions with Affiliates."
75
Off-Balance Sheet Arrangements
As of
December 31, 2017
we had no material off-balance sheet arrangements.
Related Party Transactions
For a discussion of related party transactions see Note
14 "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 by using the following criteria: (1) persuasive evidence of an exchange arrangement exists, (2) delivery has occurred or services have been rendered, (3) the buyer’s price is fixed or determinable and (4) collection is reasonably assured. Utilizing these criteria, revenue is recognized when the natural gas or electricity is delivered. Similarly, cost of revenues is recognized when the commodity is delivered.
Revenues for natural gas and electricity sales are recognized upon delivery 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.
The cost of natural gas and electricity for sale to retail customers is 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.
Our asset optimization activities, which primarily include natural gas physical arbitrage and other short term storage and transportation opportunities, meet the definition of trading activities and are recorded on a net basis in the consolidated statements of operations in net asset optimization revenues as required by the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 815,
Derivatives and Hedging.
Accounts Receivable
76
We accrue an allowance for doubtful accounts based upon estimated uncollectible accounts receivable considering historical collections, accounts receivable aging analysis, credit risk and other factors. We write off accounts receivable balances against the allowance for doubtful accounts when the accounts receivable is deemed to be uncollectible.
We conduct 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 our credit risk being linked to the applicable utility in these territories, which generally has an investment-grade rating, and not to the end-use customer. We monitor the financial condition of each utility and currently believe that our susceptibility to an individually significant write-off as a result of concentrations of customer accounts receivable with those utilities is remote.
In markets that do not offer POR services or when we choose to directly bill our customers, certain accounts receivable are billed and collected by us. We bear the credit risk on these accounts and record an appropriate allowance for doubtful accounts to reflect any losses due to non-payment by customers. Our customers are individually insignificant and geographically dispersed in these markets. We write off customer balances when we believe that amounts are no longer collectible and when we have exhausted all means to collect these receivables.
Capitalized Customer Acquisition Costs
Capitalized customer acquisition costs consist primarily of hourly and commission based telemarketing costs, door-to-door agent commissions and other direct advertising costs associated with proven customer generation, and are capitalized and amortized over the estimated two-year average life of a customer in accordance with the provisions of FASB ASC 340-20,
Capitalized Advertising Costs
.
Recoverability of customer acquisition costs is evaluated based on a comparison of the carrying amount of the customer acquisition 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.
Business Combinations
Accounting Standards Codification (“ASC”) 815, Business Combinations requires that the purchase price for a business combination be assigned and allocated to the identifiable assets acquired and liabilities assumed based upon their 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, a purchase price that exceeds the fair value of the net assets acquired will result in the recognition of 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, 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
77
appraisers or valuation specialists to help us make this determination as we deem appropriate under the circumstances. Refer to Note
3 "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 make 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 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, 2017 is associated with both our Retail Natural Gas and Retail Electricity reporting units. We determine our reporting units 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 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. On October 31, 2017, we elected to by-pass the option to perform a qualitative assessment of goodwill and performed a quantitative assessment of goodwill in accordance with guidance from ASC 350. This guidance permits an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. If we fail the qualitative test or if we elect to by-pass the qualitative assessment, then we must compare our estimate of the fair value of a reporting unit with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, we perform the second step of the goodwill impairment test to measure the amount of goodwill impairment loss to be recorded, as necessary. The second step compares the implied fair value of the reporting unit’s goodwill to the carrying value, if any, of that goodwill. We determine the implied fair value of the goodwill in the same manner as determining the amount of goodwill to be recognized in a business combination.
We completed our annual assessment of goodwill impairment at October 31, 2017, and the test indicated no impairment.
Deferred tax assets and liabilities
The Company recognizes the amount of taxes payable or refundable for the year. In addition, the Company follows the asset and liability method of accounting for income taxes where deferred tax assets and liabilities are recognized for the expected future tax consequences of events that have been recognized in the financial statements or tax returns and operating loss carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in those years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in the tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is provided for deferred tax assets if it is more likely than not that these items will not be realized.
78
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.
Recent Accounting Pronouncements
Adopted Standards
In March 2016, the FASB issued ASU No. 2016-09,
Compensation - Stock Compensation (Topic 718)
("ASU 2016-09"). ASU 2016-09 includes provisions intended to simplify various aspects of accounting for shared-based payments, including income tax consequences, classification of awards as either equity or liability and classification on the statement of cash flows. This guidance is effective for annual and interim reporting periods of public entities beginning after December 15, 2016, with early adoption permitted. The Company adopted ASU 2016-09 on January 1, 2017.
The new standard requires prospective recognition of excess tax benefits resulting from stock-based compensation vesting and exercises to be recognized as a reduction of income taxes and reflected in operating cash flows. Previously, these amounts were recognized in additional paid-in capital and presented as a financing activity on the statement of cash flows. Net excess tax benefits of
$0.2 million
were recognized as a reduction of income taxes for the year ended
December 31, 2017
. Prior periods have not been adjusted.
The Company has elected to continue to estimate the number of stock-based awards expected to vest, as permitted by ASU 2016-09, rather than electing to account for forfeitures as they occur.
ASU 2016-09 requires that employee taxes paid when an employer withholds shares for tax-withholding purposes to be reported as financing activities in the statement of cash flows. Previously, these cash flows were included in operating activities. The Company has elected to adopt this prospectively, as permitted by ASU 2016-09. This change resulted in a
$1.1 million
impact on the statement of cash flow for the year ended
December 31, 2017
.
In October 2016, the FASB issued ASU No. 2016-17,
Consolidation (Topic 810): Interests Held through Related Parties that Are under Common Control
("ASU 2016-17"). ASU 2016-17 amends the consolidation guidance on how a reporting entity that is the single decision maker of a variable interest entity ("VIE") should treat indirect interests in the entity held through related parties that are under common control with the reporting entity when determining whether it is the primary beneficiary of that VIE. Under ASU 2016-17, a single decision maker of a VIE is required to consider indirect economic interests in the entity held through related parties on a proportionate basis when determining whether it is the primary beneficiary of that VIE. If a single decision maker and its related party are under common control, the single decision maker is required to consider indirect interests in the entity held through those related parties to be the equivalent of direct interests in their entirety. The amendments are effective for public business entities for fiscal years beginning after December 15, 2016 (the Company's first quarter of fiscal 2017), including interim periods within those fiscal years. Early adoption is permitted. The standard may be applied retrospectively or through a cumulative effect adjustment to retained earnings as of the beginning of the fiscal year of adoption. The Company adopted ASU 2016-17 effective January 1, 2017, and the adoption had no impact on the Company's consolidated financial statements.
In November 2016, the FASB issued ASU No. 2016-18,
Statement of Cash Flows (Topic 230): Restricted Cash
("ASU 2016-18"). ASU 2016-18 is intended to add and clarify guidance on the classification and presentation of restricted cash on the statement of cash flows. ASU 2016-18 requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. The amendments are effective for public business entities for fiscal
79
years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. The Company adopted ASU 2016-18 effective April 1, 2017, and has included restricted cash with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows.
Standards adopted in 2018
In May 2014, the FASB issued ASU No. 2014-09,
Revenue from Contracts with Customers
, which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The standard permits the use of either the retrospective or cumulative effect transition method. In December 2016, the FASB further issued ASU No. 2016-20,
Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers
, to increase stakeholders' awareness of the proposals and to expedite improvements to ASU 2014-09.
The FASB issued additional amendments to ASU No. 2014-09, as amended by ASU No. 2015-14:
|
•
|
March 2016 - ASU No. 2016-08,
Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net)
("ASU 2016-08"). ASU 2016-08 clarifies the implementation guidance on principal versus agent considerations. The guidance includes indicators to assist an entity in determining whether it controls a specified good or service before it is transferred to customers.
|
|
•
|
April 2016 - ASU No. 2016-10,
Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing
("ASU 2016-10"). ASU 2016-10 covers two specific topics: performance obligations and licensing. This amendment includes guidance on immaterial promised goods or services, shipping or handling activities, separately identifiable performance obligations, functional or symbolic intellectual property licenses, sales-based and usage-based royalties, license restrictions (time, use, geographical) and licensing renewals.
|
|
•
|
May 2016 - ASU No. 2016-12,
Revenue from Contracts with Customers (Topic 606): Narrow Scope Improvements and Practical Expedients
("ASU 2016-12"). ASU 2016-12 clarifies certain core recognition principles including collectability, sales tax presentation, noncash consideration, contract modifications and completed contracts at transition and disclosures no longer required if the full retrospective transition method is adopted.
|
|
•
|
September 2017 - ASU No. 2017-13,
Amendments to SEC Paragraphs Pursuant to the Staff Announcement at the July 20, 2017 EITF Meeting and Rescission of Prior SEC Staff Announcements and Observer Comments
("ASU 2017-13"). ASU 2017-13 provides additional implementation guidance related to ASC Topic 606 and is effective for annual reporting periods beginning after December 15, 2017.
|
|
•
|
November 2017 - ASU No. 2017-14,
Amendments to SEC Paragraphs Pursuant to Staff Accounting Bulletin No. 116 and SEC Release No. 33-10403
("ASU 2017-14"). ASU 2017-14 amends various paragraphs in ASC 605,
Revenue Recognition
; and ASC 606,
Revenue from Contracts With Customers
, that contain SEC guidance. The amendments include superseding ASC 605-10-S25-1 (SAB Topic 13) as a result of SEC Staff Accounting Bulletin No. 116 and adding ASC 606-10-S25-1 as a result of SEC Release No. 33-10403.
|
In 2017, we collaborated with an external professional services firm to analyze the impact of the standard on our contract portfolio by reviewing our current accounting policies and practices to identify potential differences that would result from applying the requirements of the new standard to our revenue contracts. In addition, we identified and implemented appropriate changes to our business processes, systems and controls to support recognition and disclosure under the new standard.
80
The Company adopted the new standard effective January 1, 2018 utilizing the full retrospective approach. The adoption of the new standard will result in an immaterial impact to our total revenues and operating income for the years ended December 31, 2017 and 2016, since our contracts with customers identify the delivery of products and services that are individually distinct performance obligations and revenue is recognized when performance obligations are satisfied. As a result, receivable balances related to revenue, including amounts related to unbilled revenue, are reflected as accounts receivable in the consolidated balance sheets. No other revenue related contract assets or liabilities are recorded.
The standard requires expanded disclosures regarding the qualitative and quantitative information of an entity's nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.
Note, the Company’s asset optimization activities meet the definition of trading activities per FASB ASC Topic 815,
Derivatives and Hedging,
and are therefore excluded from the scope of
Revenue from Contracts with Customers (Topic 606)
.
In August 2016, the FASB issued ASU No. 2016-15,
Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments
("ASU 2016-15"). ASU 2016-15 provides guidance on the presentation and classification of eight specific cash flow issues in the statement of cash flows. Those issues are cash payment for debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instrument or other debt instrument with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; cash proceeds from the settlement of insurance claims, cash received from settlement of corporate-owned life insurance policies; distribution received from equity method investees; beneficial interest in securitization transactions; and classification of cash receipts and payments that have aspects of more than one class of cash flows. The guidance is effective for interim and annual reporting periods beginning after December 15, 2017. This ASU is to be applied using a retrospective transition method for each period presented. The Company adopted ASU 2016-15 effective January 1, 2018 and will classify contingent consideration payments made after a business combination as cash outflows for operating and financing activities on a retrospective basis. Because of the change in accounting guidance, we expect to reclassify acquisition related payments of approximately
$1.8 million
and
$0.8 million
from cash flows from investing activities to cash flows from operating activities for the years ended December 31, 2017 and December 31, 2016, respectively. We expect to reclassify acquisition related payments of approximately
$18.4 million
and
$2.0 million
from cash flows from investing activities to cash flows from financing activities for the years ended December 31, 2017 and December 31, 2016, respectively.
In October 2016, the FASB issued ASU No. 2016-16,
Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory
(“ASU 2016-16”). ASU 2016-16 requires immediate recognition of the current and deferred income tax consequences of intercompany asset transfers other than inventory. Current U.S. GAAP prohibits the recognition of current and deferred income taxes for an intra-entity asset transfer until the asset has been sold to an outside party. This guidance is effective for annual and interim reporting periods of public entities beginning after December 15, 2017. This ASU is to be applied using a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. The Company adopted ASU 2016-16 effective January 1, 2018 and the adoption of this standard will not have an impact on the Company's consolidated financial statements.
In January 2017, the FASB issued ASU No. 2017-01,
Business Combinations (Topic 805): Clarifying the Definition of a Business
("ASU 2017-01"). ASU 2017-01 clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The definition of a business affects many areas of accounting, including acquisitions, disposals, goodwill, and consolidation. ASU 2017-01 is effective for annual periods beginning after December 15, 2017, including interim periods within those periods and is to be applied prospectively to transactions on or after the adoption date. The Company adopted ASU 2017-01 effective January 1, 2018, and the adoption will not have an impact on the Company's historical consolidated financial statements.
81
In May 2017, the FASB issued ASU No. 2017-09,
Compensation - Stock Compensation (Topic 718)
("ASU 2017-09"). ASU 2017-09 provides guidance on when changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting. An entity should account for the effects of a modification unless all of the following are met:
|
•
|
The fair value of the modified award is the same as the fair value of the original award immediately before the original award is modified
|
|
•
|
The vesting conditions of the modified award are the same as the vesting conditions of the original award immediately before the original award is modified
|
|
•
|
The classification of the modified award as an equity instrument or a liability instrument is the same as the classification of the original award immediately before the original award is modified.
|
The amendments in ASU 2017-09 are effective for all entities for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. The amendments are to be applied prospectively to an award modified on or after the adoption date. The Company adopted ASU 2017-09 effective January 1, 2018, and the adoption will not have an impact on the Company's consolidated financial statements.
Standards Being Evaluated/Standards Not Yet Adopted
In February 2016, the FASB issued ASU No. 2016-02,
Leases (Topic 842)
("ASU 2016-02"). ASU 2016-02 amends the existing accounting standards for lease accounting by requiring entities to include substantially all leases on the balance sheet by requiring the recognition of right-of-use assets and lease liabilities for all leases. Entities may elect to not recognize leases with a maximum possible term of less than 12 months. For lessees, a lease is classified as finance or operating and the asset and liability are initially measured at the present value of the lease payments. For lessors, accounting for leases is largely unchanged from previous guidance. ASU 2016-02 also requires qualitative disclosures along with certain specific quantitative disclosures for both lessees and lessors. The amendments in this ASU are effective for fiscal years beginning after December 15, 2018, with early adoption permitted, and are effective for interim periods in the year of adoption. The ASU should be applied using a modified retrospective approach, which requires lessees and lessors to recognize and measure leases at the beginning of the earliest period presented. The Company is currently evaluating the impact of adopting this guidance on its consolidated financial statements.
In January 2017, the FASB issued ASU No. 2017-04,
Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment
("ASU 2017-04"). ASU 2017-04 simplifies the subsequent measurement of goodwill by eliminating Step 2 from the goodwill impairment test. Under the amendments in 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. 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. The Company is currently evaluating the impact of adopting this guidance on its consolidated financial statements.
Contingencies
In the ordinary course of business, we may become party to lawsuits, administrative proceedings and governmental investigations, including regulatory and other matters. As of
December 31, 2017
, management does not believe that any of our outstanding lawsuits, administrative proceedings or investigations could result in a material adverse effect.
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.
82
For a discussion of the status of current litigation and governmental investigations, see Note
13 "Commitment and Contingencies"
in the Company’s audited consolidated financial statements.
Emerging Growth Company Status
We are an “emerging growth company” within the meaning of the federal securities laws. For as long as we are an emerging growth company, we will not be required to comply with certain requirements that are applicable to other public companies that are not “emerging growth companies” including, but not limited to, not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act, the reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements and the exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and shareholder approval of any golden parachute payments not previously approved. In addition, Section 107 of the JOBS Act provides that an emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards, but we have irrevocably opted out of the extended transition period and, as a result, we will adopt new or revised accounting standards on the relevant dates on which adoption of such standards is required for other public companies.
We intend to take advantage of these exemptions until we are no longer an emerging growth company. We will cease to be an “emerging growth company” upon the earliest of: (i) the last day of the fiscal year in which we have $1.07 billion or more in annual revenues; (ii) the date on which we become a “large accelerated filer” (the fiscal year-end on which the total market value of our common equity securities held by non-affiliates is $700 million or more as of June 30); (iii) the date on which we issue more than $1.0 billion of non-convertible debt over a three-year period; or (iv) the last day of 2019.
83
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 policies and procedures to manage 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. 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 a few years, depending on the instrument. Our asset optimization group utilizes similar derivative contracts in connection with its trading activities to attempt to generate incremental gross margin by effecting transactions in markets where we have a retail presence. Generally, any of 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 gain on non-trading derivative instruments, net of cash settlements, was
$22.1 million
for the year ended
December 31, 2017
.
We have adopted risk management policies to measure and limit market risk associated with our fixed-price portfolio and our hedging activities. For additional information regarding our commodity price risk and our risk management policies, see “Item 1A—Risk Factors."
We measure the commodity risk of our non-trading energy derivatives using a sensitivity analysis on our net open position. As of
December 31, 2017
, our Gas Non-Trading Fixed Price Open Position (hedges net of retail load) was a long position of
103,603
MMBtu. An increase in 10% in the market prices (NYMEX) from their
December 31, 2017
levels would have increased the fair market value of our net non-trading energy portfolio by
$0.1 million
. Likewise, a decrease in 10% in the market prices (NYMEX) from their
December 31, 2017
levels would have decreased the fair market value of our non-trading energy derivatives by
$0.1 million
. As of
December 31, 2017
, our Electricity Non-Trading Fixed Price Open Position (hedges net of retail load) was a long position of
280,424
MWhs. An increase in 10% in the forward market prices from their
December 31, 2017
levels would have increased the fair market value of our net non-trading energy portfolio by
$0.7 million
. Likewise, a decrease in 10% in the forward market prices from their
December 31, 2017
levels would have decreased the fair market value of our non-trading energy derivatives by
$0.7 million
.
Credit Risk
In many of the utility services territories where we conduct business, POR programs have been established, whereby the local regulated utility purchases our receivables, and becomes responsible for billing the customer and collecting payment from the customer. This service results in substantially all of our credit risk being linked to the applicable utility and not to our end-use customer in these territories. Approximately
66%
,
67%
and
56%
of our retail revenues were derived from territories in which substantially all of our credit risk was directly linked to local regulated utility companies as of
December 31, 2017
,
2016
and
2015
, respectively, all of which had investment grade ratings as of such date. During the same period, we paid these local regulated utilities a weighted average discount of approximately
1.1%
,
1.3%
and
1.4%
, respectively, of total revenues for customer credit risk protection. In certain of the POR markets in which we operate, the utilities limit their collections exposure by retaining the ability to transfer a delinquent account back to us for collection when collections are past due for a specified period.
If our collection efforts are unsuccessful, we return the account to the local regulated utility for termination of service. Under these service programs, we are exposed to credit risk related to payment for services rendered during
84
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, 2017
,
2016
and
2015
was approximately
2.5%
,
0.6%
and
5.0%
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
2017
.
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, 2017
and
2016
, approximately
84%
and
96%
of our total exposure of
$34.2 million
and
$14.6 million
, respectively, was either with an investment grade customer or otherwise 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, 2017
and
2016
.
Interest Rate Risk
We are exposed to fluctuations in interest rates under our variable-price debt obligations. At
December 31, 2017
, we were co-borrowers under the Senior Credit Facility, under which
$125.3 million
of variable rate indebtedness was outstanding. Based on the average amount of our variable rate indebtedness outstanding during the year ended
December 31, 2017
, a
1%
percent increase in interest rates would have resulted in additional annual interest expense of approximately
$1.3 million
. We do not currently employ interest rate hedges, although we may choose to do so in the future.
85
|
ITEM 8. FINANCIAL STATEMENTS
|
||
|
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
|
||
|
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
|
||
|
CONSOLIDATED BALANCE SHEETS AS OF DECEMBER 31, 2017 AND DECEMBER 31, 2016
|
|
|
|
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) FOR THE YEARS ENDED DECEMBER 31, 2017, 2016 AND 2015
|
|
|
|
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY FOR THE YEARS ENDED DECEMBER 31, 2017, 2016 AND 2015
|
|
|
|
CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 2017, 2016 AND 2015
|
|
|
|
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
86
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, 2017
, 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, 2017
.
As permitted, the business of Verde Energy USA, Inc.; Verde Energy USA Commodities, LLC; Verde Energy USA Connecticut, LLC; Verde Energy USA DC, LLC; Verde Energy USA Illinois, LLC; Verde Energy USA Maryland, LLC; Verde Energy USA Massachusetts, LLC; Verde Energy USA New Jersey, LLC; Verde Energy USA New York, LLC; Verde Energy USA Ohio, LLC; Verde Energy USA Pennsylvania, LLC; Verde Energy USA Texas Holdings, LLC; Verde Energy USA Trading, LLC; and Verde Energy Solutions, LLC (collectively, the “Verde Companies”), which the Company purchased on July 1, 2017, was excluded from the scope of management’s assessment of the effectiveness of our internal control over financial reporting as of
December 31, 2017
. The business constituted
21%
of the Company’s total assets as of
December 31, 2017
and
10%
of the Company’s consolidated revenues for the year ended
December 31, 2017
.
87
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholders and board of directors
Spark Energy, Inc.:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Spark Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2017 and 2016, the related consolidated statements of operations and comprehensive income, changes in equity, and cash flows for each of the years in the three‑year period ended December 31, 2017, and the related notes (collectively, the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the years in the three‑year period ended December 31, 2017, in conformity with U.S. generally accepted accounting principles.
Change in Accounting Principle
As discussed in Note 2 to the consolidated financial statements, the Company has changed its method of accounting for employee taxes paid for shares withheld for tax withholding purposes in the year ended December 31, 2017 due to the adoption of Accounting Standards Update No. 2016-09, “Improvements to Employee Share-Based Payment Accounting”.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ KPMG LLP
We have served as the Company’s auditor since 2011.
Houston, Texas
March 9, 2018
88
89
AUDITED CONSOLIDATED FINANCIAL STATEMENTS
SPARK ENERGY, INC.
90
|
December 31, 2017
|
December 31, 2016
|
|||||||
|
Assets
|
|
|
||||||
|
Current assets:
|
|
|
||||||
|
Cash and cash equivalents
|
$
|
29,419
|
|
$
|
18,960
|
|
||
|
Accounts receivable, net of allowance for doubtful accounts of $4.0 million and $2.3 million as of December 31, 2017 and 2016, respectively
|
158,814
|
|
112,491
|
|
||||
|
Accounts receivable
—
affiliates
|
3,661
|
|
2,624
|
|
||||
|
Inventory
|
4,470
|
|
3,752
|
|
||||
|
Fair value of derivative assets
|
31,191
|
|
8,344
|
|
||||
|
Customer acquisition costs, net
|
22,123
|
|
18,834
|
|
||||
|
Customer relationships, net
|
18,653
|
|
12,113
|
|
||||
|
Prepaid assets
|
1,028
|
|
1,361
|
|
||||
|
Deposits
|
7,701
|
|
7,329
|
|
||||
|
Other current assets
|
19,678
|
|
12,175
|
|
||||
|
Total current assets
|
296,738
|
|
197,983
|
|
||||
|
Property and equipment, net
|
8,275
|
|
4,706
|
|
||||
|
Fair value of derivative assets
|
3,309
|
|
3,083
|
|
||||
|
Customer acquisition costs, net
|
6,949
|
|
6,134
|
|
||||
|
Customer relationships, net
|
34,839
|
|
21,410
|
|
||||
|
Deferred tax assets
|
24,185
|
|
54,109
|
|
||||
|
Goodwill
|
120,154
|
|
79,147
|
|
||||
|
Other assets
|
11,500
|
|
8,658
|
|
||||
|
Total Assets
|
$
|
505,949
|
|
$
|
375,230
|
|
||
|
Liabilities, Series A Preferred Stock and Stockholders' Equity
|
|
|
||||||
|
Current liabilities:
|
|
|
||||||
|
Accounts payable
|
$
|
77,510
|
|
$
|
52,309
|
|
||
|
Accounts payable—affiliates
|
4,622
|
|
3,775
|
|
||||
|
Accrued liabilities
|
33,679
|
|
36,619
|
|
||||
|
Fair value of derivative liabilities
|
1,637
|
|
680
|
|
||||
|
Current portion of Senior Credit Facility
|
7,500
|
|
51,287
|
|
||||
|
Current payable pursuant to tax receivable agreement—affiliates
|
5,937
|
|
|
—
|
|
|||
|
Current contingent consideration for acquisitions
|
4,024
|
|
11,827
|
|
||||
|
Current portion of note payable
|
13,443
|
|
15,501
|
|
||||
|
Convertible subordinated notes to affiliates
|
—
|
|
6,582
|
|
||||
|
Other current liabilities
|
2,675
|
|
5,476
|
|
||||
|
Total current liabilities
|
151,027
|
|
184,056
|
|
||||
|
Long-term liabilities:
|
|
|
|
|
||||
|
Fair value of derivative liabilities
|
492
|
|
68
|
|
||||
|
Payable pursuant to tax receivable agreement—affiliates
|
26,355
|
|
49,886
|
|
||||
|
Long-term portion of Senior Credit Facility
|
117,750
|
|
—
|
|
||||
|
Subordinated debt—affiliate
|
—
|
|
5,000
|
|
||||
|
Contingent consideration for acquisitions
|
626
|
|
10,826
|
|
||||
|
Other long-term liabilities
|
172
|
|
1,658
|
|
||||
|
Long-term portion of note payable
|
7,051
|
|
|
—
|
|
|||
|
Total liabilities
|
303,473
|
|
251,494
|
|
||||
|
Commitments and contingencies (Note 13)
|
|
|
|
|
||||
|
Series A Preferred Stock, par value $0.01 per share, 20,000,000 shares authorized, 1,704,339 shares issued and outstanding at December 31, 2017 and zero shares issued and outstanding at December 31, 2016
|
41,173
|
|
—
|
|
||||
|
Stockholders' equity:
|
|
|
|
|
||||
|
Common Stock
(1)
:
|
|
|
|
|
||||
|
Class A common stock, par value $0.01 per share, 120,000,000 shares authorized, 13,235,082 issued and 13,135,636 outstanding at December 31, 2017 and 12,993,118 issued and outstanding at December 31, 2016
|
132
|
|
130
|
|
||||
|
Class B common stock, par value $0.01 per share, 60,000,000 shares authorized, 21,485,126 issued and outstanding at December 31, 2017 and 20,449,484 issued and outstanding at December 31, 2016
|
216
|
|
206
|
|
||||
|
Additional paid-in capital
(1)
|
26,914
|
|
25,272
|
|
||||
|
Accumulated other comprehensive (loss)/income
|
(11
|
)
|
11
|
|
||||
|
Retained earnings
|
11,008
|
|
4,711
|
|
||||
|
Treasury stock, at cost, 99,446 shares at December 31, 2017 and zero shares at December 31, 2016
|
(2,011
|
)
|
|
—
|
|
|||
|
Total stockholders' equity
|
36,248
|
|
30,330
|
|
||||
|
Non-controlling interest in Spark HoldCo, LLC
(1)
|
125,055
|
|
93,406
|
|
||||
|
Total equity
|
161,303
|
|
123,736
|
|
||||
|
Total Liabilities, Series A Preferred Stock and stockholders' equity
|
$
|
505,949
|
|
$
|
375,230
|
|
||
further discussion.
91
(1) Outstanding shares of common stock, additional paid-in capital and non-controlling interest reflect the
two
-for-one stock split, which took effect on June 16, 2017. See Note
4 "Equity"
for further discussion.
(2) See Note
4 "Equity"
for disclosure of our variable interest entity in Spark HoldCo, LLC.
The accompanying notes are an integral part of the consolidated financial statements.
92
SPARK ENERGY, INC.
(in thousands, except per share data)
|
|
Year Ended December 31,
|
||||||||||
|
|
2017
(1)
|
2016
(2)
|
2015
(3)
|
||||||||
|
Revenues:
|
|
|
|
||||||||
|
Retail revenues
|
$
|
798,772
|
|
|
$
|
547,283
|
|
|
$
|
356,659
|
|
|
Net asset optimization (expense)/revenues
(4)
|
(717
|
)
|
|
(586
|
)
|
|
1,494
|
|
|||
|
Total Revenues
|
798,055
|
|
|
546,697
|
|
|
358,153
|
|
|||
|
Operating Expenses:
|
|
|
|
||||||||
|
Retail cost of revenues
(5)
|
552,167
|
|
|
344,944
|
|
|
241,188
|
|
|||
|
General and administrative
(6)
|
101,127
|
|
|
84,964
|
|
|
61,682
|
|
|||
|
Depreciation and amortization
|
42,341
|
|
|
32,788
|
|
|
25,378
|
|
|||
|
Total Operating Expenses
|
695,635
|
|
|
462,696
|
|
|
328,248
|
|
|||
|
Operating income
|
102,420
|
|
|
84,001
|
|
|
29,905
|
|
|||
|
Other (expense)/income:
|
|
|
|
||||||||
|
Interest expense
|
(11,134
|
)
|
|
(8,859
|
)
|
|
(2,280
|
)
|
|||
|
Change in tax receivable agreement liability
|
22,267
|
|
|
—
|
|
|
—
|
|
|||
|
Interest and other income
|
256
|
|
|
957
|
|
|
324
|
|
|||
|
Total other expenses
|
11,389
|
|
|
(7,902
|
)
|
|
(1,956
|
)
|
|||
|
Income before income tax expense
|
113,809
|
|
|
76,099
|
|
|
27,949
|
|
|||
|
Income tax expense
|
37,528
|
|
|
10,426
|
|
|
1,974
|
|
|||
|
Net income
|
76,281
|
|
|
65,673
|
|
|
25,975
|
|
|||
|
Less: Net income attributable to non-controlling interests
|
57,427
|
|
|
51,229
|
|
|
22,110
|
|
|||
|
Net income attributable to Spark Energy, Inc. stockholders
|
$
|
18,854
|
|
|
$
|
14,444
|
|
|
$
|
3,865
|
|
|
Less: Dividend on Series A preferred stock
|
3,038
|
|
|
—
|
|
|
—
|
|
|||
|
Net income attributable to stockholders of Class A common stock
|
15,816
|
|
|
14,444
|
|
|
3,865
|
|
|||
|
Other comprehensive (loss) income, net of tax:
|
|
|
|||||||||
|
Currency translation (loss) gain
|
(59
|
)
|
|
41
|
|
|
—
|
|
|||
|
Other comprehensive (loss) income
|
(59
|
)
|
|
41
|
|
|
—
|
|
|||
|
Comprehensive income
|
76,222
|
|
|
65,714
|
|
|
25,975
|
|
|||
|
Less: Comprehensive income attributable to non-controlling interests
|
57,390
|
|
|
51,259
|
|
|
22,110
|
|
|||
|
Comprehensive income attributable to Spark Energy, Inc. stockholders
|
18,832
|
|
|
14,455
|
|
|
3,865
|
|
|||
|
Net income attributable to Spark Energy, Inc. per share of Class A common stock
|
|
|
|||||||||
|
Basic
|
$
|
1.20
|
|
$
|
1.27
|
|
$
|
0.63
|
|
||
|
Diluted
|
$
|
1.19
|
|
$
|
1.11
|
|
$
|
0.53
|
|
||
|
|
|
|
|||||||||
|
Weighted average shares of Class A common stock outstanding
|
|
|
|||||||||
|
Basic
|
13,143
|
|
11,402
|
|
6,129
|
|
|||||
|
Diluted
|
13,346
|
|
12,690
|
|
6,655
|
|
|||||
(1) Financial information includes results attributable to the acquisition of Perigee Energy, LLC by an affiliate on February 3, 2017. See Notes
2
and
3
"Basis of Presentation and Summary of Significant Accounting Policies" and "Acquisitions," respectively, for further discussion.
(2) Financial information includes results attributable to the acquisition of Major Energy Companies from an affiliate on April 15, 2016. See Notes
2
and
3
"Basis of Presentation and Summary of Significant Accounting Policies" and "Acquisitions," respectively, for further discussion.
(3) Financial information includes results attributable to the acquisition of Oasis Power Holdings LLC from an affiliate on May 12, 2015. See Notes
2
and
3
"Basis of Presentation and Summary of Significant Accounting Policies" and "Acquisitions," respectively, for further discussion.
(4)
Net asset optimization revenues includes asset optimization (expense)/revenues—affiliates of
$1,334
,
$154
and
$1,101
for the years ended
December 31, 2017
,
2016
and
2015
, respectively, and asset optimization revenues—affiliates cost of revenues of
$53
,
$1,633
and
$11,285
for the years ended
December 31, 2017
,
2016
and
2015
, respectively.
(5) Retail cost of revenues includes retail cost of revenues—affiliates of
$0
,
$9
and
$17
for the years
December 31, 2017
,
2016
and
2015
, respectively.
(6) General and administrative includes general and administrative expense—affiliates of
$24,700
,
$15,700
and
$0
for the years ended
December 31, 2017
,
2016
and
2015
, respectively.
The accompanying notes are an integral part of the consolidated financial statements.
93
SPARK ENERGY, INC.
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
FOR THE
YEARS ENDED
DECEMBER 31, 2017
,
2016
and
2015
(in thousands)
|
|
Issued Shares of Class A Common Stock
(1)
|
Issued Shares of Class B Common Stock
(1)
|
Treasury Stock
|
Class A Common Stock
(1)
|
Class B Common Stock
(1)
|
Treasury Stock
|
Accumulated Other Comprehensive Income (Loss)
|
Additional Paid-In Capital
(1)
|
Retained Earnings (Deficit)
|
Total Stockholders' Equity
|
Non-controlling Interest
(1)
|
Total Equity
|
|||||||||||||||||||||
|
Balance at 12/31/2014:
|
6,000
|
|
21,500
|
|
—
|
|
$
|
60
|
|
$
|
216
|
|
$
|
—
|
|
$
|
—
|
|
$
|
9,158
|
|
$
|
(775
|
)
|
$
|
8,659
|
|
$
|
15,458
|
|
$
|
24,117
|
|
|
Stock based compensation
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
2,165
|
|
—
|
|
2,165
|
|
—
|
|
2,165
|
|
|||||||||
|
Restricted stock unit vesting
|
238
|
|
—
|
|
—
|
|
2
|
|
—
|
|
—
|
|
—
|
|
185
|
|
—
|
|
187
|
|
—
|
|
187
|
|
|||||||||
|
Contribution from NuDevco
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
129
|
|
—
|
|
129
|
|
—
|
|
129
|
|
|||||||||
|
Consolidated net income
(2)
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
3,865
|
|
3,865
|
|
22,110
|
|
25,975
|
|
|||||||||
|
Beneficial conversion feature
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
789
|
|
—
|
|
789
|
|
—
|
|
789
|
|
|||||||||
|
Distributions paid to Class B non-controlling unit holders
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(15,587
|
)
|
(15,587
|
)
|
|||||||||
|
Dividends paid to Class A common shareholders
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(4,456
|
)
|
(4,456
|
)
|
—
|
|
(4,456
|
)
|
|||||||||
|
Balance at 12/31/2015:
|
6,238
|
|
21,500
|
|
—
|
|
$
|
62
|
|
$
|
216
|
|
$
|
—
|
|
$
|
—
|
|
$
|
12,426
|
|
$
|
(1,366
|
)
|
$
|
11,338
|
|
$
|
21,981
|
|
$
|
33,319
|
|
|
Stock based compensation
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
|
2,270
|
|
—
|
|
2,270
|
|
—
|
|
2,270
|
|
|||||||||
|
Restricted stock unit vesting
|
305
|
|
—
|
|
—
|
|
4
|
|
—
|
|
—
|
|
—
|
|
1,058
|
|
—
|
|
1,062
|
|
—
|
|
1,062
|
|
|||||||||
|
Excess tax benefit related to restricted stock vesting
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
186
|
|
—
|
|
186
|
|
—
|
|
186
|
|
|||||||||
|
Consolidated net income
(3)
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
14,444
|
|
14,444
|
|
51,229
|
|
65,673
|
|
|||||||||
|
Foreign currency translation adjustment for equity method investee
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
11
|
|
—
|
|
—
|
|
11
|
|
30
|
|
41
|
|
|||||||||
|
Beneficial conversion feature
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
243
|
|
—
|
|
243
|
|
—
|
|
243
|
|
|||||||||
|
Distributions paid to non-controlling unit holders
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(34,931
|
)
|
(34,931
|
)
|
|||||||||
|
Net contribution of the Major Energy Companies
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
3,873
|
|
3,873
|
|
|||||||||
|
Dividends paid to Class A common stockholders
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(8,367
|
)
|
(8,367
|
)
|
—
|
|
(8,367
|
)
|
|||||||||
|
Proceeds from disgorgement of stockholder short-swing profits
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
1,605
|
|
—
|
|
1,605
|
|
—
|
|
1,605
|
|
|||||||||
|
Tax impact from tax receivable agreement upon exchange of units of Spark HoldCo, LLC to shares of Class A Common Stock
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
4,768
|
|
—
|
|
4,768
|
|
—
|
|
4,768
|
|
|||||||||
94
|
Exchange of shares of Class B common stock to shares of Class A common stock
|
6,450
|
|
(6,450
|
)
|
—
|
|
64
|
|
(64
|
)
|
—
|
|
—
|
|
2,716
|
|
—
|
|
2,716
|
|
(2,716
|
)
|
—
|
|
|||||||||
|
Issuance of Class B Common Stock
|
—
|
|
5,400
|
|
—
|
|
—
|
|
54
|
|
—
|
|
—
|
|
—
|
|
—
|
|
54
|
|
53,940
|
|
53,994
|
|
|||||||||
|
Balance at 12/31/2016:
|
12,993
|
|
20,450
|
|
—
|
|
$
|
130
|
|
$
|
206
|
|
$
|
—
|
|
$
|
11
|
|
$
|
25,272
|
|
$
|
4,711
|
|
$
|
30,330
|
|
$
|
93,406
|
|
$
|
123,736
|
|
|
Stock based compensation
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
2,754
|
|
—
|
|
2,754
|
|
—
|
|
2,754
|
|
|||||||||
|
Restricted stock unit vesting
|
242
|
|
—
|
|
—
|
|
2
|
|
—
|
|
—
|
|
—
|
|
1,052
|
|
—
|
|
1,054
|
|
—
|
|
1,054
|
|
|||||||||
|
Consolidated net income
(4)
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
18,854
|
|
18,854
|
|
57,427
|
|
76,281
|
|
|||||||||
|
Foreign currency translation adjustment for equity method investee
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(22
|
)
|
—
|
|
—
|
|
(22
|
)
|
(37
|
)
|
(59
|
)
|
|||||||||
|
Distributions paid to non-controlling unit holders
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(33,800
|
)
|
(33,800
|
)
|
|||||||||
|
Net contribution by NG&E
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
274
|
|
274
|
|
|||||||||
|
Dividends paid to Class A common stockholders
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(9,519
|
)
|
(9,519
|
)
|
—
|
|
(9,519
|
)
|
|||||||||
|
Dividends to Preferred Stock
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(3,038
|
)
|
(3,038
|
)
|
—
|
|
(3,038
|
)
|
|||||||||
|
Proceeds from disgorgement of stockholder short-swing profits
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
708
|
|
—
|
|
708
|
|
—
|
|
708
|
|
|||||||||
|
Tax receivable agreement liability true-up
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(2,872
|
)
|
—
|
|
(2,872
|
)
|
—
|
|
(2,872
|
)
|
|||||||||
|
Conversion of Convertible Subordinated Notes to Class B Common Stock
|
—
|
|
1,035
|
|
—
|
|
—
|
|
10
|
|
—
|
|
—
|
|
—
|
|
—
|
|
10
|
|
7,785
|
|
7,795
|
|
|||||||||
|
Treasury Stock
|
—
|
|
—
|
|
(99
|
)
|
—
|
|
—
|
|
(2,011
|
)
|
—
|
|
—
|
|
—
|
|
(2,011
|
)
|
—
|
|
(2,011
|
)
|
|||||||||
|
Balance at 12/31/2017:
|
13,235
|
|
21,485
|
|
(99
|
)
|
$
|
132
|
|
$
|
216
|
|
$
|
(2,011
|
)
|
$
|
(11
|
)
|
$
|
26,914
|
|
$
|
11,008
|
|
$
|
36,248
|
|
$
|
125,055
|
|
$
|
161,303
|
|
(1) Outstanding shares of common stock, additional paid-in capital and non-controlling interest have been retrospectively adjusted to reflect the
two
-for-one stock split, which took effect on June 16, 2017. See Note 4 "Equity" for further discussion.
(2) Financial information includes results attributable to the acquisition of Oasis Power Holdings LLC from an affiliate on May 12, 2015. See Notes
2
and
3
"Basis of Presentation and Summary of Significant Accounting Policies" and "Acquisitions," respectively, for further discussion.
(3) Financial information includes results attributable to the acquisition of Major Energy Companies from an affiliate on April 15, 2016. See Notes
2
and
3
"Basis of Presentation and Summary of Significant Accounting Policies" and "Acquisitions," respectively, for further discussion.
(4) Financial information has been recast to include results attributable to the acquisition of Perigee Energy, LLC by an affiliate on February 3, 2017. See Notes
2
and
3
"Basis of Presentation and Summary of Significant Accounting Policies" and "Acquisitions," respectively, for further discussion.
The accompanying notes are an integral part of the consolidated financial statements.
95
SPARK ENERGY, INC.
FOR THE
YEARS ENDED
DECEMBER 31, 2017
,
2016
AND
2015
(in thousands)
|
|
Year Ended December 31,
|
||||||||||
|
|
2017
(1)
|
2016
(2)
|
2015
(3)
|
||||||||
|
Cash flows from operating activities:
|
|
|
|
|
|
||||||
|
Net income
|
$
|
76,281
|
|
|
$
|
65,673
|
|
|
$
|
25,975
|
|
|
Adjustments to reconcile net income to net cash flows provided by operating activities:
|
|
|
|
|
|
||||||
|
Depreciation and amortization expense
|
42,666
|
|
|
48,526
|
|
|
25,378
|
|
|||
|
Deferred income taxes
|
28,584
|
|
|
3,382
|
|
|
1,340
|
|
|||
|
Change in Tax Receivable Agreement liability
|
(22,267
|
)
|
|
—
|
|
|
—
|
|
|||
|
Stock based compensation
|
5,058
|
|
|
5,242
|
|
|
3,181
|
|
|||
|
Amortization of deferred financing costs
|
1,035
|
|
|
668
|
|
|
412
|
|
|||
|
Change in fair value of Earnout liabilities
|
(7,898
|
)
|
|
(297
|
)
|
|
—
|
|
|||
|
Accretion on fair value of Earnout liabilities
|
4,108
|
|
|
5,060
|
|
|
—
|
|
|||
|
Excess tax benefit related to restricted stock vesting
|
179
|
|
|
—
|
|
|
—
|
|
|||
|
Bad debt expense
|
6,550
|
|
|
1,261
|
|
|
7,908
|
|
|||
|
(Gain) loss on derivatives, net
|
(5,008
|
)
|
|
(22,407
|
)
|
|
18,497
|
|
|||
|
Current period cash settlements on derivatives, net
|
(19,598
|
)
|
|
(24,427
|
)
|
|
(23,948
|
)
|
|||
|
Accretion of discount to convertible subordinated notes to affiliate
|
1,004
|
|
|
—
|
|
|
—
|
|
|||
|
Other
|
(5
|
)
|
|
(407
|
)
|
|
(1,320
|
)
|
|||
|
Changes in assets and liabilities:
|
|
|
|
|
|
||||||
|
Decrease in restricted cash
|
—
|
|
|
—
|
|
|
707
|
|
|||
|
(Increase) decrease in accounts receivable
|
(32,361
|
)
|
|
(12,088
|
)
|
|
7,876
|
|
|||
|
Increase in accounts receivable
—
affiliates
|
(1,459
|
)
|
|
(118
|
)
|
|
(608
|
)
|
|||
|
(Increase) decrease in inventory
|
(718
|
)
|
|
542
|
|
|
4,544
|
|
|||
|
Increase in customer acquisition costs
|
(25,874
|
)
|
|
(21,907
|
)
|
|
(19,869
|
)
|
|||
|
Decrease in prepaid and other current assets
|
1,915
|
|
|
71
|
|
|
10,845
|
|
|||
|
(Increase) decrease in other assets
|
(465
|
)
|
|
1,321
|
|
|
(1,101
|
)
|
|||
|
Increase in customer relationships and trademarks
|
—
|
|
|
—
|
|
|
(2,776
|
)
|
|||
|
Increase (decrease) in accounts payable and accrued liabilities
|
14,831
|
|
|
14,831
|
|
|
(13,307
|
)
|
|||
|
Increase in accounts payable
—
affiliates
|
51
|
|
|
458
|
|
|
944
|
|
|||
|
(Decrease) increase in other current liabilities
|
(1,210
|
)
|
|
2,364
|
|
|
(645
|
)
|
|||
|
(Decrease) increase in other non-current liabilities
|
(1,487
|
)
|
|
45
|
|
|
1,898
|
|
|||
|
Net cash provided by
operating activities
|
63,912
|
|
67,793
|
|
45,931
|
|
|||||
|
Cash flows from investing activities:
|
|
|
|||||||||
|
Purchases of property and equipment
|
(1,704
|
)
|
|
(2,258
|
)
|
|
(1,766
|
)
|
|||
|
Acquisitions of CenStar and Oasis
|
—
|
|
—
|
|
(39,847
|
)
|
|||||
|
Acquisition of Major Energy Companies and Provider Companies
|
(1,853
|
)
|
(31,641
|
)
|
—
|
|
|||||
|
Acquisitions of Perigee and other customers
|
(11,759
|
)
|
|
—
|
|
|
—
|
|
|||
|
Acquisition of the Verde Companies
|
(69,538
|
)
|
|
—
|
|
|
—
|
|
|||
|
Payment of CenStar Earnout
|
—
|
|
(1,343
|
)
|
—
|
|
|||||
|
Payment of the Major Energy Companies Earnout
|
(7,403
|
)
|
|
—
|
|
|
—
|
|
|||
|
Payment of the Provider Companies Earnout
|
(5,500
|
)
|
|
—
|
|
|
—
|
|
|||
|
Contribution to equity method investment
|
—
|
|
(1,102
|
)
|
(330
|
)
|
|||||
|
Net cash used in investing activities
|
(97,757
|
)
|
(36,344
|
)
|
(41,943
|
)
|
|||||
|
Cash flows from financing activities:
|
|
|
|||||||||
|
Proceeds from issuance of Series A Preferred Stock, net of issuance costs paid
|
40,241
|
|
|
—
|
|
|
—
|
|
|||
|
Borrowings on notes payable
|
206,400
|
|
|
79,048
|
|
|
59,224
|
|
|||
|
Payments on notes payable
|
(152,939
|
)
|
|
(66,652
|
)
|
|
(49,826
|
)
|
|||
|
Issuance of convertible subordinated notes to affiliate
|
—
|
|
|
—
|
|
|
7,075
|
|
|||
|
Restricted stock vesting
|
(3,091
|
)
|
|
(1,183
|
)
|
|
(432
|
)
|
|||
|
Contributions from NuDevco
|
—
|
|
|
—
|
|
|
129
|
|
|||
|
Proceeds from issuance of Class B common stock
|
—
|
|
|
13,995
|
|
|
—
|
|
|||
|
Proceeds from disgorgement of stockholders short-swing profits
|
1,129
|
|
|
941
|
|
|
—
|
|
|||
|
Excess tax benefit related to restricted stock vesting
|
—
|
|
|
185
|
|
|
—
|
|
|||
|
Payment of dividends to Class A common shareholders
|
(9,519
|
)
|
|
(8,367
|
)
|
|
(4,456
|
)
|
|||
|
Payment of distributions to non-controlling unitholders
|
(33,800
|
)
|
|
(34,930
|
)
|
|
(15,587
|
)
|
|||
|
Payment of dividends to Preferred Stock
|
(2,106
|
)
|
|
—
|
|
|
—
|
|
|||
|
Purchase of Treasury Stock
|
(2,011
|
)
|
|
—
|
|
|
—
|
|
|||
|
Net cash provided by (used in) financing activities
|
44,304
|
|
|
(16,963
|
)
|
|
(3,873
|
)
|
|||
|
Increase in Cash and cash equivalents and Restricted Cash
|
10,459
|
|
|
14,486
|
|
|
115
|
|
|||
|
Cash and cash equivalents and Restricted cash—beginning of period
|
18,960
|
|
|
4,474
|
|
|
4,359
|
|
|||
|
Cash and cash equivalents and Restricted cash—end of period
|
$
|
29,419
|
|
|
$
|
18,960
|
|
|
$
|
4,474
|
|
|
Supplemental Disclosure of Cash Flow Information:
|
|
|
|
|
|
||||||
|
Non-cash items:
|
|
|
|
|
|
|
|
|
|||
96
|
Issuance of Class B common stock to affiliates for Major Energy Companies acquisition
|
$
|
—
|
|
|
$
|
40,000
|
|
|
$
|
—
|
|
|
Contingent consideration
—
earnout obligations incurred in connection with the Provider Companies and Major Energy Companies acquisitions
|
$
|
—
|
|
|
$
|
18,936
|
|
|
$
|
—
|
|
|
Assumption of legal liability in connection with the Major Energy Companies acquisition
|
$
|
—
|
|
|
$
|
5,000
|
|
|
$
|
—
|
|
|
Net contribution of the Major Energy Companies
|
$
|
—
|
|
|
$
|
3,873
|
|
|
$
|
—
|
|
|
Net contribution by NG&E in excess of cash
|
$
|
274
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Installment consideration incurred in connection with the Provider Companies acquisition
|
$
|
—
|
|
|
$
|
1,890
|
|
|
$
|
—
|
|
|
Installment consideration incurred in connection with the Verde Companies acquisition and Verde Earnout Termination Note
|
$
|
19,994
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Tax benefit from tax receivable agreement
|
$
|
(1,802
|
)
|
|
$
|
31,490
|
|
|
$
|
(64
|
)
|
|
Liability due to tax receivable agreement
|
$
|
4,674
|
|
|
$
|
(26,722
|
)
|
|
$
|
(55
|
)
|
|
Property and equipment purchase accrual
|
$
|
91
|
|
|
$
|
(32
|
)
|
|
$
|
45
|
|
|
CenStar Earnout accrual
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
500
|
|
|
Cash paid during the period for:
|
|
|
|
|
|
||||||
|
Interest
|
$
|
5,715
|
|
|
$
|
2,280
|
|
|
$
|
1,661
|
|
|
Taxes
|
$
|
11,205
|
|
|
$
|
7,326
|
|
|
$
|
216
|
|
(1) Financial information has been recast to include results attributable to the acquisition of Perigee Energy, LLC by an affiliate on February 3, 2017. See Notes
2
and
3
"Basis of Presentation and Summary of Significant Accounting Policies" and "Acquisitions," respectively, for further discussion.
(2) Financial information has been recast to include results attributable to the acquisition of the Major Energy Companies from an affiliate on April 15, 2016. See Notes
2
and
3
"Basis of Presentation and Summary of Significant Accounting Policies" and "Acquisitions," respectively, for further discussion.
(3) Financial information has been recast to include results attributable to the acquisition of Oasis Power Holdings LLC by an affiliate on May 12, 2015. See Note
2
"Basis of Presentation and Summary of Significant Accounting Policies" for further discussion.
The accompanying notes are an integral part of the consolidated financial statements.
97
SPARK ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Formation and Organization
Organization
Spark Energy, Inc. ("Spark Energy," “Company,” "we" or "us") is 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”). Spark HoldCo owns all of the outstanding membership interests or common stock in each of Spark Energy, LLC (“SE”), Spark Energy Gas, LLC (“SEG”), Oasis Power Holdings, LLC ("Oasis"), CenStar Energy Corp. ("CenStar"), Electricity Maine, LLC, Electricity N.H., LLC and Provider Power Mass, LLC (collectively, the "Provider Companies"); Major Energy Services, LLC, Major Energy Electric Services, LLC, and Respond Power, LLC (collectively, the "Major Energy Companies"), Perigee Energy, LLC ("Perigee"), and the Verde Companies (as defined below) the operating subsidiaries through which the Company operates. 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.
Relationship with our Founder and Majority Shareholder
W. Keith Maxwell, III (our "Founder") is the owner of a majority in voting power of our common stock through his ownership of NuDevco Retail, LLC ("NuDevco Retail") and Retailco, LLC ("Retailco"). Retailco is a wholly owned subsidiary of TxEx Energy Investments, LLC ("TxEx"), which is wholly owned by Mr. Maxwell. NuDevco Retail is a wholly owned subsidiary of NuDevco Retail Holdings LLC ("NuDevco Retail Holdings"), which is a wholly owned subsidiary of Electric HoldCo, LLC, which is also a wholly owned subsidiary of TxEx.
We entered into a Master Service Agreement effective January 1, 2016 with Retailco Services, LLC, which is wholly owned by W. Keith Maxwell III. See Note
14 "Transactions with Affiliates"
for further discussion.
Emerging Growth Company Status
As a company with less than
$1.07 billion
in revenues during its last fiscal year, the Company qualifies as an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012, or the JOBS Act. An emerging growth company may take advantage of specified reduced reporting and other regulatory requirements.
The Company will remain an “emerging growth company” until as late as the last day of the Company's 2019 fiscal year, or until the earliest of (i) the last day of the fiscal year in which the Company has
$1.07 billion
or more in annual revenues; (ii) the date on which the Company becomes a “large accelerated filer” (the fiscal year-end on which the total market value of the Company’s common equity securities held by non-affiliates is
$700 million
or more as of June 30); (iii) the date on which the Company issues more than
$1.0 billion
of non-convertible debt over a
three
-year period.
As a result of the Company's election to avail itself of certain provisions of the JOBS Act, the information that the Company provides may be different than what you may receive from other public companies in which you hold an equity interest.
Exchange and Registration Rights
The Spark HoldCo Third Amended and Restated Limited Liability Company Agreement provides that if the Company issues a new share of Class A common stock, par value
$0.01
per share (the "Class A common stock"), Series A Preferred Stock (as defined below), or other equity security of the Company (other than shares of Class B common stock, par value
$0.01
per share ("Class B common stock"), and excluding issuances of Class A common
98
stock upon an exchange of Class B common stock or Series A Preferred Stock), Spark HoldCo will concurrently issue a corresponding limited liability company unit either to the holder of the Class B common stock, or to the Company in the case of the issuance of shares of Class A common stock, Series A Preferred Stock or such other equity security. As a result, the number of Spark HoldCo units held by the Company always equals the number of shares of Class A common stock, Series A Preferred Stock or such other equity securities of the Company outstanding.
Each share of Class B common stock, all of which are held by NuDevco Retail and Retailco, has no economic rights but entitles the holder to
one
vote on all matters to be voted on by stockholders generally. Holders of Class A common stock and Class B common stock vote together as a single class on all matters presented to our stockholders for their vote or approval, except as otherwise required by applicable law or by our certificate of incorporation.
NuDevco Retail and Retailco have the right to exchange (the “Exchange Right”) all or a portion of their Spark HoldCo units (together with a corresponding number of shares of Class B common stock) for Class A common stock (or cash at Spark Energy, Inc.’s or Spark HoldCo’s election (the “Cash Option”)) at an exchange ratio of
one
share of Class A common stock for each Spark HoldCo unit (and corresponding share of Class B common stock) exchanged. In addition, NuDevco Retail and Retailco have the right, under certain circumstances, to cause the Company to register the offer and resale of NuDevco Retail's and Retailco's shares of Class A common stock obtained pursuant to the Exchange Right. Retail Acquisition Co., LLC ("RAC") was entitled to similar registration rights under the
$2.1 million
convertible subordinated note (the "CenStar Note") and
$5.0 million
convertible subordinated note (the "Oasis Note") prior to their respective conversions to Class B common stock in January 2017. Refer to Note
8 "Debt"
for further information.
Tax Receivable Agreement
The Company is party to a Tax Receivable Agreement with Spark HoldCo, NuDevco Retail Holdings and NuDevco Retail. This agreement generally provides for the payment by the Company to Retailco, LLC (as successor to NuDevco Retail Holdings) and NuDevco Retail of
85%
of the net cash savings, if any, in U.S. federal, state and local income tax or franchise tax that the Company actually realizes (or is deemed to realize in certain circumstances) in future periods as a result of (i) any tax basis increases resulting from the purchase by the Company of Spark HoldCo units from NuDevco Retail Holdings, (ii) any tax basis increases resulting from the exchange of Spark HoldCo units for shares of Class A common stock pursuant to the Exchange Right (or resulting from an exchange of Spark HoldCo units for cash pursuant to the Cash Option) and (iii) any imputed interest deemed to be paid by the Company as a result of, and additional tax basis arising from, any payments the Company makes under the Tax Receivable Agreement. The Company retains the benefit of the remaining 15% of these tax savings. See Note
12 "Income Taxes"
for further discussion.
In certain circumstances, the Company may defer or partially defer any payment due (a “TRA Payment”) to the holders of rights under the Tax Receivable Agreement, which are currently Retailco and NuDevco Retail. During the
five
-year period ending September 30, 2019, the Company will defer all or a portion of any TRA Payment owed pursuant to the Tax Receivable Agreement to the extent that Spark HoldCo does not generate sufficient Cash Available for Distribution (as defined below) during the
four
-quarter period ending September 30th of the applicable year in which the TRA Payment is to be made in an amount that equals or exceeds
130%
(the “TRA Coverage Ratio”) of the Total Distributions (as defined below) paid in such four-quarter period by Spark HoldCo. For purposes of computing the TRA Coverage Ratio:
|
•
|
“Cash Available for Distribution” is generally defined as the Adjusted EBITDA of Spark HoldCo for the applicable period, less (i) cash interest paid by Spark HoldCo, (ii) capital expenditures of Spark HoldCo (exclusive of customer acquisition costs) and (iii) any taxes payable by Spark HoldCo; and
|
|
•
|
“Total Distributions” are defined as the aggregate distributions necessary to cause the Company to receive distributions of cash equal to (i) the targeted quarterly distribution the Company intends to pay to holders of its Class A common stock and Series A Preferred Stock payable during the applicable four-quarter period,
|
99
plus (ii) the estimated taxes payable by the Company during such four-quarter period, plus (iii) the expected TRA Payment payable during the calendar year for which the TRA Coverage Ratio is being tested.
In the event that the TRA Coverage Ratio is not satisfied in any calendar year, the Company will defer all or a portion of the TRA Payment to NuDevco Retail or Retailco under the Tax Receivable Agreement to the extent necessary to permit Spark HoldCo to satisfy the TRA Coverage Ratio (and Spark HoldCo is not required to make and will not make the pro rata distributions to its members with respect to the deferred portion of the TRA Payment). If the TRA Coverage Ratio is satisfied in any calendar year, the Company will pay NuDevco Retail or Retailco the full amount of the TRA Payment.
Following the
five
-year deferral period ending September 30, 2019, the Company will be obligated to pay any outstanding deferred TRA Payments to the extent such deferred TRA Payments do not exceed (i) the lesser of the Company's proportionate share of aggregate Cash Available for Distribution of Spark HoldCo during the
five
-year deferral period or the cash distributions actually received by the Company during the
five
-year deferral period, reduced by (ii) the sum of (a) the aggregate target quarterly dividends (which, for the purposes of the Tax Receivable Agreement, will be
$0.18125
per Class A common stock share and
$0.546875
per Series A Preferred Stock share per quarter) during the
five
-year deferral period, (b) the Company's estimated taxes during the
five
-year deferral period, and (c) all prior TRA Payments and (d) if with respect to the quarterly period during which the deferred TRA Payment is otherwise paid or payable, Spark HoldCo has or reasonably determines it will have amounts necessary to cause the Company to receive distributions of cash equal to the target quarterly distribution payable during that quarterly period. Any portion of the deferred TRA Payments not payable due to these limitations will no longer be payable.
We met the threshold coverage ratio required to fund the second TRA Payment to Retailco and NuDevco Retail under the Tax Receivable Agreement during the four-quarter period ending September 30, 2016, resulting in an initial TRA Payment of
$1.4 million
becoming due in December 2016. On November 6, 2016, Retailco and NuDevco Retail granted the Company the right to defer the TRA Payment until May 2018. During the period of time when the Company has elected to defer the TRA Payment, the outstanding payment amount will accrue interest at a rate calculated in the manner provided for under the Tax Receivable Agreement. The initial payment of
$1.4 million
deferred until May 2018 was classified to a current liability as of
December 31, 2017
.
We met the threshold coverage ratio required to fund the third TRA Payment to Retailco and NuDevco Retail under the Tax Receivable Agreement during the four-quarter periods ending September 30, 2017. As such, the third payment under the Tax Receivable Agreement due in April 2018 has been classified as current in our consolidated balance sheet at
December 31, 2017
.
We expect to meet the threshold coverage ratio required to fund the fourth payment to Retailco and NuDevco Retail under the Tax Receivable Agreement during the four-quarter period ending September 30, 2018. As such, the fourth payment under the Tax Receivable Agreement due in late 2018 has been classified as current in our consolidated balance sheet at
December 31, 2017
.
2. Basis of Presentation and Summary of Significant Accounting Policies
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”). The Company's consolidated 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.
Transactions with Affiliates
The Company enters into transactions with and pays certain costs on behalf of affiliates that are commonly controlled by W. Keith Maxwell III, and these affiliates enter into transactions with and pay certain costs on our behalf, 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, certain services to the affiliated companies associated with employee benefits provided through the Company’s benefit plans, insurance plans, leased office space, administrative salaries for management due diligence work, recurring management consulting, and accounting, tax, legal, or technology services 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
14 "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. Accounts receivable in the consolidated balance sheets are net of allowance for doubtful accounts of
$4.0 million
and
$2.3 million
as of
December 31, 2017
and
2016
, respectively.
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
$6.6 million
,
$1.3 million
and
$7.9 million
was recorded in general and administrative expense in the consolidated statements of operations for the years ended
December 31, 2017
,
2016
and
2015
, 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 that its susceptibility to an individually significant write-off as a result of concentrations of customer accounts receivable with those utilities is remote. 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
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Company’s customers are individually insignificant and geographically dispersed in these markets. The Company writes off customer balances when it believes that amounts are no longer collectible and when it has exhausted all means to collect these receivables.
Inventory
Inventory consists of natural gas used to fulfill and manage seasonality for fixed and variable-price retail customer load requirements and is valued at the lower of weighted average cost or market. Purchased natural gas costs are recognized in the consolidated statements of operations, within retail cost of revenues, when the natural gas is sold and delivered out of the storage facility. There were
no
inventory impairments recorded for the years ended
December 31, 2017
,
2016
and
2015
. When natural gas is sold costs are recognized in the consolidated statements of operations, within retail cost of revenues, at the weighted average cost value at the time of the sale.
Customer Acquisition Costs
The Company has retail natural gas and electricity customer acquisition costs, net of
$22.1 million
and
$18.8 million
recorded in current assets and
$6.9 million
and
$6.1 million
recorded in noncurrent assets representing direct response advertising costs as of
December 31, 2017
and
2016
, respectively. Customer acquisition costs are spending for organic customer acquisitions and do not include customer acquisitions through merger and acquisition activities, which are recorded as customer relationships. Amortization of customer acquisition costs, recorded in depreciation and amortization in the consolidated statements of operations, was
$21.4 million
,
$17.5 million
and
$18.0 million
for the years ended
December 31, 2017
,
2016
and
2015
, respectively. Capitalized direct response advertising costs consist primarily of hourly and commission based telemarketing costs, door-to-door agent commissions and other direct advertising costs associated with proven customer generation, and are capitalized and amortized over the estimated
two
-year average life of a customer in accordance with the provisions of FASB ASC 340-20,
Capitalized Advertising Costs
.
Recoverability of customer acquisition costs is evaluated based on a comparison of the carrying amount of the customer acquisition 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 acquisitions through direct acquisitions of customer contracts or recorded as part of the acquisition method in accordance with FASB ASC Topic 805,
Business Combinations
("ASC 805") are recorded as customer relationships and represent customer contract acquisitions not acquired through the direct response advertising discussed above at “
Customer Acquisition Costs.
” The Company has recorded
$18.7 million
and
$12.1 million
, net of amortization, as current assets as of
December 31, 2017
and
2016
, respectively, and
$34.8 million
and
$21.4 million
, net of amortization, as non-current assets as of
December 31, 2017
and
2016
, 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 years
to
six years
.
The acquired customer relationships intangibles related to Oasis, CenStar, Provider Companies, Major Energy Companies, Perigee Energy LLC, and Verde Companies 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 and Perigee 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
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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.
Amortization expense was
$17.8 million
,
$28.6 million
, and
$5.7 million
for the years ended
December 31, 2017
,
2016
and
2015
, respectively. Approximately
$0.3 million
,
$15.8 million
, and
zero
of the
$17.8 million
,
$28.6 million
, and
$5.7 million
customer relationships amortization expense for the twelve months ending
December 31, 2017
,
2016
, and
2015
, respectively, was included in retail cost of revenue.
We review customer relationships for impairment whenever events or changes in business circumstances indicate the carrying value of the intangible assets may not be recoverable. Impairment is indicated when the undiscounted cash flows estimated to be generated by the intangible assets are less than their respective carrying value. If an impairment exists, a loss would be 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,
2017
,
2016
and
2015
.
Non-compete agreements
The 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 members. The fair values of non-compete agreements are determined using the differential valuation approach at acquisition date. Under this approach, the Company estimates the present value of expected future cash flows under two scenarios; one scenario assumes the non-compete agreements are in place and the other scenario assumes the absence of non-compete agreements. The resulting difference between the two scenarios is the implied value of the non-compete agreements, which is further adjusted by an estimated probability factor representing the likelihood that previous members of acquired companies would be successful competitors.
As a result of the Provider Companies and Major Energy Companies acquisitions, the Company recorded
$1.2 million
, net of amortization, as Acquired customer intangibles - current and
$1.4 million
, net of amortization, as Acquired customer intangibles - non-current as of December 31, 2016 related to these non-compete agreements. These non-compete agreements are amortized over their estimated
three
-year life on a straight-line basis. Amortization expense was
$1.2 million
and
$0.9 million
for the years ended
December 31, 2017
and
2016
.
Trademarks
Trademarks recorded as part of the acquisition method in accordance with ASC 805 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. 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.
The Company has recorded
$8.6 million
and
$6.3 million
, net of amortization, as other assets as of
December 31, 2017
and
2016
related to these trademarks in other assets. These intangibles are amortized over the estimated
five
-year to
twenty
-year life of the trademarks on a straight-line basis. Amortization expense was
$0.8 million
,
$0.4 million
and
$0.1 million
for the years ended
December 31, 2017
,
2016
and
2015
, 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 would be recognized for the difference between the fair value and carrying value of the intangible assets.
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No
impairments of trademarks were recorded for the years ended December 31,
2017
,
2016
and
2015
.
Deferred Financing Costs
Costs incurred in connection with the issuance of long-term debt are capitalized and amortized to interest expense using the straight-line method over the life of the related long-term debt due to the variable nature of the Company’s long-term debt.
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. When assets are placed into service, management makes estimates with respect to useful lives and 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 internal-use software projects in accordance with FASB ASC Topic 350-40,
Internal-Use Software
. Capitalized costs are the costs incurred during the application development stage of the internal-use software project such as software configuration, coding, installation of hardware and testing. Costs incurred during the preliminary or post-implementation stage of the internal-use software project are expensed in the period incurred. These types of costs include 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 capitalized in accordance with FASB ASC Topic 835-20,
Capitalization of Interest
. Capitalized interest costs for the years ended
December 31, 2017
,
2016
and
2015
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, 2017
is associated with both our Retail Natural Gas and Retail Electricity reporting units. We determine our reporting units 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 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. On October 31, 2017, we elected to by-pass the option to perform a qualitative assessment of goodwill and performed a quantitative assessment of goodwill in accordance with guidance from ASC 350. This guidance permits an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. If we fail the qualitative test or if we elect to by-pass the qualitative assessment, then we must compare our estimate of the fair value of a reporting unit with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, we perform the second step of the goodwill impairment test to measure the amount of goodwill impairment loss to be recorded, as necessary. The second step compares the implied fair value of the reporting unit’s goodwill to the carrying value, if any, of that goodwill. We determine the implied fair value of the goodwill in the same manner as determining the amount of goodwill to be recognized in a business combination. The inputs used in the determination of fair value are generally level 3 inputs. See Note
9 "Fair Value Measurements"
for further discussion.
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We completed our annual assessment of goodwill impairment as of October 31, 2017 during the fourth quarter of 2017, and the test indicated
no
impairment.
Treasury Stock
Treasury stock consists of Company's own stock that has been issued, but is 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. Accounting for treasury stock transactions is governed by FASB ASC Topic 550-30
Equity-Treasury Stock.
We use the cost method to account for treasury shares. Purchases of shares of Class A common stock are recorded at cost, and the gross cost of the Class A common stock purchased is charged to a contra equity account entitled "Treasury Stock."
Equity Method Investment
The Company accounts for investments in unconsolidated entities using the equity method of accounting, as prescribed in FASB ASC Topic 323-10,
Investments-Equity Method and Joint Venture,
if the investment gives us the ability to exercise significant influence over, but not control, of an investee. Significant influence generally exists if we have an ownership interest representing between 20% and 50% of the voting stock of the investee. Under the equity method of accounting, investments are stated at initial cost and are adjusted for subsequent additional investments and our proportionate share of earnings or losses and distributions. Such investment is presented on the consolidated balance sheet under "Other assets" and our share of their income as "Interest and other income" on the consolidated statements of operations. The Company determines its equity investment earnings using the Hypothetical Liquidation at Book Value (HLBV) method. Under the HLBV method, a calculation is prepared at each balance sheet date to determine the amount the Company would receive if the investee were to liquidate all of its assets, as valued in accordance with U.S. GAAP, and distribute that cash to the investors. The difference between the calculated liquidation distribution amounts at the beginning and the end of the reporting period, after adjusting for capital contributions and distributions, is the Company's share of the earnings or losses from the equity investment for the period. See Note
17 "Equity Method Investment"
for further discussion.
Segment Reporting
The FASB ASC Topic 280,
Segment Reporting
, established standards for entities to report information about the operating segments and geographic areas in which they operate. The Company operates
two
segments, retail natural gas and retail electricity, and all of its operations are located in the United States.
Revenues and Cost of Revenues
The Company’s revenues are derived primarily from the sale of natural gas and electricity to retail customers. The Company also records revenue from sales of natural gas and electricity to wholesale counterparties, including affiliates. Revenues are recognized by the Company using the following criteria: (1) persuasive evidence of an exchange arrangement exists, (2) delivery has occurred or services have been rendered, (3) the buyer’s price is fixed or determinable and (4) collection is reasonably assured. Utilizing these criteria, revenue is recognized when the natural gas or electricity is delivered. Similarly, cost of revenues is recognized when the commodity is delivered.
Revenues for natural gas and electricity sales are recognized upon delivery 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.
104
The Company records gross receipts taxes on a gross basis in retail revenues and retail cost of revenues. During the years ended
December 31, 2017
,
2016
and
2015
, the Company’s retail revenues and retail cost of revenues included gross receipts taxes of
$9.0 million
,
$5.3 million
and
$3.0 million
, respectively.
Costs for natural gas and electricity sales are recognized as the commodity is delivered to the customer 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.
The Company’s asset optimization activities, which primarily include natural gas physical arbitrage and other short term storage and transportation opportunities, meet the definition of trading activities and are recorded on a net basis in the consolidated statements of operations in net asset optimization revenues pursuant to FASB ASC Topic 815,
Derivatives and Hedging
. The Company recorded asset optimization revenues, primarily related to physical sales or purchases of commodities, of
$178.3 million
,
$133.0 million
and
$154.1 million
for the years ended
December 31, 2017
,
2016
and
2015
, respectively, and recorded asset optimization costs of revenues of
$179.0 million
,
$133.6 million
and
$152.6 million
for the years ended
December 31, 2017
,
2016
and
2015
, 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 results 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 an estimated net realizable value. The Company recorded an imbalance receivable of
$0.7 million
and
$0.9 million
recorded in other current assets on the consolidated balance sheets as of
December 31, 2017
and
2016
, respectively. The Company recorded an imbalance payable of
$1.0 million
and
$0.1 million
recorded in other current liabilities on the consolidated balance sheets as of
December 31, 2017
and
2016
, respectively.
Fair Value
FASB ASC Topic 820,
Fair Value Measurement
, established a single authoritative definition of fair value, set out a framework for measuring fair value, and requires disclosures about fair value measurements. The standard clarifies that fair value is an exit price, representing the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. The standard utilizes a fair value hierarchy that prioritizes the inputs to the valuation techniques used to measure fair value into three broad levels based on quoted prices in active market, observable market prices, and unobservable market prices.
When the Company is required to measure fair value, and there is not a quoted or observable market price for a similar asset or liability, the Company utilizes the cost, income, or market valuation approach depending on the quality of information available to support management’s assumptions.
Derivative Instruments
The Company uses derivative instruments such as futures, swaps, forwards and options to manage the commodity price risks of its business operations.
All derivatives, other than those for which an exception applies, 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. The Company has elected to offset
105
amounts in the consolidated balance sheets for derivative instruments executed with the same counterparty under a master netting arrangement. One of the exceptions to fair value accounting, normal purchases and normal sales, has been elected by the Company for certain derivative instruments when the contract satisfies certain criteria, including a requirement that physical delivery of the underlying commodity is probable and is expected to be used in normal course of business. Retail revenues and retail cost of revenues resulting from deliveries of commodities under normal purchase contracts and normal sales contracts are included in earnings at the time of contract settlement.
To manage commodity price risk, the Company holds certain derivative instruments that are not held for trading purposes and are not designated as hedges for accounting purposes. However, to the extent the Company does not hold offsetting positions for such derivatives, they believe these instruments represent economic hedges that mitigate their exposure to fluctuations in commodity prices. As part of the Company’s strategy to optimize its assets and manage related commodity risks, it also manages a portfolio of commodity derivative instruments held for trading purposes. The Company uses established policies and procedures to manage the risks associated with price fluctuations in these energy commodities and uses derivative instruments to reduce risk by generally creating offsetting market positions.
Changes in the fair value of and amounts realized upon settlement of derivative instruments not held for trading purposes are recognized currently in retail costs of revenues.
Changes in the fair value of and amounts realized upon settlement of derivative instruments held for trading purposes are recognized currently in earnings in net asset optimization revenues.
Income Taxes
The Company recognizes the amount of taxes payable or refundable for the year. In addition, the Company follows the asset and liability method of accounting for income taxes where deferred tax assets and liabilities are recognized for the expected future tax consequences of events that have been recognized in the financial statements or tax returns and operating loss carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in those years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in the tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is provided for deferred tax assets if it is more likely than not that these items will not be realized.
In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the projected future taxable income and tax planning strategies in making this assessment. Based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that we will realize the benefits of these deductible differences.
The Company recognizes interest and penalties related to unrecognized tax benefits within the provision for income taxes on continuing operations in our consolidated statements of operations.
Earnings per Share
Basic earnings per share (“EPS”) is computed by dividing net income attributable to shareholders (the numerator) by the weighted-average number of Class A common shares outstanding for the period (the denominator). Class B common shares are not included in the calculation of basic earnings per share because they are not participating securities and have no economic interest in the Company. Diluted earnings per share is similarly calculated except that the denominator is increased (1) using the treasury stock method to determine the potential dilutive effect of the Company’s outstanding unvested restricted stock units, (2) using the if-converted method to determine the potential dilutive effect of the Company’s Class B common stock and (3) using the if-converted method to determine the
106
potential dilutive effect of the outstanding convertible subordinated notes into the Company's Class B common stock.
On May 22, 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"). All shares and per share amounts in this report have been retrospectively restated to reflect the Stock Split.
Non-controlling Interest
The Company and NuDevco Retail and Retailco owned the following economic interests in Spark HoldCo at
December 31, 2016
and
December 31, 2017
, respectively.
|
The Company
|
NuDevco Retail and Retailco
(1) (2)
|
|
|
On December 31, 2016
|
38.85%
|
61.15%
|
|
On December 31, 2017
|
38.12%
|
61.88%
|
|
(1) In January 2016, Retailco succeeded to the interest of NuDevco Retail Holdings of its Class B common stock and an equal number of Spark HoldCo units it held pursuant to a series of transfers.
|
||
|
(2) In January 2017, Retailco converted the CenStar Note and Oasis Note to 269,462 and 766,180 shares, respectively, of Class B common stock.
|
||
See Note
4 "Equity"
for further detail.
Net income attributable to non-controlling interest for the years ended
December 31, 2017
and
2016
represents NuDevco’s interest in Spark HoldCo. Income and expenses specifically attributable to the non-controlling interest and the Company are allocated accordingly (for example income tax expense (benefit), gain related to the remeasurement of the TRA liability as a result of U.S. Tax Reform, and income (loss) related to recast financial statements). The weighted average ownership percentages for the applicable reporting period are used to allocate the remaining income (loss) before income taxes to the each economic interest owner.
Commitments and Contingencies
The Company enters into various firm purchase and sale commitments for natural gas, storage, transportation, and electricity that do not meet the definition of a derivative instrument. Management does not anticipate that such commitments will result in any significant gains or losses based on current market conditions.
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.
Use of Estimates and Assumptions
The preparation of the Company’s consolidated financial statements requires estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the period. Actual results could materially differ from those estimates. Significant items subject to such estimates by the Company’s management include estimates for unbilled revenues and related cost of revenues, provisions for uncollectible receivables, valuation of customer acquisition costs, estimated useful lives of property and equipment, valuation of derivatives and reserves for contingencies.
Subsequent Events
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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. See Note
18 "Subsequent Events"
for further discussion.
Reclassifications
Certain amounts in the prior period financial statements have been reclassified to conform to the current period presentation. These reclassifications had no effect on reported earnings.
Recent Accounting Pronouncements
Adopted Standards
In March 2016, the FASB issued ASU No. 2016-09,
Compensation - Stock Compensation (Topic 718)
("ASU 2016-09"). ASU 2016-09 includes provisions intended to simplify various aspects of accounting for shared-based payments, including income tax consequences, classification of awards as either equity or liability and classification on the statement of cash flows. This guidance is effective for annual and interim reporting periods of public entities beginning after December 15, 2016. The Company adopted ASU 2016-09 on January 1, 2017.
The new standard requires prospective recognition of excess tax benefits resulting from stock-based compensation vesting and exercises to be recognized as a reduction of income taxes and reflected in operating cash flows. Previously, these amounts were recognized in additional paid-in capital and presented as a financing activity on the statement of cash flows. Net excess tax benefits of
$0.2 million
were recognized as a reduction of income taxes for the year ended
December 31, 2017
. Prior periods have not been adjusted.
The Company has elected to continue to estimate the number of stock-based awards expected to vest, as permitted by ASU 2016-09, rather than electing to account for forfeitures as they occur.
ASU 2016-09 requires that employee taxes paid when an employer withholds shares for tax-withholding purposes to be reported as financing activities in the statement of cash flows. Previously, these cash flows were included in operating activities. The Company has elected to adopt this prospectively, as permitted by ASU 2016-09. This change resulted in a
$1.1 million
impact on the statement of cash flow for the year ended
December 31, 2017
.
In October 2016, the FASB issued ASU No. 2016-17,
Consolidation (Topic 810): Interests Held through Related Parties that Are under Common Control
("ASU 2016-17"). ASU 2016-17 amends the consolidation guidance on how a reporting entity that is the single decision maker of a variable interest entity ("VIE") should treat indirect interests in the entity held through related parties that are under common control with the reporting entity when determining whether it is the primary beneficiary of that VIE. Under ASU 2016-17, a single decision maker of a VIE is required to consider indirect economic interests in the entity held through related parties on a proportionate basis when determining whether it is the primary beneficiary of that VIE. If a single decision maker and its related party are under common control, the single decision maker is required to consider indirect interests in the entity held through those related parties to be the equivalent of direct interests in their entirety. The amendments are effective for public business entities for fiscal years beginning after December 15, 2016 (the Company's first quarter of fiscal 2017), including interim periods within those fiscal years. The standard is to be applied retrospectively or through a cumulative effect adjustment to retained earnings as of the beginning of the fiscal year of adoption. The Company adopted ASU 2016-17 effective January 1, 2017, and the adoption had no impact on the Company's consolidated financial statements.
In November 2016, the FASB issued ASU No. 2016-18,
Statement of Cash Flows (Topic 230): Restricted Cash
("ASU 2016-18"). ASU 2016-18 is intended to add and clarify guidance on the classification and presentation of restricted cash on the statement of cash flows. ASU 2016-18 requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents
108
should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. The amendments are effective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The Company adopted ASU 2016-18 effective April 1, 2017, and has included restricted cash with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows.
Standards adopted in 2018
In May 2014, the FASB issued ASU No. 2014-09,
Revenue from Contracts with Customers
, which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The standard permits the use of either the retrospective or cumulative effect transition method. In December 2016, the FASB further issued ASU No. 2016-20,
Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers
, to increase stakeholders' awareness of the proposals and to expedite improvements to ASU 2014-09.
The FASB issued additional amendments to ASU No. 2014-09, as amended by ASU No. 2015-14:
|
•
|
March 2016 - ASU No. 2016-08,
Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net)
("ASU 2016-08"). ASU 2016-08 clarifies the implementation guidance on principal versus agent considerations. The guidance includes indicators to assist an entity in determining whether it controls a specified good or service before it is transferred to customers.
|
|
•
|
April 2016 - ASU No. 2016-10,
Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing
("ASU 2016-10"). ASU 2016-10 covers two specific topics: performance obligations and licensing. This amendment includes guidance on immaterial promised goods or services, shipping or handling activities, separately identifiable performance obligations, functional or symbolic intellectual property licenses, sales-based and usage-based royalties, license restrictions (time, use, geographical) and licensing renewals.
|
|
•
|
May 2016 - ASU No. 2016-12,
Revenue from Contracts with Customers (Topic 606): Narrow Scope Improvements and Practical Expedients
("ASU 2016-12"). ASU 2016-12 clarifies certain core recognition principles including collectability, sales tax presentation, noncash consideration, contract modifications and completed contracts at transition and disclosures no longer required if the full retrospective transition method is adopted.
|
|
•
|
September 2017 - ASU No. 2017-13,
Amendments to SEC Paragraphs Pursuant to the Staff Announcement at the July 20, 2017 EITF Meeting and Rescission of Prior SEC Staff Announcements and Observer Comments
("ASU 2017-13"). ASU 2017-13 provides additional implementation guidance related to ASC Topic 606 and is effective for annual reporting periods beginning after December 15, 2017.
|
|
•
|
November 2017 - ASU No. 2017-14,
Amendments to SEC Paragraphs Pursuant to Staff Accounting Bulletin No. 116 and SEC Release No. 33-10403
("ASU 2017-14"). ASU 2017-14 amends various paragraphs in ASC 605,
Revenue Recognition
; and ASC 606,
Revenue from Contracts With Customers
, that contain SEC guidance. The amendments include superseding ASC 605-10-S25-1 (SAB Topic 13) as a result of SEC Staff Accounting Bulletin No. 116 and adding ASC 606-10-S25-1 as a result of SEC Release No. 33-10403.
|
In 2017, we collaborated with an external professional services firm to analyze the impact of the standard on our contract portfolio by reviewing our current accounting policies and practices to identify potential differences that would result from applying the requirements of the new standard to our revenue contracts. In addition, we identified and implemented appropriate changes to our business processes, systems and controls to support recognition and disclosure under the new standard.
109
The Company adopted the new standard effective January 1, 2018 utilizing the full retrospective approach. The adoption of the new standard will result in an immaterial impact to our total revenues and operating income for the years ended December 31, 2017 and 2016, since our contracts with customers identify the delivery of products and services that are individually distinct performance obligations and revenue is recognized when performance obligations are satisfied. As a result, receivable balances related to revenue, including amounts related to unbilled revenue, are reflected as accounts receivable in the consolidated balance sheets. No other revenue related contract assets or liabilities are recorded.
The standard requires expanded disclosures regarding the qualitative and quantitative information of an entity's nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.
Note, the Company’s asset optimization activities meet the definition of trading activities per FASB ASC Topic 815,
Derivatives and Hedging,
and are therefore excluded from the scope of
Revenue from Contracts with Customers (Topic 606)
.
In August 2016, the FASB issued ASU No. 2016-15,
Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments
("ASU 2016-15"). ASU 2016-15 provides guidance on the presentation and classification of eight specific cash flow issues in the statement of cash flows. Those issues are cash payment for debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instrument or other debt instrument with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; cash proceeds from the settlement of insurance claims, cash received from settlement of corporate-owned life insurance policies; distribution received from equity method investees; beneficial interest in securitization transactions; and classification of cash receipts and payments that have aspects of more than one class of cash flows. The guidance is effective for interim and annual reporting periods beginning after December 15, 2017. This ASU is to be applied using a retrospective transition method for each period presented. The Company adopted ASU 2016-15 effective January 1, 2018 and will classify contingent consideration payments made after a business combination as cash outflows for operating and financing activities on a retrospective basis. Because of the change in accounting guidance, we expect to reclassify acquisition related payments of approximately
$1.8 million
and
$0.8 million
from cash flows from investing activities to cash flows from operating activities for the years ended December 31, 2017 and December 31, 2016, respectively. We expect to reclassify acquisition related payments of approximately
$18.4 million
and
$2.0 million
from cash flows from investing activities to cash flows from financing activities for the years ended December 31, 2017 and December 31, 2016, respectively.
In October 2016, the FASB issued ASU No. 2016-16,
Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory
(“ASU 2016-16”). ASU 2016-16 requires immediate recognition of the current and deferred income tax consequences of intercompany asset transfers other than inventory. Current U.S. GAAP prohibits the recognition of current and deferred income taxes for an intra-entity asset transfer until the asset has been sold to an outside party. This guidance is effective for annual and interim reporting periods of public entities beginning after December 15, 2017. This ASU is to be applied using a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. The Company adopted ASU 2016-16 effective January 1, 2018 and the adoption of this standard will not have an impact on the Company's consolidated financial statements.
In January 2017, the FASB issued ASU No. 2017-01,
Business Combinations (Topic 805): Clarifying the Definition of a Business
("ASU 2017-01"). ASU 2017-01 clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The definition of a business affects many areas of accounting, including acquisitions, disposals, goodwill, and consolidation. ASU 2017-01 is effective for annual periods beginning after December 15, 2017, including interim periods within those periods and is to be applied prospectively to transactions on or after the adoption date. The Company adopted ASU 2017-01 effective January 1, 2018, and the adoption will not have an impact on the Company's historical consolidated financial statements.
110
In May 2017, the FASB issued ASU No. 2017-09,
Compensation - Stock Compensation (Topic 718)
("ASU 2017-09"). ASU 2017-09 provides guidance on when changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting. An entity should account for the effects of a modification unless all of the following are met:
|
•
|
The fair value of the modified award is the same as the fair value of the original award immediately before the original award is modified
|
|
•
|
The vesting conditions of the modified award are the same as the vesting conditions of the original award immediately before the original award is modified
|
|
•
|
The classification of the modified award as an equity instrument or a liability instrument is the same as the classification of the original award immediately before the original award is modified.
|
The amendments in ASU 2017-09 are effective for all entities for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. The amendments are to be applied prospectively to an award modified on or after the adoption date. The Company adopted ASU 2017-09 effective January 1, 2018, and the adoption will not have an impact on the Company's consolidated financial statements.
Standards Being Evaluated/Standards Not Yet Adopted
In February 2016, the FASB issued ASU No. 2016-02,
Leases (Topic 842)
("ASU 2016-02"). ASU 2016-02 amends the existing accounting standards for lease accounting by requiring entities to include substantially all leases on the balance sheet by requiring the recognition of right-of-use assets and lease liabilities for all leases. Entities may elect to not recognize leases with a maximum possible term of less than 12 months. For lessees, a lease is classified as finance or operating and the asset and liability are initially measured at the present value of the lease payments. For lessors, accounting for leases is largely unchanged from previous guidance. ASU 2016-02 also requires qualitative disclosures along with certain specific quantitative disclosures for both lessees and lessors. The amendments in this ASU are effective for fiscal years beginning after December 15, 2018, with early adoption permitted, and are effective for interim periods in the year of adoption. The ASU should be applied using a modified retrospective approach, which requires lessees and lessors to recognize and measure leases at the beginning of the earliest period presented. The Company is currently evaluating the impact of adopting this guidance on its consolidated financial statements.
In January 2017, the FASB issued ASU No. 2017-04,
Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment
("ASU 2017-04"). ASU 2017-04 simplifies the subsequent measurement of goodwill by eliminating Step 2 from the goodwill impairment test. Under the amendments in 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. 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. The Company is currently evaluating the impact of adopting this guidance on its consolidated financial statements.
3. Acquisitions
Acquisition of CenStar Energy Corp
On July 8, 2015, the Company completed its acquisition of CenStar, a retail energy company based in New York. CenStar serves natural gas and electricity customers in New York, New Jersey, and Ohio. The purchase price for the CenStar acquisition was
$8.3 million
, subject to working capital adjustments, plus a payment for positive working capital of
$10.4 million
and an earnout payment estimated as of the acquisition date to be
$0.5 million
, which was associated with a financial measurement attributable to the operations of CenStar for the year following the closing ("CenStar Earnout"). See Note
9 "Fair Value Measurements"
for further discussion of the CenStar Earnout. The
111
purchase price was financed with
$16.6 million
(including positive working capital of
$10.4 million
) under our Senior Credit Facility and
$2.1 million
from the issuance of a convertible subordinated note ("CenStar Note") from the Company and Spark HoldCo to Retailco Acquisition Co, LLC ("RAC"). See Note
8 "Debt"
for further discussion of the Senior Credit Facility and the CenStar Note.
The Company’s consolidated statements of operations for the year ended December 31, 2015 included
$21.4 million
of revenue and a
$1.4 million
loss on operations of CenStar. The Company incurred
$0.1 million
of acquisition related costs for the year ended December 31, 2015, in connection with the acquisition of CenStar, which have been expensed as incurred and included in general and administrative expense in the consolidated statement of operations.
Acquisition of Oasis Power Holdings, LLC
On July 31, 2015, the Company completed its acquisition of Oasis, a retail energy company operating in
six
states across
18
utilities. The purchase price for the Oasis acquisition was
$20.0 million
, subject to working capital adjustments. The purchase price was financed with
$15.0 million
in borrowings under our Senior Credit Facility,
$5.0 million
from the issuance of a convertible subordinated note ("Oasis Note") from the Company and Spark HoldCo to RAC, and
$2.0 million
cash on hand. See Note
8 "Debt"
for further discussion of the Senior Credit Facility and the Oasis Note.
The acquisition of Oasis by the Company from RAC was a transfer of equity interests of entities under common control on July 31, 2015.
The Company’s consolidated statements of operations for year ended December 31, 2015 included
$26.9 million
of revenue and a
$0.5 million
loss on the operations of Oasis.
Acquisition of the Provider Companies
On August 1, 2016, the Company and Spark HoldCo completed the purchase of all of the outstanding membership interests of the Provider Companies. The Provider Companies serve electrical customers in Maine, New Hampshire and Massachusetts. The purchase price for the Provider Companies was approximately
$34.1 million
, which included
$1.3 million
in working capital, subject to adjustments, and up to
$9.0 million
in earnout payments, valued at
$4.8 million
as of the purchase date, which was to be paid by June 30, 2017, subject to the achievement of certain performance targets (the "Provider Earnout"). See Note
9 "Fair Value Measurements"
for further discussion on the Provider Earnout, including the final earnout payment made in June 2017. The purchase price was funded by the sale of
1,399,484
shares of Class B common stock (and a corresponding number of Spark HoldCo units) to Retailco, valued at
$14.0 million
based on a value of
$10
per share; borrowings under the Senior Credit Facility of
$10.6 million
; and
$3.8 million
in net installment consideration to be paid in
ten
monthly payments that commenced in August 2016. The first payment of the installment consideration in the amount of
$0.4 million
was made with the initial consideration paid. See Note
8 "Debt"
for further discussion of the Senior Credit Facility.
The acquisition of the Provider Companies was accounted for under the acquisition method in accordance with ASC 805,
Business Combinations
(“ASC 805”). The allocation of purchase consideration was based upon the estimated fair value of the tangible and identifiable intangible assets acquired and liabilities assumed in the acquisition. The allocation was made to major categories of assets and liabilities
based on management’s best
estimates, and supported by independent third-party analyses. The excess of the purchase price over the estimated fair value of tangible and intangible assets acquired and liabilities assumed was allocated to goodwill. The purchase price allocation for the acquisition of the Provider Companies was finalized as of December 31, 2016.
112
The allocation of the purchase consideration is as follows (in thousands):
|
|
|
|
Final as of December 31, 2016
|
||
|
Cash
|
|
|
$
|
431
|
|
|
Net working capital, net of cash acquired
|
|
|
812
|
|
|
|
Intangible assets - customer relationships and non-compete agreements
|
|
|
24,417
|
|
|
|
Intangible assets - trademark
|
|
|
529
|
|
|
|
Goodwill
|
|
|
26,040
|
|
|
|
Fair value of derivative liabilities
|
|
|
(18,163
|
)
|
|
|
Total
|
|
|
$
|
34,066
|
|
The fair values of intangible assets were measured primarily based on significant inputs that are not observable in the market and thus represent a Level 3 measurement as defined by ASC 820,
Fair Value Measurement
("ASC 820"). The fair value of derivative liabilities were measured by utilizing readily available quoted market prices and non-exchange-traded contracts fair valued using market price quotations available through brokers or over-the-counter and on-line exchanges and represent a Level 2 measurement as defined by ASC 820. Refer to Note
9
"Fair Value Measurements" for further discussion on the fair values hierarchy. Significant inputs for Level 3 measurements related to customer relationships, non-compete agreements and trademarks are discussed in Note
2
"Basis of Presentation and Summary of Significant Accounting Policies." Significant inputs for Level 3 measurements related to goodwill were as follows:
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 acquisition of the Provider Companies primarily due the value of its assembled workforce, along with access to new utility service territories. Goodwill recorded in connection with the acquisition of the Provider Companies is deductible for income tax purposes because the Provider Companies was an acquisition of all of the assets of the Provider Companies. The valuation and purchase price allocation of the Provider Companies was based on a preliminary fair value analysis. Prior to the measurement period's expiration, the Company recorded adjustments to the working capital balances upon settlement of the final working capital balances per the terms of the purchase agreement.
The Company’s consolidated statements of operations for the year ended December 31, 2016, respectively, included
$46.8 million
of revenue and
$12.8 million
of losses from operations related to the operations of the Provider Companies. We have not included pro forma information for the Provider Companies acquisition because it did not have a material impact on our financial position or results of operations.
Acquisition of the Major Energy Companies
On August 23, 2016, the Company and Spark HoldCo completed the purchase of all of the outstanding membership interests of the Major Energy Companies, which are retail energy companies operating in Connecticut, Illinois, Maryland (including the District of Columbia), Massachusetts, New Jersey, New York, Ohio, and Pennsylvania across
43
utilities, from NG&E in exchange for consideration of
$64.1 million
, which included
$5.2 million
in working capital; an assumed litigation reserve of
$5.0 million
, and up to
$35.0 million
in installment and earnout payments, valued at
$13.1 million
as of NG&E's April 15, 2016 purchase date, to be paid to the previous members of the Major Energy Companies, in annual installments on March 31, 2017, 2018 and 2019, subject to the achievement of certain performance targets (the “Major Earnout”). The Company is obligated to issue up to
400,000
shares of Class B common stock (and a corresponding number of Spark HoldCo units) to NG&E, subject to the achievement of certain performance targets, valued at
$0.8 million
(
81,436
shares valued at
$10
per share) as of the purchase date (the "Stock Earnout"). See Note
9 "Fair Value Measurements"
for further discussion on the
113
Major Earnout and Stock Earnout. The purchase price was funded by the issuance of
4,000,000
shares of Class B common stock (and a corresponding number of Spark HoldCo units) valued at
$40.0 million
based on a value of
$10
per share, to NG&E. NG&E is owned by our Founder.
The acquisition of the Major Energy Companies by the Company and Spark HoldCo from NG&E was a transfer of equity interests of entities under common control on August 23, 2016. Accordingly, the assets acquired and liabilities assumed were based on their historical values as of August 23, 2016. NG&E acquired the Major Energy Companies on April 15, 2016 and the fair value of the net assets acquired was as follows (in thousands):
|
|
Reported as of December 31, 2016
|
2017 Adjustments
(1)
|
December 31, 2017
|
|||||||||
|
Cash
|
$
|
17,368
|
|
$
|
—
|
|
$
|
17,368
|
|
|||
|
Property and equipment
|
14
|
|
—
|
|
14
|
|
||||||
|
Intangible assets - customer relationships & non-compete agreements
|
24,271
|
|
—
|
|
24,271
|
|
||||||
|
Other assets - trademarks
|
4,973
|
|
—
|
|
4,973
|
|
||||||
|
Non-current deferred tax assets
|
1,042
|
|
—
|
|
1,042
|
|
||||||
|
Goodwill
|
34,728
|
|
260
|
|
34,988
|
|
||||||
|
Net working capital, net of cash acquired
|
(6,746
|
)
|
—
|
|
(6,746
|
)
|
||||||
|
Fair value of derivative liabilities
|
(7,260
|
)
|
—
|
|
(7,260
|
)
|
||||||
|
Total
|
$
|
68,390
|
|
$
|
260
|
|
$
|
68,650
|
|
|||
(1) Changes to the purchase price allocation during 2017 related to NG&E's working capital settlement with the Major Energy Companies' sellers.
The working capital paid to Major Energy Companies by NG&E was
$10.6 million
. The Company paid
$4.3 million
in working capital to NG&E on August 23, 2016, and settled working capital with NG&E for
$5.2 million
in 2017. The
$0.9 million
related to the working capital true-up between the Company and NG&E is included in accounts payable-affiliates as of December 31, 2017. Approximately
$3.9 million
was recorded as an equity transaction and treated as a contribution on August 23, 2016. The Stock Earnout liability of
$0.8 million
due to NG&E and the working capital true-up of
$0.3 million
are also recorded as an equity transaction and treated as a contribution as of
December 31, 2017
. The value of the Stock Earnout liability was
zero
as of
December 31, 2017
. See further discussion in Note
9 "Fair Value Measurements."
The fair values of intangible assets were measured primarily based on significant inputs that are not observable in the market and thus represent a Level 3 measurement as defined by ASC 820,
Fair Value Measurement
("ASC 820"). The fair value of derivative liabilities were measured by utilizing readily available quoted market prices and non-exchange-traded contracts fair valued using market price quotations available through brokers or over-the-counter and on-line exchanges and represent a Level 2 measurement as defined by ASC 820. Refer to Note
9 "Fair Value Measurements"
for further discussion on the fair values hierarchy. Significant inputs for Level 3 measurements related to customer relationships, non-compete agreements and trademarks are discussed in Note
2 "Basis of Presentation and Summary of Significant Accounting Policies."
Significant inputs for Level 3 measurements related to goodwill were as follows:
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 acquisition of the Major Energy Companies by NG&E primarily due to the value of the Major Energy Companies brand strength, established vendor relationships and access to new utility service territories. Goodwill recorded in connection with the acquisition of the Major Energy Companies is deductible for income tax purposes because the acquisition of the Major Energy Companies was an acquisition of all of the assets of the Major Energy Companies.
114
Goodwill was transferred to the Company based on the acquisition of the Major Energy Companies by NG&E on April 15, 2016. Goodwill recorded in connection with the transfer of the Major Energy Companies is deductible for income tax purposes.
In December 2016, certain executives of the Major Energy Companies exercised a change of control provision under employment agreements with the Major Energy Companies. As a result, the Company recorded employment contract termination costs of
$4.1 million
as of December 31, 2016. The Company paid employment contract termination costs totaling approximately
$2.5 million
during the year ended
December 31, 2017
. As of
December 31, 2017
, the Company's liability related to the contract termination costs was
$1.6 million
, to be paid over a
22
month period beginning April 1, 2017.
The Major Energy Companies contributed revenues of
$125.6 million
and earnings of
$1.3 million
to the Company for the year ended December 31, 2016.
The following unaudited pro forma revenue and earnings summary presents consolidated information of the Company as if the acquisition had occurred on January 1, 2015 (in thousands):
|
Year Ended December 31,
|
||
|
2016
|
2015
|
|
|
Revenue
|
$603,673
|
$547,381
|
|
Earnings
|
$15,776
|
$15,460
|
The pro forma results are not necessarily indicative of our consolidated results of operations in future periods or the results that actually would have been realized had the companies operated on a combined basis during the periods presented. The revenue and earnings for the twelve months ended December 31, 2016 reflects actual results of operations for the period from April 15, 2016 through December 31, 2016, the period the financial results were fully combined. The pro forma results include adjustments primarily related to amortization of acquired intangibles, and certain accounting policy alignments as well as direct and incremental acquisition related costs reflected in the historical financial statements. The purchase price allocation was used to prepare the pro forma adjustments.
Acquisition of Perigee
On April 1, 2017, the Company and Spark Holdco completed the purchase of all of the outstanding membership interest of Perigee, a Texas limited liability company, with operations across
14
utilities in Connecticut, Delaware, Massachusetts, New York and Ohio. 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.
The acquisition of Perigee by the Company and Spark HoldCo from NG&E was a transfer of equity interests of entities under common control on April 1, 2017. Accordingly, the assets acquired and liabilities assumed were based on their historical value as of April 1, 2017. NG&E acquired Perigee on February 3, 2017 and the fair value of the net assets acquired was as follows (in thousands):
|
As of December 31, 2017
|
|||
|
Cash
|
$
|
23
|
|
|
Intangible assets - customer relationships
|
1,100
|
|
|
|
Goodwill
|
1,540
|
|
|
|
Net working capital, net of cash acquired
|
2,085
|
|
|
|
Fair value of derivative liabilities
|
(443
|
)
|
|
|
Total
|
$
|
4,305
|
|
115
Customer relationships
The acquired customer relationships intangibles related to Perigee are reflective of Perigee's 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. These customer relationships are amortized to depreciation and amortization based on the expected future net cash flows by year.
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 acquisition of Perigee by NG&E primarily due to the value of Perigee's access to a new utility service territory. Goodwill recorded in connection with the acquisition of Perigee is deductible for income tax purposes because the acquisition of Perigee was an acquisition of all of the assets of Perigee.
The valuation and purchase price allocation of Perigee was based on a preliminary fair value analysis performed as of February 3, 2017, the date Perigee was acquired by NG&E.
We have not included pro forma information for the Perigee acquisition because it did not have a material impact on our financial position or results of operations.
Acquisition of Verde
On July 1, 2017, the Company, through CenStar, its subsidiary, completed the acquisition from Verde Energy USA Holdings, LLC (the “Seller”) of all of the outstanding membership interests and stock in the Verde Companies. Total consideration was approximately
$91.2 million
, of which approximately
$20.8 million
was used to purchase positive net working capital, subject to adjustments. The Company funded the closing consideration of
$85.8 million
through: (i) approximately
$6.8 million
of cash on hand, (ii) approximately
$15.0 million
in subordinated debt from the Company's founder and majority shareholder through an existing subordinated debt facility, (iii) approximately
$44.0 million
in borrowings under its senior secured revolving credit facility, and (iv) the issuance by CenStar to the Seller of a promissory note in the aggregate principal amount of
$20.0 million
(the “Promissory Note”). In addition to the consideration paid at closing, CenStar is obligated to pay
100%
of the Adjusted EBITDA earned by the Verde Companies for the
18
months following closing that exceeds certain thresholds, subject to the Verde Companies’ ability to achieve defined customer count criteria (the “Verde Earnout”). The Verde Earnout was valued at
$5.4 million
on the acquisition date. In determining the fair value of the Verde Earnout, the Company forecasted certain expected performance targets and calculated the probability of such forecast being attained. Upon the closing of the acquisition, the Verde Companies became restricted subsidiaries and co-borrowers under the Company’s Senior Credit Facility.
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 acquisition of the Verde Companies. The Verde Earnout was valued at
$5.4 million
as of July 1, 2017, the acquisition date. The Company and the Seller agreed to terminate the Verde Earnout on January 12, 2018, and settled the obligation with the issuance of a
$5.9 million
promissory note payable to the Seller in June 2019 (the “Verde Earnout Termination Note”). The Company recorded a
$0.3 million
increase in fair value of the Verde Earnout in general and administrative expenses and classified the liability as long-term debt as of
December 31, 2017
. During the year ended
December 31, 2017
, the Company recorded accretion of
$0.2 million
to reflect the impact of the time value of the liability. See discussion of the Verde Earnout Termination Note in Note
8 "Debt."
116
The acquisition of the Verde Companies was accounted for under the acquisition method in accordance with ASC 805, Business Combinations (“ASC 805”). The allocation of purchase consideration was based upon the estimated fair value of the tangible and identifiable intangible assets acquired and liabilities assumed in the acquisition. The allocation was made to major categories of assets and liabilities based on management’s best estimates, and supported by independent third-party analyses. The excess of the purchase price over the estimated fair value of tangible and intangible assets acquired and liabilities assumed was allocated to goodwill. The allocation of the purchase consideration is as follows (in thousands):
|
December 31, 2017
|
||||
|
Cash and restricted cash
|
$
|
1,653
|
|
|
|
Property and equipment
|
4,560
|
|
||
|
Intangible assets - customer relationships
|
28,700
|
|
||
|
Intangible assets - trademarks
|
3,000
|
|
||
|
Goodwill
|
39,207
|
|
||
|
Net working capital, net of cash acquired
|
19,132
|
|
||
|
Deferred tax liability
|
(3,126
|
)
|
||
|
Fair value of derivative liabilities
|
(1,942
|
)
|
||
|
Total
|
$
|
91,184
|
|
|
Finalization of the Company's actual working capital adjustment with the Seller is pending as of December 31, 2017. An estimated positive working capital adjustment between the Company and the Seller of approximately
$0.5 million
was recorded as of December 31, 2017 and is included in accounts receivable.
Customer relationships
The acquired customer relationships intangibles related to the Verde Companies are reflective of the Verde Companies' customer base, and were valued 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, intangible assets, fixed assets, and 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. These customer relationships were bifurcated between unhedged and hedged and will be amortized to depreciation and amortization based on the expected future net cash flows by year and expensed to retail cost of revenues based on the expected term of the underlying fixed price contract acquired in each reporting period, respectively.
Trademark
The fair value of the Verde Companies' trademark is reflective of the value associated with the recognition and reputation of the Verde Companies to target markets. The fair value of the trademark was valued using a royalty savings method under the income approach. The value is based on the savings the Company would realize from owning the trademark rather than paying a royalty for the use of that trademark. Under this approach, the Company estimated the present value of the expected cash flows resulting from avoiding royalty payments to use a third party trademark. 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. The trademark is being amortized over the estimated
five
-year life of the asset on a straight-line basis.
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 acquisition of the Verde Companies primarily due the value of its assembled workforce, its proprietary sales channels, and access to new utility service territories. Goodwill recorded in connection with the acquisition of the Verde Companies is
117
deductible for income tax purposes because the Verde Companies was an acquisition of all of the assets of the Verde Companies.
The valuation and purchase price allocation of the Verde Companies was based on a preliminary fair value analysis. The Company anticipates adjustments to the working capital amounts that are expected to be finalized prior to the measurement period's expiration. The Verde Companies contributed revenues of
$76.0 million
and earnings of
$1.2 million
to the Company for the year ended
December 31, 2017
.
The following unaudited pro forma revenue and earnings summary presents consolidated information of the Company as if the acquisition had occurred on January 1, 2016 (in thousands):
|
Year Ended December 31,
|
||||||
|
2017
|
2016
|
|||||
|
Revenues
|
$
|
868,415
|
|
$
|
716,696
|
|
|
Earnings
|
$
|
18,047
|
|
$
|
17,860
|
|
The pro forma results are not necessarily indicative of our consolidated results of operations in future periods or the results that actually would have been realized had the companies operated on a combined basis during the periods presented. The revenue and earnings for the twelve months ended December 31, 2017 reflects actual results of operations for the period from July 1, 2017 through December 31, 2017, the period the financial results were fully combined. The pro forma results include adjustments primarily related to amortization of acquired intangibles, and certain accounting policy alignments as well as direct and incremental acquisition related costs reflected in the historical financial statements. The preliminary purchase price allocation was used to prepare the pro forma adjustments. The final allocation could differ materially from the preliminary allocation used in the pro forma adjustments.
4. Equity
Non-controlling Interest
The Company holds an economic interest and is the sole managing member in Spark HoldCo, with NuDevco Retail and Retailco holding the remaining economic interest in Spark HoldCo. As a result, the Company has consolidated the financial position and results of operations of Spark HoldCo and reflected the economic interest retained by NuDevco Retail and Retailco as a non-controlling interest.
The Company and NuDevco Retail and Retailco owned the following economic interests in Spark HoldCo at
December 31, 2016
and
December 31, 2017
, respectively.
|
Non-controlling Interest Economic Interest
|
|
|
||
|
|
The Company
|
NuDevco Retail and Retailco
(1) (2)
|
||
|
December 31, 2016
|
38.85
|
%
|
61.15
|
%
|
|
December 31, 2017
|
38.12
|
%
|
61.88
|
%
|
(1) In January 2016, Retailco succeeded to the interest of NuDevco Retail Holdings of its Class B common stock and an equal number of Spark HoldCo units it held pursuant to a series of transfers.
(2) In January 2017, Retailco converted the CenStar Note and Oasis Note into
269,462
and
766,180
shares, respectively, of Class B common stock.
118
The following table summarizes the portion of net income and income tax expense (benefit) attributable to non-controlling interest (in thousands):
|
|
2017
|
2016
|
2015
|
||||||
|
|
|
|
|
||||||
|
Net income allocated to non-controlling interest
|
$
|
56,696
|
|
$
|
52,300
|
|
$
|
21,779
|
|
|
Income tax expense (benefit) allocated to non-controlling interest
|
(731
|
)
|
1,071
|
|
(331
|
)
|
|||
|
Net income attributable to non-controlling interest
|
$
|
57,427
|
|
$
|
51,229
|
|
$
|
22,110
|
|
Stock Split
On May 22, 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.
Share Repurchase Program
On May 24, 2017, the Company authorized a share repurchase program of up to
$50.0 million
of Spark Class A common stock through December 31, 2017. The Company funds the program through available cash balances, its credit facilities, and operating cash flows. The shares of Class A common stock may be repurchased from time to time in the open market or in privately negotiated transactions based on ongoing assessments of capital needs, the market price of the Class A common stock, and other factors, including general market conditions. The repurchase program does not obligate Spark to acquire any particular amount of Class A common stock and it may be modified or suspended at any time, and can be terminated prior to completion.
The Company uses the cost method to account for its treasury shares. Purchases of shares of Class A common stock are recorded at cost, and the gross cost of the Class A common stock purchased is charged to a contra equity account entitled "Treasury Stock."
During the year ended
December 31, 2017
, the Company repurchased
99,446
shares of its Class A common stock at a weighted-average price of
$20.22
per share, for a total cost of approximately
$2.0 million
.
Class A Common Stock
The Company had a total of
13,135,636
and
12,993,118
shares of its Class A common stock outstanding at
December 31, 2017
and
2016
, respectively, and
99,446
and
zero
shares of treasury stock at
December 31, 2017
and
2016
, respectively. Each share of Class A common stock holds economic rights and entitles its holder to
one
vote on all matters to be voted on by shareholders generally. All shares and per share amounts in this report have been retrospectively restated to reflect the Stock Split.
Issuance of Class A Common Stock Upon Vesting of Restricted Stock Units
For the year ended
December 31, 2017
,
356,014
restricted stock units vested, with
241,965
shares of common stock distributed to the holders of these units and
114,049
shares of common stock withheld by the Company to cover taxes owed on the vesting of such units.
For the year ended
December 31, 2016
,
395,056
restricted stock units vested, with
305,872
shares of common stock distributed to the holders of these units and
89,184
shares of common stock withheld by the Company to cover taxes owed on the vesting of such units.
119
Conversion of Class B Common Stock to Class A Common Stock
On February 3, 2016, April 1, 2016 and June 8, 2016, Retailco exchanged
2,000,000
,
3,450,000
and
1,000,000
, respectively, of its 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. Refer to Note
12 "Income Taxes"
for further discussion.
Class B Common Stock
The Company had a total of
21,485,126
and
20,449,484
shares of its Class B common stock outstanding at
December 31, 2017
and
2016
, respectively. Each share of Class B common stock, all of which are held by NuDevco Retail and Retailco, have no economic rights but entitles its holder to
one
vote on all matters to be voted on by shareholders generally. All outstanding shares and per share amounts in this report have been retrospectively restated to reflect the Stock Split.
Holders of Class A common stock and Class B common stock vote together as a single class on all matters presented to our shareholders for their vote or approval, except as otherwise required by applicable law or by our certificate of incorporation.
Issuance of Class B Common Stock
On August 1, 2016, the Company issued
1,399,484
shares of Class B common stock to Retailco in connection with the acquisition of the Provider Companies. On August 23, 2016, the Company issued
4,000,000
shares of Class B common stock to Retailco in connection with the acquisition of Major Energy Companies.
Preferred Stock
The Company has
20,000,000
shares of authorized preferred stock for which there are
1,704,339
and
zero
issued and outstanding shares at
December 31, 2017
and
2016
.
Conversion of CenStar and Oasis Notes
On October 5, 2016, RAC issued to the Company an irrevocable commitment to convert the CenStar Note and Oasis Note into
269,462
and
766,180
shares, respectively, of Class B common stock (and related Spark HoldCo units) on January 8, 2017 and January 31, 2017, respectively. Refer to Note
8 "Debt"
for further discussion.
On January 8, 2017 and January 31, 2017, respectively, the CenStar Note and Oasis Note were converted into
269,462
and
766,180
shares of Class B common stock (and related Spark HoldCo units). Refer to Note
8 "Debt"
for further discussion.
Earnings Per Share
Basic earnings per share (“EPS”) is computed by dividing net income attributable to stockholders (the numerator) by the weighted-average number of Class A common shares outstanding for the period (the denominator). Class B common shares are not included in the calculation of basic earnings per share because they are not participating securities and have no economic interest in the Company. Diluted earnings per share is similarly calculated except that the denominator is increased (1) using the treasury stock method to determine the potential dilutive effect of the Company's outstanding unvested restricted stock units, (2) using the if-converted method to determine the potential dilutive effect of the Company's Class B common stock and (3) using the if-converted method to determine the potential dilutive effect of the outstanding convertible subordinated notes into the Company's Class B common stock. All shares and per share amounts in this report have been retrospectively restated to reflect the Stock Split.
120
The following table presents the computation of earnings per share for the years ended
December 31, 2017
and
2016
(in thousands, except per share data):
|
|
Year Ended December 31,
|
||||||||
|
2017
|
2016
|
2015
|
|||||||
|
Net income attributable to Spark Energy, Inc. stockholders
|
$
|
18,854
|
|
$
|
14,444
|
|
$
|
3,865
|
|
|
Less: Dividend on Series A preferred stock
|
3,038
|
|
—
|
|
—
|
|
|||
|
Net income attributable to stockholders of Class A common stock
|
$
|
15,816
|
|
$
|
14,444
|
|
$
|
3,865
|
|
|
|
|||||||||
|
Basic weighted average Class A common shares outstanding
|
13,143
|
|
11,402
|
|
6,129
|
|
|||
|
Basic EPS attributable to stockholders
|
$
|
1.20
|
|
$
|
1.27
|
|
$
|
0.63
|
|
|
|
|
||||||||
|
Net income attributable to stockholders of Class A common stock
|
$
|
15,816
|
|
$
|
14,444
|
|
$
|
3,865
|
|
|
Effect of conversion of Class B common stock to shares of Class A common stock
|
—
|
|
—
|
|
—
|
|
|||
|
Effect of conversion of convertible subordinated notes into shares of Class B common stock and shares of Class B common stock into shares of Class A common stock
(1)
|
—
|
|
(310
|
)
|
(334
|
)
|
|||
|
Diluted net income attributable to stockholders of Class A common stock
|
$
|
15,816
|
|
$
|
14,134
|
|
$
|
3,531
|
|
|
Basic weighted average Class A common shares outstanding
|
13,143
|
|
11,402
|
|
6,129
|
|
|||
|
Effect of dilutive Class B common stock
|
—
|
|
—
|
|
—
|
|
|||
|
Effect of dilutive convertible subordinated notes into shares of Class B common stock and shares of Class B common stock into shares of Class A common stock
|
—
|
|
1,010
|
|
420
|
|
|||
|
Effect of dilutive restricted stock units
|
203
|
|
278
|
|
106
|
|
|||
|
Diluted weighted average shares outstanding
|
13,346
|
|
12,690
|
|
6,655
|
|
|||
|
|
|
||||||||
|
Diluted EPS attributable to stockholders
|
$
|
1.19
|
|
$
|
1.11
|
|
$
|
0.53
|
|
(1) The CenStar Note and Oasis Note converted into
269,462
and
766,180
shares of Class B common stock on January 8, 2017, and January 31, 2017, respectively.
The conversion of shares of Class B common stock to shares of Class A common stock was not recognized in dilutive earnings per share for the years ended
December 31, 2017
as the effect of the conversion was antidilutive.
Variable Interest Entity
On January 1, 2016, we adopted ASU No. 2015-02,
Consolidation (Topic 810) (“ASU 2015-02”)
. ASU 2015-02 changed the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. Upon adoption, we continued to consolidate Spark HoldCo, but considered Spark HoldCo to be a variable interest entity requiring additional disclosures in the footnotes of our consolidated financial statements.
Spark HoldCo is a variable interest entity due to its lack of rights to participate in significant financial and operating decisions and inability to dissolve or otherwise remove its management. Spark HoldCo owns all of the outstanding membership interests in each of the operating subsidiaries through which the Company operates. The Company is the sole managing member of Spark HoldCo, manages Spark HoldCo's operating subsidiaries through this managing membership interest, and is considered the primary beneficiary of Spark HoldCo.
The assets of Spark HoldCo cannot be used to settle the obligations of the Company except through distributions to the Company, and the liabilities of Spark HoldCo cannot be settled by the Company except through contributions to Spark HoldCo.
121
The following table includes the carrying amounts and classification of the assets and liabilities of Spark HoldCo that are included in the Company's consolidated balance sheet as of
December 31, 2017
(in thousands):
|
|
December 31, 2017
|
||
|
Assets
|
|||
|
Current assets:
|
|||
|
Cash and cash equivalents
|
$
|
29,385
|
|
|
Accounts receivable
|
158,814
|
|
|
|
Other current assets
|
105,165
|
|
|
|
Total current assets
|
293,364
|
|
|
|
Non-current assets:
|
|||
|
Goodwill
|
120,154
|
|
|
|
Other assets
|
62,552
|
|
|
|
Total non-current assets
|
182,706
|
|
|
|
Total Assets
|
$
|
476,070
|
|
|
|
|||
|
Liabilities
|
|||
|
Current liabilities:
|
|||
|
Accounts Payable and Accrued Liabilities
|
$
|
110,152
|
|
|
Current portion of Senior Credit Facility
|
7,500
|
|
|
|
Contingent consideration
|
4,024
|
|
|
|
Other current liabilities
|
8,933
|
|
|
|
Total current liabilities
|
130,609
|
|
|
|
Long-term liabilities:
|
|||
|
Long-term portion of Senior Credit Facility
|
117,750
|
|
|
|
Contingent consideration
|
626
|
|
|
|
Other long-term liabilities
|
663
|
|
|
|
Total long-term liabilities
|
119,039
|
|
|
|
Total Liabilities
|
$
|
249,648
|
|
5. Preferred Stock
On March 15, 2017, the Company 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 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 the Company, net of underwriting discounts and commissions). The Company 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. The net proceeds from the offering were contributed to Spark HoldCo to use for general corporate purposes.
On July 21, 2017, the Company 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, the Company may sell from time to time through the Agent the Company's Series A Preferred Stock, having an aggregate offering price of up to
$50.0 million
.
During the year ended
December 31, 2017
, the Company sold an aggregate of
94,339
shares of Series A Preferred Stock under the ATM Agreement. The Company 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.
122
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. From March 15, 2017, the Series A Preferred Stock issuance date, to, but not including, April 15, 2022, the Series A Preferred Stock will accrue dividends at an annual percentage rate of three-month LIBOR plus
6.578%
.
The liquidation preference provisions of the Series A Preferred Stock were considered contingent redemption provisions because there were certain rights granted to the holders of the Series A Preferred Stock that were not solely within the control of the Company upon a change in control of the Company. Accordingly, the Series A Preferred Stock is presented within the mezzanine portion of the accompanying consolidated balance sheet.
The Company had a total of
1,704,339
shares of Series A Preferred Stock issued and outstanding at
December 31, 2017
and no shares of Series A Preferred Stock issued and outstanding at
December 31, 2016
. During the year ended
December 31, 2017
, the Company paid
$2.1 million
in dividends to holders of the Series A Preferred Stock. As of
December 31, 2017
, the Company had accrued
$0.9 million
related to dividends to holders of the Series A Preferred Stock. This dividend was paid on
January 15, 2018
.
A summary of the Company's mezzanine equity for the year ended
December 31, 2017
is as follows:
|
(in thousands)
|
||||
|
Mezzanine equity at December 31, 2016
|
$
|
—
|
|
|
|
Issuance of Series A Preferred Stock, net of issuance cost
|
40,241
|
|
||
|
Accumulated dividends on Series A Preferred Stock
|
932
|
|
||
|
Mezzanine equity at December 31, 2017
|
$
|
41,173
|
|
|
In connection with the issuance of the Series A Preferred Stock, the Company and Spark HoldCo entered into the Third Amended and Restated Spark HoldCo Limited Liability Company Agreement to amend the prior agreement to provide for, among other things, the designation and issuance of Spark HoldCo Series A preferred units, as another equity security of Spark HoldCo to be issued concurrently with the issuance of Series A Preferred Stock by the Company, including specific terms relating to distributions by Spark HoldCo in connection with the payment by the Company of dividends on the Series A Preferred Stock, the priority of liquidating distributions by Spark HoldCo, the allocation of income and loss to the Company in connection with distributions by Spark HoldCo on Series A preferred units, and other terms relating to the redemption and conversion by the Company of the Series A Preferred Stock.
Public Offering of Series A Preferred Stock
On January 23, 2018, the Company commenced a public offering of its
8.75%
Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Stock (“Series A Preferred Stock”) pursuant to an effective shelf registration statement on Form S-3 previously filed with the SEC. At the time of issuance, Spark granted the underwriters a
30
-day option to purchase additional shares of Series A Preferred Stock. The offering closed on January 26, 2018.
As of the filing date, the Company sold an aggregate of
2,000,000
shares of Series A Preferred Stock. The Company received net proceeds from the offering of approximately
$48.9 million
(net of underwriting discounts, commissions and a structuring fee).
6. Property and Equipment
Property and equipment consist of the following amounts as of (in thousands):
123
|
|
Estimated
useful lives (years) |
|
December 31, 2017
|
|
December 31, 2016
|
||||
|
Information technology
|
2 – 5
|
|
$
|
34,103
|
|
|
$
|
29,675
|
|
|
Leasehold improvements
|
2 – 5
|
|
4,568
|
|
|
4,568
|
|
||
|
Furniture and fixtures
|
2 – 5
|
|
1,964
|
|
|
1,024
|
|
||
|
Building improvements
|
2 – 5
|
|
809
|
|
|
—
|
|
||
|
Total
|
|
|
41,444
|
|
35,267
|
|
|||
|
Accumulated depreciation
|
|
|
(33,169
|
)
|
|
(30,561
|
)
|
||
|
Property and equipment—net
|
|
|
$
|
8,275
|
|
$
|
4,706
|
|
|
Information technology assets include software and consultant time used in the application, development and implementation of various systems including customer billing and resource management systems. As of
December 31, 2017
and
2016
, information technology includes
$1.2 million
and
$1.1 million
, respectively, of costs associated with assets not yet placed into service.
Depreciation expense recorded in the consolidated statements of operations was
$2.6 million
,
$2.1 million
and
$1.6 million
for the years ended
December 31, 2017
,
2016
and
2015
, respectively.
7. Goodwill, Customer Relationships and Trademarks
Goodwill, customer relationships and trademarks consist of the following amounts as of (in thousands):
|
|
|
|
|||||
|
|
December 31, 2017
|
December 31, 2016
|
|||||
|
Goodwill
|
$
|
120,154
|
|
$
|
79,147
|
|
|
|
Customer Relationships
— Acquired
(1)
|
|
|
|||||
|
Cost
|
$
|
93,371
|
|
$
|
63,571
|
|
|
|
Accumulated amortization
|
(46,681
|
)
|
(31,660
|
)
|
|||
|
Customer Relationships
—Acquired, net
|
$
|
46,690
|
|
$
|
31,911
|
|
|
|
Customer Relationships
— Other
(2)
|
|
|
|||||
|
Cost
|
$
|
12,336
|
|
$
|
4,320
|
|
|
|
Accumulated amortization
|
(5,534
|
)
|
(2,708
|
)
|
|||
|
Customer Relationships
—Other, net
|
$
|
6,802
|
|
$
|
1,612
|
|
|
|
Trademarks
(3)
|
|
|
|||||
|
Cost
|
$
|
9,770
|
|
$
|
6,770
|
|
|
|
Accumulated amortization
|
(1,212
|
)
|
(431
|
)
|
|||
|
Trademarks, net
|
$
|
8,558
|
|
$
|
6,339
|
|
|
|
(1)
|
Customer relationships—Acquired represent those customer acquisitions accounted for under the acquisition method in accordance with ASC 805. See Note
3 "Acquisitions"
for further discussion.
|
|
(2)
|
Customer relationships—Other represent portfolios of customer contracts not accounted for in accordance with ASC 805 as these acquisitions were not in conjunction with the acquisition of businesses. See Note
16 "Customer Acquisitions"
for further discussion.
|
|
(3)
|
Trademarks reflect values associated with the recognition and positive reputation of acquired businesses accounted for as part of the acquisition method in accordance with ASC 805 through the acquisitions of CenStar, Oasis, the Provider Companies, the Major Energy Companies and the Verde Companies. These trademarks are recorded as other assets in the consolidated balance sheets. See Note
3 "Acquisitions"
for further discussion.
|
Changes in goodwill, customer relationships and trademarks consisted of the following (in thousands):
|
|
Goodwill
(1)
|
Customer Relationships— Acquired & Non-Compete Agreements
|
Customer Relationships
— Other
|
Trademarks
|
|||||||||||
|
Balance at December 31, 2014
|
$
|
—
|
|
$
|
—
|
|
$
|
1,501
|
|
$
|
—
|
|
|||
|
Additions
|
$
|
—
|
|
$
|
—
|
|
$
|
2,731
|
|
$
|
—
|
|
|||
|
Acquisition of CenStar
|
6,396
|
|
5,494
|
|
—
|
|
651
|
|
|||||||
|
Acquisition of Oasis
|
11,983
|
|
9,389
|
|
—
|
|
617
|
|
|||||||
|
Amortization expense
|
—
|
|
(4,503
|
)
|
(1,183
|
)
|
(74
|
)
|
|||||||
|
Balance at December 31, 2015
|
$
|
18,379
|
|
$
|
10,380
|
|
$
|
3,049
|
|
$
|
1,194
|
|
|||
|
Additions
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
|||
|
Acquisition of Provider Companies
|
26,040
|
|
24,417
|
|
—
|
|
529
|
|
|||||||
|
Acquisition of Major Energy Companies
|
34,728
|
|
24,271
|
|
—
|
|
4,973
|
|
|||||||
|
Amortization expense
|
—
|
|
(27,157
|
)
|
(1,437
|
)
|
(357
|
)
|
|||||||
|
Balance at December 31, 2016
|
$
|
79,147
|
|
$
|
31,911
|
|
$
|
1,612
|
|
$
|
6,339
|
|
|||
|
Additions (Major Working Capital Adjustment)
|
$
|
260
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Acquisition of Perigee
|
1,540
|
|
|
1,100
|
|
|
—
|
|
|
—
|
|
||||
|
Acquisition of Verde
|
39,207
|
|
|
28,700
|
|
|
—
|
|
|
3,000
|
|
||||
|
Additions (Other)
(2)
|
—
|
|
|
—
|
|
|
8,016
|
|
|
—
|
|
||||
|
Amortization expense
|
—
|
|
|
(15,021
|
)
|
|
(2,826
|
)
|
|
(781
|
)
|
||||
|
Balance at December 31, 2017
|
$
|
120,154
|
|
$
|
46,690
|
|
$
|
6,802
|
|
$
|
8,558
|
|
|||
(1) Changes in goodwill for the year ended
December 31, 2017
include NG&E's working capital settlement with the Major Energy Companies' sellers of
$0.3 million
, Perigee's goodwill of
$1.5 million
, and the Verde Companies' goodwill of
$39.2 million
.
(2) Includes
$8.0 million
related to customer contract purchases for the year ended
December 31, 2017
.
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, 2017
,
2016
, and
2015
, respectively, approximately
$0.3 million
,
$15.8 million
, and
zero
of the
$15.0 million
,
$27.2 million
, and
$4.5 million
customer relationship amortization expense is included in the cost of revenues.
Estimated future amortization expense for customer relationships and trademarks at
December 31, 2017
is as follows (in thousands):
|
Year Ending December 31,
|
|||
|
2018
|
$
|
19,469
|
|
|
2019
|
14,894
|
|
|
|
2020
|
10,474
|
|
|
|
2021
|
8,912
|
|
|
|
2022
|
4,700
|
|
|
|
> 5 years
|
3,601
|
|
|
|
Total
|
$
|
62,050
|
|
124
Balance Sheet and Income Statement Summary
Debt consists of the following amounts as of (in thousands):
|
|
December 31, 2017
|
December 31, 2016
|
|||||
|
Current portion of Senior Credit Facility—Bridge Loan
(5)
|
$
|
7,500
|
|
$
|
—
|
|
|
|
Current portion of Prior Senior Credit Facility—Working Capital Line
(1)
|
—
|
|
29,000
|
|
|||
|
Current portion of Prior Senior Credit Facility—Acquisition Line
(2)
|
—
|
|
22,287
|
|
|||
|
Current portion of Note Payable—Pacific Summit Energy
|
—
|
|
15,501
|
|
|||
|
Convertible subordinated notes to affiliate
(3)
|
—
|
|
6,582
|
|
|||
|
Current portion of Note Payable—Verde
|
13,443
|
|
—
|
|
|||
|
Total current debt
|
20,943
|
|
73,370
|
|
|||
|
Long-term portion of Senior Credit Facility
(4) (5)
|
117,750
|
|
—
|
|
|||
|
Subordinated Debt
|
—
|
|
5,000
|
|
|||
|
Long-term portion of Note Payable—Verde
|
7,051
|
|
—
|
|
|||
|
Total long-term debt
|
124,801
|
|
5,000
|
|
|||
|
Total debt
|
$
|
145,744
|
|
$
|
78,370
|
|
|
(1) As of
December 31,
2016
, the Company had
$29.6 million
in letters of credit issued.
(2) As of December 31,
2016
, the weighted average interest rate on the current portion of our Prior Senior Credit Facility was
4.93%
.
(3) On October 5, 2016, RAC issued to the Company an irrevocable commitment to convert the CenStar Note and the Oasis Note into shares of Class B common stock on January 8, 2017 and January 31, 2017, respectively. RAC assigned the CenStar Note and Oasis Note to Retailco on January 4, 2017, and on January 8, 2017 and January 31, 2017, the CenStar Note and Oasis Note were converted into
269,462
and
766,180
shares of Class B common stock, respectively.
(4) As of
December 31, 2017
, the Company had
$47.2 million
in letters of credit issued.
(5) As of
December 31, 2017
, the weighted average interest rate on our Senior Credit Facility was
4.61%
.
Deferred financing costs were
$1.6 million
and
$0.4 million
as of
December 31, 2017
and
2016
, respectively. Of these amounts,
$1.2 million
and
$0.4 million
is recorded in other current assets in the consolidated balance sheets as of
December 31, 2017
and
2016
, respectively, and
$0.4 million
and
zero
is recorded in other assets in the consolidated balance sheets as of
December 31, 2017
and
2016
, respectively, representing capitalized financing costs related to our Senior Credit Facility and Prior Senior Credit Facility.
Interest expense consists of the following components for the periods indicated (in thousands):
|
|
Years Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
Interest incurred on Senior Credit Facility
|
$
|
3,275
|
|
|
$
|
1,730
|
|
|
$
|
1,144
|
|
|
Accretion related to Earnouts
(1)
|
4,108
|
|
|
5,060
|
|
|
—
|
|
|||
|
Letters of credit fees and commitment fees
|
1,125
|
|
|
883
|
|
|
517
|
|
|||
|
Amortization of deferred financing costs
(2)
|
1,035
|
|
|
668
|
|
|
412
|
|
|||
|
Interest incurred on convertible subordinated notes to affiliate
(3)
|
1,052
|
|
|
518
|
|
|
207
|
|
|||
|
Interest incurred on subordinated debt
|
167
|
|
|
—
|
|
|
—
|
|
|||
|
Interest on Verde promissory note
|
372
|
|
|
—
|
|
|
—
|
|
|||
|
Interest expense
|
$
|
11,134
|
|
$
|
8,859
|
|
$
|
2,280
|
|
||
125
(1) Includes accretion related to the Provider Earnout of
$0.1 million
, the Major Earnout of
$3.8 million
, and the Verde Earnout of
$0.2 million
for the year ended
December 31, 2017
and accretion related to the Provider Earnout of
$0.1 million
and the Major Earnout of
$4.9 million
for the year ended
December 31, 2016
.
(2) Write offs of deferred financing costs included in the above amortization were
$0.1 million
in connection with the amended and restated Prior Senior Credit Facility on July 8, 2015,
$0.3 million
upon extinguishment of the Seventh Amended Credit Facility and
$0.1 million
in connection with the execution of the Seventh Amended Credit Facility for the year ended
December 31,
2015
.
(3) Includes amortization of the discount on the convertible subordinated notes to affiliates of
zero
,
$0.2 million
, and less than
$0.1 million
for the years ended
December 31, 2017
,
2016
, and
2015
.
Prior Senior Credit Facility
The Company, as guarantor, and Spark HoldCo (the “Borrower,” and together with Spark Energy, LLC, Spark Energy Gas, LLC, CenStar Energy Corp, CenStar Operating Company, LLC, Oasis, Oasis Power, LLC, Electricity Maine, LLC, Electricity N.H., LLC, and Provider Power Mass, LLC, each a subsidiary of Spark HoldCo, the “Co-Borrowers”) were party to a senior secured revolving credit facility (“Prior Senior Credit Facility”), which included a senior secured revolving working capital facility up to
$82.5 million
("Working Capital Line") and a secured revolving line of credit of
$25.0 million
("Acquisition Line") to be used specifically for the financing of up to
75%
of the cost of acquisitions with the remainder to be financed by the Company either through cash on hand or the issuance of subordinated debt or equity.
The Prior Senior Credit Facility was secured by pledges of the equity of the portion of Spark HoldCo owned by the Company and of the equity of Spark HoldCo’s subsidiaries (excluding the Major Energy Companies) and the Co-Borrowers’ present and future subsidiaries, 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. The Major Energy Companies were excluded from the definition of "Borrowers" under the Prior Senior Credit Facility. Accordingly, we did not factor in their working capital into our working capital covenants.
The Prior Senior Credit Facility had a maturity date of July 8, 2017. The outstanding balances under the Working Capital Line and the Acquisition Line were paid in full on May 19, 2017 upon execution of the Company's new Senior Credit Facility.
Senior Credit Facility
On May 19, 2017 (the “Closing Date”), the Company, as guarantor, and Spark HoldCo (the “Borrower” and, together with SE, SEG, CenStar, CenStar Operating Company, LLC, Oasis, Oasis Power, LLC, the Provider Companies, the Major Energy Companies and Perigee Energy, LLC, each subsidiaries of Spark HoldCo, the “Co-Borrowers”), entered into a senior secured borrowing base credit facility (the “Senior Credit Facility”) in an aggregate amount of
$120.0 million
. The Verde Companies became Co-Borrowers upon the completion of our acquisition of the Verde Companies. On November 2, 2017, the Company and Co-Borrowers entered into an amendment to the Senior Credit Facility, which entitles the co-borrowers to elect to increase total commitments under the Senior Credit Facility to
$200.0 million
. In connection with any such increase in commitments, the various limits on advances for Working Capital Loans, Letters of Credit and Bridge Loans increased accordingly. On November 30, 2017, we exercised the accordion feature in the Senior Credit Facility, expanding commitments to an aggregate amount of
$185.0 million
.
As of December 31, 2017, there was
$125.3 million
outstanding under the Senior Credit Facility, and there was approximately
$12.5 million
available borrowing capacity (which includes a
$47.2 million
reduction for outstanding letters of credit).
The Senior Credit Facility will mature on May 19, 2019, and all amounts outstanding thereunder will be payable on the maturity date. Borrowings under the Bridge Loan sublimit will be repaid
25%
per year on a quarterly basis (or
6.25%
per quarter), with the remainder due at maturity.
126
On January 11, 2018 and January 23, 2018, we exercised the accordion feature in the Senior Credit Facility for an additional
$10.0 million
and
$5.0 million
, respectively, in commitments by existing lenders. These exercises of the accordion feature of the Senior Credit Facility brought total commitments under the Senior Credit Facility to
$200.0 million
.
Subject to applicable sublimits and terms of the Senior Credit Facility, borrowings are available for the issuance of letters of credit (“Letters of Credit”), working capital and general purpose revolving credit loans up to
$200.0 million
(“Working Capital Loans”), and bridge loans up to
$50.0 million
(“Bridge Loans”) for the purpose of partial funding for acquisitions. Borrowings under the Senior Credit Facility may be used to refinance loans outstanding under the previous Senior Credit Facility, pay fees and expenses in connection with the current 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 the Company’s Class A common stock.
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
|
|
•
|
the 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
|
|
•
|
the 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 will pay a commitment fee of
0.50%
quarterly in arrears on the unused portion of the Senior Credit Facility. In addition, the Co-Borrowers will be 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 as follows:
|
•
|
Minimum Fixed Charge Coverage Ratio
. Spark Energy, Inc. 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 any Subordinated Debt but including interest in respect of that certain promissory note made by Censtar Energy Corp 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 of the Company), distributions, the aggregate amount of repurchases of the Company’s Class A common stock or commitments for such purchases, taxes and scheduled amortization payments.
|
|
•
|
Maximum Total Leverage Ratio
. Spark Energy, Inc. must maintain a ratio of total indebtedness (excluding eligible subordinated debt) to Adjusted EBITDA of no more than
2.00
to 1.00.
|
127
The Senior Credit Facility contains various negative covenants that limit the Company’s ability to, among other things, do any of the following:
|
•
|
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 is secured by pledges of the equity of the portion of Spark HoldCo owned by the Company, 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.
Spark Energy, Inc. is 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 the Company’s Class A common stock through one or more normal course open market purchases through NASDAQ so long as: (a) no default exists or would result therefrom; (b) the Co-Borrowers are in pro forma compliance with all financial covenants before and after giving effect thereto; and (c) the outstanding amount of all loans and letters of credit does not exceed the borrowing base limits.
The Senior Credit Facility contains certain customary representations and warranties and events of default. Events of default include, among other things, payment defaults, breaches of representations and warranties, covenant defaults, cross-defaults and cross-acceleration to certain indebtedness, certain events of bankruptcy, certain events under ERISA, material judgments in excess of
$5.0 million
, certain events with respect to material contracts, actual or asserted failure of any guaranty or security document supporting the Senior Credit Facility to be in full force and effect, failure of Nathan Kroeker to retain his position as President and Chief Executive Officer of the Company, and failure of W. Keith Maxwell III to retain his position as chairman of the board of directors. A default will also occur if at any time W. Keith Maxwell III ceases to, directly or indirectly, own at least
13,600,000
Class A and Class B shares on a combined basis (to be adjusted for any stock split, subdivisions or other stock reclassification or recapitalization), and a controlling percentage of the voting equity interest of the Company, and certain other changes in control. If such an event of default occurs, the lenders under the Senior Credit Facility would be entitled to take various actions, including the acceleration of amounts due under the facility and all actions permitted to be taken by a secured creditor.
In addition, the Senior Credit Facility contains affirmative covenants that are customary for credit facilities of this type. The covenants include delivery of financial statements, including any filings made with the SEC, maintenance of property and insurance, payment of taxes and obligations, material compliance with laws, inspection of property, books and records and audits, use of proceeds, payments to bank blocked accounts, notice of defaults and certain other customary matters.
Convertible Subordinated Notes to Affiliate
In connection with the financing of the CenStar acquisition, the Company, together with Spark HoldCo, issued the CenStar Note to RAC for
$2.1 million
on July 8, 2015 at an annual interest rate of
5%
, payable semiannually. On October 5, 2016, RAC issued to the Company an irrevocable commitment to convert the CenStar Note into
269,462
shares of Class B common stock. RAC assigned the CenStar Note to Retailco on January 4, 2017, and on January 8, 2017, the CenStar Note was converted into
269,462
shares of Class B common stock.
In connection with the financing of the Oasis acquisition, the Company, together with Spark HoldCo, issued the Oasis Note to RAC for
$5.0 million
on July 31, 2015 at an annual rate of
5%
, payable semiannually. On October 5, 2016, RAC issued to the Company an irrevocable commitment to convert the Oasis Note into
766,180
shares of
128
Class B common stock. RAC assigned the Oasis Note to Retailco on January 4, 2017, and on January 31, 2017 the Oasis Note was converted into
766,180
shares of Class B common stock.
The conversion rate of
$7.00
per share for the Oasis Note was fixed as of the date of the execution of the Oasis acquisition agreement on May 12, 2015. Due to a rise in the price of our common stock from May 12, 2015 to the closing of Oasis acquisition on July 31, 2015, the conversion rate of
$7.00
per share was below the market price per share of Class A common stock of
$8.11
on the issuance date of the Oasis Note on July 31, 2015. As a result, the Company assessed the Oasis Note for a beneficial conversion feature. Due to this conversion feature being "in-the-money" upon issuance, we recognized a beneficial conversion feature based on its intrinsic value of
$0.8 million
as a discount to the Oasis Note and as additional paid-in capital. This discount was amortized as interest expense under the effective interest method over the life of the Oasis Note through the conversion on January 31, 2017, at which time the remaining
$1.0 million
beneficial conversion feature was written-off and recognized as interest expense.
Subordinated Debt Facility
On December 27, 2016, we and Spark HoldCo jointly issued to Retailco, an entity owned by our Founder, a
5%
subordinated note in the principal amount of up to
$25.0 million
. The subordinated note allows the Company and
Spark HoldCo to draw advances in increments of no less than
$1.0 million
per advance up to the maximum principal amount of the subordinated note. The subordinated note matures in July 2020, and advances thereunder accrue interest at
5%
per annum from the date of the advance. The Company has the right to capitalize interest payments under the subordinated note. The subordinated note is subordinated in certain respects to the Company's Senior Credit Facility pursuant to a subordination agreement. The Company may pay interest and prepay principal on the subordinated note so long as it is in compliance with its covenants under the Senior Credit Facility, is not in default under the Senior Credit Facility and has minimum availability of
$5.0 million
under the borrowing base under the Senior Credit Facility. Payment of principal and interest under the subordinated note is accelerated upon the occurrence of certain change of control or sale transactions. As of
December 31, 2017
and
2016
, there were
zero
and
$5.0 million
, respectively, in outstanding borrowings under the subordinated note.
Pacific Summit Energy LLC
Prior to March 31, 2017, the Major Energy Companies were party to
three
trade credit arrangements with Pacific Summit Energy LLC (“Pacific Summit”), which consisted of purchase agreements, operating agreements relating to purchasing terms, security agreements, lockbox agreements and guarantees, and provided for the exclusive supply of gas and electricity on credit by Pacific Summit to the Major Energy Companies for resale to end users.
Under these arrangements, when the costs that Pacific Summit paid to procure and deliver the gas and electricity exceeded the payments that the Major Energy Companies made attributable to the gas and electricity purchased, the Major Energy Companies incurred interest on the difference. The operating agreements also allowed Pacific Summit to provide credit support. Each form of borrowing incurred interest at the floating 90-day LIBOR rate plus
300
basis points (except for certain credit support guaranties that did not bear interest). In connection with these arrangements, the Major Companies granted first liens to Pacific Summit on a substantial portion of the Major Companies’ assets, including present and future accounts receivable, inventory, liquid assets, and control agreements relating to bank accounts. As of
December 31, 2016
, the Company had aggregate outstanding amounts payable under these arrangements of approximately
$15.5 million
bearing an interest rate of approximately
4.0%
. The Company was also the beneficiary under various credit support guarantees issued by Pacific Summit under these arrangements as of such date. On September 27, 2016, we notified Pacific Summit of our election to trigger the expiration of these arrangements. On March 31, 2017, the agreements were terminated.
Verde Companies Promissory Note
In connection with the financing of the Verde Companies acquisition, on July 1, 2017, CenStar issued a promissory note in the aggregate principal amount of
$20.0 million
(the "Verde Promissory Note") for a portion of the purchase price. The Verde Promissory Note required
18
monthly installments beginning on August 1, 2017, and accrued
129
interest at
5%
per annum from the date of issuance. The Verde Promissory Note, including principal and interest, was unsecured, but is guaranteed by the Company. Payment of principal and interest under the Verde Promissory Note was accelerated upon the occurrence of certain events of default. As of
December 31, 2017
, there was
$14.6 million
outstanding under the Verde Promissory Note, of which
$13.4 million
is due in 2018.
On January 12, 2018, CenStar issued to the Seller an amended and restated promissory note (the “Amended and Restated Verde Promissory Note”), which amended and restated the Verde Promissory Note in connection with the termination of our earnout obligations under the purchase agreement for the Verde Companies. The Amended and Restated Verde Promissory Note, effective January 12, 2018, retains the same maturity date as the Verde Promissory Note. The Amended and Restated Verde Promissory Note bears interest at a rate of
9%
per annum beginning January 1, 2018. Principal and interest remain payable monthly on the first day of each month in which the Amended and Restated Verde Promissory Note is outstanding. CenStar will continue to deposit a portion of each payment under the Amended and Restated Verde Promissory Note into an escrow account, which serves as security for certain indemnification claims and obligations under the purchase agreement. The amount deposited into the escrow account has been increased from the Verde Promissory Note. All principal and interest payable under the Amended and Restated Verde Promissory Note remains subject to acceleration upon the occurrence of certain events of default, including the failure to pay any principal or interest when due under the Amended and Restated Verde Promissory Note.
Verde Earnout Termination Note
On January 12, 2018, we entered into an Agreement to Terminate Earnout Payments (the “Earnout Termination Agreement”) that terminates our obligation to make any required earnout payments under the purchase agreement for our acquisition of the Verde Companies in exchange for CenStar’s issuance to the Seller of a promissory note in the principal amount of
$5.9 million
(the “Verde Earnout Termination Note”). The Verde Earnout Termination Note, effective January 12, 2018, matures on June 30, 2019 (subject to early maturity upon certain events) and bears interest at a rate of
9%
per annum. CenStar is permitted to withhold amounts otherwise due at maturity related to certain indemnifiable matters under the purchase agreement for our acquisition of the Verde Companies. Interest is payable monthly on the first day of each month in which the Verde Earnout Termination Note is outstanding, beginning on its issuance date. The principal and any outstanding interest is due on June 30, 2019. All principal and interest payable under the Verde Earnout Termination Note is accelerated upon the occurrence of certain events of default, including the failure to pay any principal or interest when due under the Verde Earnout Termination Note. The Company recorded the Verde Earnout Termination Note of
$5.9 million
as long-term debt as of
December 31, 2017
.
9. 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 not only the credit standing of counterparties involved and the impact of credit enhancements but also the impact of the Company’s own nonperformance risk on its liabilities.
The Company applies fair value measurements to its commodity derivative instruments and a contingent payment arrangement based on the following fair value hierarchy, which prioritizes the inputs to 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
|
130
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 the Company's acquisitions.
|
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. In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. In these cases, the lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy.
Other Financial Instruments
The carrying amount of cash and cash equivalents, accounts receivable, accounts receivable—affiliates, accounts payable, accounts payable—affiliates, and accrued liabilities recorded in the consolidated balance sheets approximate fair value due to the short-term nature of these items. The carrying amounts of the Senior Credit Facility and Prior Senior Credit Facility recorded in the consolidated balance sheets approximate fair value because of the variable rate nature of the Company’s line of credit. The fair value of our convertible subordinated notes to affiliates is not determinable for accounting purposes due to the affiliate nature and terms of the associated debt instrument with the affiliate. The fair value of the payable pursuant to tax receivable agreement—affiliate is not determinable for accounting purposes due to the affiliate nature and terms of the associated agreement with the affiliate.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
The following tables present assets and liabilities measured and recorded at fair value in the Company’s consolidated balance sheets on a recurring basis by and their level within the fair value hierarchy as of (in thousands):
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
|
December 31, 2017
|
|
|
|
|
|
|
|
||||||||
|
Non-trading commodity derivative assets
|
$
|
158
|
|
|
$
|
33,886
|
|
|
$
|
—
|
|
|
$
|
34,044
|
|
|
Trading commodity derivative assets
|
—
|
|
|
456
|
|
|
—
|
|
|
456
|
|
||||
|
Total commodity derivative assets
|
$
|
158
|
|
$
|
34,342
|
|
$
|
—
|
|
$
|
34,500
|
|
|||
|
Non-trading commodity derivative liabilities
|
$
|
(387
|
)
|
|
$
|
(950
|
)
|
|
$
|
—
|
|
|
$
|
(1,337
|
)
|
|
Trading commodity derivative liabilities
|
(555
|
)
|
|
(237
|
)
|
|
—
|
|
|
(792
|
)
|
||||
|
Total commodity derivative liabilities
|
$
|
(942
|
)
|
$
|
(1,187
|
)
|
$
|
—
|
|
$
|
(2,129
|
)
|
|||
|
Contingent payment arrangement
|
$
|
—
|
|
$
|
—
|
|
$
|
(4,650
|
)
|
$
|
(4,650
|
)
|
|||
131
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
|
December 31, 2016
|
|
|
|
|
|
|
|||||||||
|
Non-trading commodity derivative assets
|
$
|
1,511
|
|
|
$
|
9,385
|
|
|
$
|
—
|
|
|
$
|
10,896
|
|
|
Trading commodity derivative assets
|
101
|
|
|
430
|
|
|
—
|
|
|
531
|
|
||||
|
Total commodity derivative assets
|
$
|
1,612
|
|
$
|
9,815
|
|
$
|
—
|
|
$
|
11,427
|
|
|||
|
Non-trading commodity derivative liabilities
|
$
|
—
|
|
|
$
|
(661
|
)
|
|
$
|
—
|
|
|
$
|
(661
|
)
|
|
Trading commodity derivative liabilities
|
—
|
|
|
(87
|
)
|
|
—
|
|
|
(87
|
)
|
||||
|
Total commodity derivative liabilities
|
$
|
—
|
|
$
|
(748
|
)
|
$
|
—
|
|
$
|
(748
|
)
|
|||
|
Contingent payment arrangement
|
$
|
—
|
|
$
|
—
|
|
$
|
(22,653
|
)
|
$
|
(22,653
|
)
|
|||
The Company had no transfers of assets or liabilities between any of the above levels during the years ended
December 31, 2017
,
2016
and
2015
.
The Company’s derivative contracts include exchange-traded contracts fair valued utilizing readily available quoted market prices and non-exch
ange-traded contra
cts fair valued using market price quotations available through brokers or over-the-counter and on-line exchanges. In addition, in determining the fair value of the Company’s derivative contracts, the Company applies a credit risk valuation adjustment to reflect credit risk, which is calculated based on the Company’s or the counterparty’s historical credit risks. As of
December 31, 2017
and
2016
, the credit risk valuation adjustment was not material.
The contingent payment arrangements referred to above reflect estimated earnout obligations incurred in relation to the Company's acquisitions. As of
December 31, 2017
, the estimated earnout obligations were
$4.6 million
, which was comprised of the Major Earnout and the Stock Earnout in the amount of
$4.6 million
, and
zero
, respectively. The final Provider Earnout payment was paid in June 2017. The Verde Earnout was settled for
$5.9 million
on January 12, 2018 with a promissory note payable to the Seller in June 2019 and is classified as long-term debt as of
December 31, 2017
. As of
December 31, 2016
, the estimated earnout obligations were
$22.7 million
, which was comprised of the Provider Earnout, the Major Earnout and the Stock Earnout in the amount of
$4.9 million
,
$17.1 million
, and
$0.7 million
, respectively. As of
December 31, 2017
, the estimated earnouts are recorded on our consolidated balance sheets in current liabilities - contingent consideration and long-term liabilities - contingent consideration in the amount of
$4.0 million
and
$0.6 million
respectively; and as of
December 31, 2016
, in current liabilities - contingent consideration and long-term liabilities - contingent consideration in the amount of
$11.8 million
and
$10.8 million
, respectively.
The Provider Earnout, the Major Earnout, and the Verde Earnout are discussed in Note
3 "Acquisitions."
The CenStar Earnout was based on a financial measurement attributable to the operations of CenStar for the year following the closing of the acquisition. In determining the fair value of the CenStar Earnout, the Company forecasted a one year performance measurement, as defined by the CenStar stock purchase agreement. As this calculation was based on management's estimates of the liability, we had classified the CenStar Earnout as a Level 3 measurement. During the first quarter of 2016, our estimate of the CenStar Earnout was increased to
$1.5 million
, which was based on the results of operations during such period. In August 2016, we entered into a settlement and release agreement with the seller of CenStar in which the Company paid
$1.3 million
to such seller and released an additional
$0.6 million
from escrow in full satisfaction of the earnout obligation under the CenStar stock purchase agreement. During the year ended December 31, 2016, the remaining estimated earnout liability of
$0.2 million
was written off via a reduction to general and administrative expense in our consolidated statements of operations.
The Provider Earnout was based on achievement by the Provider Companies of a certain customer count criteria over the
nine
month period following the closing of the Provider Companies acquisition. The sellers of the Provider Companies were entitled to a maximum of
$9.0 million
and a minimum of
$5.0 million
in earnout payments based on the level of customer count attained, as defined by the Provider Companies membership interest purchase agreement. In March and June 2017, the Company paid the sellers of the Provider Companies
$1.0 million
and
$4.5 million
, respectively, related to the earnout based on the achievement of certain customer count and sales targets.
132
During the year ended
December 31, 2017
, the Company recorded accretion of
$0.1 million
to reflect the impact of the time value of the liability prior to the final payment in June 2017. The Company additionally recorded
$0.5 million
of general and administrative expense related to the change in fair value of the earnout prior to the final payment in June 2017. During the period from August 1, 2016 (acquisition date) through December 31, 2016, the Company recorded accretion of
$0.1 million
to reflect the impact of the time value of the liability. In determining the fair value of the Provider Earnout, the Company forecasted an expected customer count and certain other related criteria and
calculated the probability of such forecast being attained. As this calculation was based on management's estimates of the liability, we classified the Provider Earnout as a Level 3 measurement.
The Major Earnout is based on the achievement by the Major Energy Companies of certain performance targets over the
33
month period following NG&E's closing of the Major Energy Companies acquisition (i.e., April 15, 2016). The previous members of Major Energy Companies are 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 is 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 earn such maximum Major Earnout payments, NG&E would be entitled 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, the Company forecasted certain expected performance targets and calculated the probability of such forecast being attained. In March 2017, the Company paid the previous members of the Major Energy Companies
$7.4 million
related to the period from April 15, 2016 through December 31, 2016. During the year ended
December 31, 2017
, the Company recorded accretion of
$3.8 million
to reflect the impact of the time value of the liability. The Company revalued the liability at
December 31, 2017
, resulting in the decrease of the fair value of the liability to
$4.6 million
. During the period from April 15, 2016 (NG&E acquisition date) through December 31, 2016, the Company recorded accretion of
$5.0 million
to reflect the impact of the time value of the liability. The Company revalued the liability at December 31, 2016, resulting in the write-down of the fair value of the liability to
$17.8 million
. The impact of the
$9.6 million
and
$1.1 million
decrease in fair value is recorded in general and administrative expenses for the years ended
December 31, 2017
and
2016
, respectively. As this calculation is based on management's estimates of the liability, we classified the Major Earnout as a Level 3 measurement.
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 acquisition of the Verde Companies. The Verde Earnout was valued at
$5.4 million
as of July 1, 2017, the acquisition date. The Company and the Seller agreed to terminate the Verde Earnout on January 12, 2018, and settled the obligation with the issuance of a
$5.9 million
promissory note payable due to the Seller in June 2019 (the “Verde Earnout Termination Note”). The Company recorded a
$0.3 million
increase in fair value of the Verde Earnout in general and administrative expenses and classified the liability as long-term debt as of
December 31, 2017
. During the year ended
December 31, 2017
, the Company recorded accretion of
$0.2 million
to reflect the impact of the time value of the liability. In determining the fair value of the Verde Earnout, the Company forecasted certain expected performance targets and calculated the probability of such forecast being attained. As the calculation was based on management's estimates of the liability, we classified the Verde Earnout liability as a Level 3 measurement prior to settlement. See discussion of the Verde Earnout Termination Note in Note
8 "Debt."
The following tables present reconciliations of liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the years ended
December 31, 2017
and
2016
, respectively.
133
|
|
CenStar Earnout
|
|
Major Earnout and Stock Earnout
|
|
Provider Earnout
|
|
Verde Earnout
|
Total
|
||||||||||
|
Fair Value at December 31, 2015
|
$
|
500
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
$
|
500
|
|
|
Purchase price contingent consideration
|
$
|
—
|
|
|
$
|
13,910
|
|
|
$
|
4,823
|
|
|
$
|
—
|
|
18,733
|
|
|
|
Change in fair value of contingent consideration, net
|
843
|
|
|
(1,140
|
)
|
|
—
|
|
|
—
|
|
(297
|
)
|
|||||
|
Accretion of contingent earnout consideration (included within interest expense)
|
—
|
|
|
4,990
|
|
|
70
|
|
|
—
|
|
5,060
|
|
|||||
|
Payments and settlements
(1)
|
(1,343
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
(1,343
|
)
|
|||||
|
Fair Value at December 31, 2016
|
$
|
—
|
|
$
|
17,760
|
|
$
|
4,893
|
|
$
|
—
|
|
$
|
22,653
|
|
|||
|
Purchase price consideration
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
5,400
|
|
$
|
5,400
|
|
|
Change in fair value of contingent consideration, net
|
—
|
|
|
(9,555
|
)
|
|
500
|
|
|
347
|
|
(8,708
|
)
|
|||||
|
Accretion of contingent earnout consideration (included within interest expense)
|
—
|
|
|
3,848
|
|
|
107
|
|
|
153
|
|
4,108
|
|
|||||
|
Payments and settlements
(1)
|
—
|
|
|
(7,403
|
)
|
|
(5,500
|
)
|
|
(5,900
|
)
|
(18,803
|
)
|
|||||
|
Fair Value at December 31, 2017
|
$
|
—
|
|
$
|
4,650
|
|
$
|
—
|
|
$
|
—
|
|
$
|
4,650
|
|
|||
(1) Payments and settlements include pay downs at maturity and the termination of the Verde Earnout liability, which was replaced with the Verde Earnout Termination Note. See discussion above and in Note 8 "Debt."
Assets and Liabilities Measured at Fair Value on a Non-recurring Basis
We apply the provisions of the fair value measurement standard to our non-recurring, non-financial measurements including business combinations as well as impairment related to goodwill and other long-lived assets. For business combinations (see Note
3 "Acquisitions"
), the purchase price is allocated to the assets acquired and liabilities assumed based on a discounted cash flow model for most intangibles as well as market assumptions for the valuation of equipment and other fixed assets. We utilize a discounted cash flow model in evaluating impairment considerations related to goodwill and long-lived assets. Given the unobservable nature of the inputs, the discounted cash flow models are considered to use Level 3 inputs.
10. Accounting for Derivative Instruments
The Company is exposed to the impact of market fluctuations in the price of electricity and natural gas and basis costs, storage and ancillary capacity charges from independent system operators. The Company uses derivative instruments to manage exposure to these risks, and historically designated certain derivative instruments as cash flow hedges for accounting purposes.
The Company holds certain derivative instruments that are not held for trading purposes and are not designated as hedges for accounting purposes. These derivative instruments represent economic hedges that mitigate the Company’s exposure to fluctuations in commodity prices. For these derivative instruments, changes in the fair value are recognized currently in earnings in retail revenues or retail cost of revenues.
As part of the Company’s strategy to optimize its assets and manage related risks, it also manages a portfolio of commodity derivative instruments held for trading purposes. The Company’s commodity trading activities are subject to limits within the Company’s 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 the Company’s consolidated balance sheets when the derivative instruments are executed with the same counterparty under a master netting arrangement. The Company’s derivative contracts include transactions that are executed both on an exchange and centrally cleared, as well as over-the-
134
counter, bilateral contracts that are transacted directly with a third party. To the extent the Company has 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, 2017
and
2016
, the Company had paid
$0.1 million
and
zero
in collateral outstanding, respectively. The specific types of derivative instruments the Company may execute to manage the commodity price risk include the following:
|
•
|
Forward contracts, which commit the Company 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 and are therefore not accounted for at fair value including the following:
•
Forward electricity and natural gas purchase contracts for retail customer load; and,
•
Natural gas transportation contracts and storage agreements.
Volumetric Underlying Derivative Transactions
The following table summarizes the net notional volume buy/(sell) of the Company’s open derivative financial instruments accounted for at fair value, broken out by commodity, as of (in thousands):
Non-trading
|
Commodity
|
Notional
|
December 31, 2017
|
December 31, 2016
|
||||
|
Natural Gas
|
MMBtu
|
9,191
|
|
8,016
|
|
||
|
Natural Gas Basis
|
MMBtu
|
—
|
|
—
|
|
||
|
Electricity
|
MWh
|
8,091
|
|
3,958
|
|
||
Trading
|
Commodity
|
Notional
|
December 31, 2017
|
December 31, 2016
|
||||
|
Natural Gas
|
MMBtu
|
26
|
|
(953
|
)
|
||
|
Natural Gas Basis
|
MMBtu
|
(225
|
)
|
(380
|
)
|
||
Gains (Losses) on Derivative Instruments
Gains (losses) on derivative instruments, net and current period settlements on derivative instruments were as follows for the periods indicated (in thousands):
135
|
|
Year Ended December 31,
|
||||||||||
|
|
2017
|
2016
|
2015
|
||||||||
|
Gain (loss) on non-trading derivatives, net
|
5,588
|
|
22,254
|
|
(18,423
|
)
|
|||||
|
(Loss) gain on trading derivatives, net
|
(580
|
)
|
153
|
|
(74
|
)
|
|||||
|
Gain (loss) on derivatives, net
|
$
|
5,008
|
|
$
|
22,407
|
|
$
|
(18,497
|
)
|
||
|
Current period settlements on non-trading derivatives
(1) (2) (3) (4)
|
16,508
|
|
(2,284
|
)
|
20,279
|
|
|||||
|
Current period settlements on trading derivatives
|
(199
|
)
|
138
|
|
268
|
|
|||||
|
Total current period settlements on derivatives
(1) (2) (3) (4)
|
$
|
16,309
|
|
$
|
(2,146
|
)
|
$
|
20,547
|
|
||
(1) Excludes settlements of less than
$0.1 million
,
$1.0 million
and
$3.4 million
, respectively, for the years ended
December 31, 2017
,
2016
, and
2015
related to non-trading derivative liabilities assumed in the acquisitions of CenStar and Oasis.
(2) Excludes settlements of
$0.5 million
and
$25.6 million
, respectively, for the years ended
December 31, 2017
and
2016
related to non-trading derivative liabilities assumed in the acquisitions of Provider Companies and Major Energy Companies.
(3) Excludes settlements of
$1.1 million
for the year ended
December 31, 2017
related to non-trading derivative liabilities assumed in the acquisitions of Perigee and other customers.
(4) Excludes settlements of
$1.7 million
for the year ended
December 31, 2017
related to non-trading derivative liabilities assumed in the acquisition of the Verde Companies.
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 the Company’s derivative instruments by counterparty and collateral received or paid as of (in thousands):
|
|
December 31, 2017
|
||||||||||||||||||
|
Description
|
Gross Assets
|
|
Gross
Amounts Offset |
|
Net Assets
|
|
Cash
Collateral Offset |
|
Net Amount
Presented |
||||||||||
|
Non-trading commodity derivatives
|
$
|
60,167
|
|
$
|
(29,432
|
)
|
$
|
30,735
|
|
$
|
—
|
|
$
|
30,735
|
|
||||
|
Trading commodity derivatives
|
918
|
|
(462
|
)
|
456
|
|
—
|
|
456
|
|
|||||||||
|
Total Current Derivative Assets
|
61,085
|
|
(29,894
|
)
|
31,191
|
|
—
|
|
31,191
|
|
|||||||||
|
Non-trading commodity derivatives
|
16,055
|
|
(12,746
|
)
|
3,309
|
|
—
|
|
3,309
|
|
|||||||||
|
Trading commodity derivatives
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|||||||||
|
Total Non-current Derivative Assets
|
16,055
|
|
(12,746
|
)
|
3,309
|
|
—
|
|
3,309
|
|
|||||||||
|
Total Derivative Assets
|
$
|
77,140
|
|
$
|
(42,640
|
)
|
$
|
34,500
|
|
$
|
—
|
|
$
|
34,500
|
|
||||
|
|
December 31, 2017
|
||||||||||||||||||
|
Description
|
Gross
Liabilities |
|
Gross
Amounts Offset |
|
Net
Liabilities |
|
Cash
Collateral Offset |
|
Net Amount
Presented |
||||||||||
|
Non-trading commodity derivatives
|
$
|
(4,517
|
)
|
$
|
3,059
|
|
$
|
(1,458
|
)
|
$
|
65
|
|
$
|
(1,393
|
)
|
||||
|
Trading commodity derivatives
|
(517
|
)
|
273
|
|
(244
|
)
|
—
|
|
(244
|
)
|
|||||||||
|
Total Current Derivative Liabilities
|
(5,034
|
)
|
3,332
|
|
(1,702
|
)
|
65
|
|
(1,637
|
)
|
|||||||||
|
Non-trading commodity derivatives
|
(676
|
)
|
732
|
|
56
|
|
|
|
56
|
|
|||||||||
|
Trading commodity derivatives
|
(566
|
)
|
18
|
|
(548
|
)
|
—
|
|
(548
|
)
|
|||||||||
|
Total Non-current Derivative Liabilities
|
(1,242
|
)
|
750
|
|
(492
|
)
|
—
|
|
(492
|
)
|
|||||||||
|
Total Derivative Liabilities
|
$
|
(6,276
|
)
|
$
|
4,082
|
|
$
|
(2,194
|
)
|
$
|
65
|
|
$
|
(2,129
|
)
|
||||
136
|
|
December 31, 2016
|
||||||||||||||||||
|
Description
|
Gross Assets
|
|
Gross
Amounts Offset |
|
Net Assets
|
|
Cash
Collateral Offset |
|
Net Amount
Presented |
||||||||||
|
Non-trading commodity derivatives
|
$
|
19,657
|
|
|
$
|
(11,844
|
)
|
|
$
|
7,813
|
|
|
$
|
—
|
|
|
$
|
7,813
|
|
|
Trading commodity derivatives
|
614
|
|
|
(83
|
)
|
|
531
|
|
|
—
|
|
|
531
|
|
|||||
|
Total Current Derivative Assets
|
20,271
|
|
|
(11,927
|
)
|
|
8,344
|
|
|
—
|
|
|
8,344
|
|
|||||
|
Non-trading commodity derivatives
|
7,874
|
|
|
(4,791
|
)
|
|
3,083
|
|
|
—
|
|
|
3,083
|
|
|||||
|
Total Non-current Derivative Assets
|
7,874
|
|
|
(4,791
|
)
|
|
3,083
|
|
|
—
|
|
|
3,083
|
|
|||||
|
Total Derivative Assets
|
$
|
28,145
|
|
|
$
|
(16,718
|
)
|
|
$
|
11,427
|
|
|
$
|
—
|
|
|
$
|
11,427
|
|
|
|
December 31, 2016
|
||||||||||||||||||
|
Description
|
Gross
Liabilities |
|
Gross
Amounts Offset |
|
Net
Liabilities |
|
Cash
Collateral Offset |
|
Net Amount
Presented |
||||||||||
|
Non-trading commodity derivatives
|
$
|
(662
|
)
|
|
$
|
69
|
|
|
$
|
(593
|
)
|
|
|
|
|
$
|
(593
|
)
|
|
|
Trading commodity derivatives
|
(92
|
)
|
|
5
|
|
|
(87
|
)
|
|
—
|
|
|
(87
|
)
|
|||||
|
Total Current Derivative Liabilities
|
(754
|
)
|
|
74
|
|
|
(680
|
)
|
|
—
|
|
|
(680
|
)
|
|||||
|
Non-trading commodity derivatives
|
(305
|
)
|
|
237
|
|
|
(68
|
)
|
|
—
|
|
|
(68
|
)
|
|||||
|
Total Non-current Derivative Liabilities
|
(305
|
)
|
|
237
|
|
|
(68
|
)
|
|
—
|
|
|
(68
|
)
|
|||||
|
Total Derivative Liabilities
|
$
|
(1,059
|
)
|
|
$
|
311
|
|
|
$
|
(748
|
)
|
|
$
|
—
|
|
|
$
|
(748
|
)
|
11. Stock-Based Compensation
Restricted Stock Units
In connection with the IPO, the Company adopted the Spark Energy, Inc. Long-Term Incentive Plan for the employees, consultants and directors of the Company and its affiliates who perform services for the Company. The Long-Term Incentive Plan was amended and restated on September 1, 2016 (as amended and restated, the "LTIP"). 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.
Periodically the Company grants restricted stock units to our officers, employees, non-employee directors and certain employees of our affiliates who perform services for the Company. The restricted stock unit awards vest over approximately
one
year for non-employee directors and ratably over approximately
three
or
four
years for officers, employees, and employees of affiliates, with the initial vesting date occurring in May of the subsequent year. 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 shall be 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.
In accordance with ASC 718,
Compensation - Stock Compensation (“ASC 718”)
, 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
137
estimated to occur. The Company has elected to recognize related compensation expense on a straight-line basis over the associated vesting periods.
Although the restricted stock units allow for cash settlement of the awards at the sole discretion of management of the Company, management intends to settle the awards by issuing shares of the Company’s Class A common stock.
Total stock-based compensation expense for the years ended
December 31, 2017
,
2016
and
2015
was
$5.1 million
,
$5.2 million
and
$3.2 million
. Total income tax benefit related to stock-based compensation recognized in net income (loss) was
$2.1 million
,
$2.1 million
and
$1.2 million
for the years ended
December 31, 2017
,
2016
and
2015
.
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
$2.8 million
,
$2.3 million
and
$2.2 million
for the years ended
December 31, 2017
,
2016
and
2015
, 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, 2017
:
|
|
Number of Shares (in thousands)
|
Weighted Average Grant Date Fair Value
|
|||
|
Unvested at December 31, 2016
|
526
|
|
$
|
9.56
|
|
|
Granted
|
307
|
|
18.10
|
|
|
|
Dividend reinvestment issuances
|
27
|
|
15.64
|
|
|
|
Vested
|
(180
|
)
|
17.88
|
|
|
|
Forfeited
|
(40
|
)
|
13.27
|
|
|
|
Unvested at December 31, 2017
|
640
|
|
$
|
11.56
|
|
For the year ended
December 31, 2017
,
179,628
restricted stock units vested, with
118,514
shares of Class A common stock distributed to the holders of these units and
61,114
shares of Class A common stock withheld by the Company to cover taxes owed on the vesting of such units.
As of
December 31, 2017
, there was
$7.4 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
2.9
years.
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 in accordance with ASC 718 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
$2.3 million
and
$3.0 million
and
$1.0 million
for years ended
December 31, 2017
,
2016
and
2015
, respectively, in general and administrative expense with a corresponding increase to liabilities. As of
December 31, 2017
, the Company’s liabilities related to these restricted stock units recorded in current liabilities was
$0.7 million
. As of
December 31, 2016
, the Company's liabilities related to these restricted stock units recorded in current liabilities was
$1.5 million
.
138
The following table summarizes liability classified restricted stock unit activity and unvested restricted stock units for the year ended
December 31, 2017
:
|
|
Number of Shares (in thousands)
|
Weighted Average Reporting Date Fair Value
|
|||
|
Unvested at December 31, 2016
|
252
|
|
$
|
15.15
|
|
|
Granted
|
140
|
|
12.40
|
|
|
|
Dividend reinvestment issuances
|
10
|
|
12.40
|
|
|
|
Vested
|
(176
|
)
|
16.93
|
|
|
|
Forfeited
|
(2
|
)
|
12.40
|
|
|
|
Unvested at December 31, 2017
|
224
|
|
$
|
12.40
|
|
For the year ended
December 31, 2017
,
176,386
restricted stock units vested, with
123,451
shares of Class A common stock distributed to the holders of these units and
52,935
shares of Class A common stock withheld by the Company to cover taxes owed on the vesting of such units.
As of
December 31, 2017
, there was
$1.8 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
2.5
years.
12. Income Taxes
The Company, CenStar and Verde Energy USA, Inc. (Verde Corp) are each subject to U.S. federal income tax as corporations. CenStar and Verde Corp will 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, the Company is subject to U.S. federal income taxation on its allocable share of Spark HoldCo's net U.S. taxable income.
The Company reports federal and state income taxes for its share of the partnership income attributable to its ownership in Spark HoldCo and for the income taxes attributable to CenStar, a C-corporation, which is owned by Spark HoldCo. The income tax liability for the partnership does not accrue to the partnership, but rather the investors are responsible for the income taxes based upon the investor's share of the partnership's income. Net income attributable to the non-controlling interest in CenStar includes the provision for income taxes.
The Company accounts for income taxes using the assets and liabilities 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. The Company applies existing tax law and the tax rate that the Company expects 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.
On December 22, 2017, the President signed the Tax Cuts and Jobs Act (“U.S. Tax Reform”), which enacts a wide range of changes to the U.S. Corporate income tax system. The impact of U.S. Tax Reform primarily represents our estimates of revaluing 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. Based on our historical financial performance, at December 31, 2017 we have a significant net deferred tax asset position that we have remeasured at the lower corporate rate of
21%
and recognized a tax expense to adjust net deferred tax assets to the reduced value.
139
The provision for income taxes included the following components:
|
(in thousands)
|
|
2017
|
|
2016
|
2015
|
|||||||
|
Current:
|
|
|
|
|
||||||||
|
Federal
|
|
$
|
6,992
|
|
$
|
5,361
|
|
$
|
268
|
|
||
|
State
|
|
1,952
|
|
1,683
|
|
(277
|
)
|
|||||
|
Total Current
|
8,944
|
|
7,044
|
|
(9
|
)
|
||||||
|
|
|
|||||||||||
|
Deferred:
|
|
|||||||||||
|
Federal
|
|
26,583
|
|
2,944
|
|
1,820
|
|
|||||
|
State
|
|
2,001
|
|
438
|
|
163
|
|
|||||
|
Total Deferred
|
|
28,584
|
|
3,382
|
|
1,983
|
|
|||||
|
Provision for income taxes
|
|
$
|
37,528
|
|
$
|
10,426
|
|
$
|
1,974
|
|
||
The effective income tax rate was
33.0%
and
13.7%
for the years ended
December 31, 2017
and
2016
, respectively. The following table reconciles the income tax benefit included in the consolidated statement of operations with income tax expense that would result from application of the statutory federal tax rate,
35%
for the years ended
December 31, 2017
and
2016
, respectively, to loss before income tax expense (benefit):
|
(in thousands)
|
2017
|
2016
|
||||
|
Expected provision at federal statutory rate
|
$
|
39,833
|
|
$
|
26,635
|
|
|
Increase (decrease) resulting from:
|
|
|||||
|
Impact of U.S. Tax Reform
|
13,217
|
|
—
|
|
||
|
Non-controlling interest
|
(19,810
|
)
|
(17,740
|
)
|
||
|
State income taxes, net of federal income tax effect
|
2,569
|
|
1,346
|
|
||
|
Other
|
1,719
|
|
185
|
|
||
|
Provision for income taxes
|
$
|
37,528
|
|
$
|
10,426
|
|
Total income tax expense for the year ended
December 31, 2017
differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income primarily due to state taxes and the impact of permanent differences between book and taxable income, most notably the income attributable to non-controlling interest. The effective tax rate includes a rate benefit attributable to the fact that Spark HoldCo operates as a limited liability company treated as a partnership for federal and state income tax purposes and is not subject to federal and state income taxes. Accordingly, the portion of earnings attributable to non-controlling interest is subject to tax when reported as a component of the non-controlling interest’s taxable income. The effective rate in 2017 includes a
$13.2 million
unfavorable impact resulting from the enactment of U.S. Tax Reform. The primary impact of the change in tax law was the remeasurment of our U.S. federal deferred tax assets and liabilities at the tax rate expected to be applied when the temporary differences are settled at a rate of
21%
.
The Company accounts for income taxes using the assets and liabilities 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 those assets and liabilities tax bases. The Company applies existing tax law and the tax rate that the Company expects 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. We remeasured our deferred tax assets and liabilities, excluding those that will be included on our 2017 tax return based on the rates we expect to realize the deferred tax assets and liabilities at in the future. The amount that was recorded related to the remeasurement of our deferred tax balance was
$13.2 million
of tax expense. 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.
The components of the Company’s deferred tax assets as of
December 31, 2017
and
2016
are as follows:
140
|
(in thousands)
|
2017
|
2016
|
||||
|
Deferred Tax Assets:
|
||||||
|
Investment in Spark HoldCo
|
$
|
18,340
|
|
$
|
35,359
|
|
|
Benefit of TRA Liability
|
8,175
|
|
19,705
|
|
||
|
Federal net operating loss carryforward
|
660
|
|
2,076
|
|
||
|
State net operating loss carryforward
|
166
|
|
366
|
|
||
|
Total deferred tax assets
|
27,341
|
|
57,506
|
|
||
|
Deferred Tax Liabilities:
|
||||||
|
Derivative liabilities
|
(811
|
)
|
(1,849
|
)
|
||
|
Intangibles
|
(2,287
|
)
|
(1,519
|
)
|
||
|
Property and equipment
|
—
|
|
(10
|
)
|
||
|
Other
|
(58
|
)
|
(19
|
)
|
||
|
Total deferred tax liabilities
|
(3,156
|
)
|
(3,397
|
)
|
||
|
Total deferred tax assets/liabilities
|
$
|
24,185
|
|
$
|
54,109
|
|
On the IPO date, the Company recorded a net deferred tax asset of
$15.6 million
related to the step up in tax basis resulting from the purchase by the Company of Spark HoldCo units from NuDevco. In addition, the Company had a long-term liability of
$20.7 million
to record the effect of the Tax Receivable Agreement liability and a corresponding long-term deferred tax asset of
$7.9 million
. As of
December 31, 2017
and
2016
, the Company had a total liability of
$32.3 million
and
$49.9 million
, respectively, for the effect of the Tax Receivable Agreement liability. The Company adjusted the Tax Receivable Agreement liability at December 31, 2017 to include the 2016 tax returns filed. The adjustment resulted in an increase to the liability of
$4.7 million
, of which
$1.8 million
increased the deferred tax asset and
$2.9 million
decreased equity. On December 22, 2017, the President signed the Tax Cuts and Jobs Act (“U.S. Tax Reform”), which enacts a wide range of changes to the U.S. Corporate income tax system including a reduction in the U.S. corporate tax rate to 21% effective in 2018. The revised corporate income tax rate reduces the amount of net cash savings to be realized in future periods. Therefore, we have reduced the TRA liability as of December 31, 2017 by
$22.3 million
to reflect the effect of U.S. Tax Reform and recorded this adjustment through Other Income. The Company had a long-term deferred tax asset of approximately
$8.2 million
related to the Tax Receivable Agreement liability at
December 31, 2017
. See Note
14 "Transactions with Affiliates"
for further discussion.
The Company has a federal net operating loss carry forward totaling
$3.8 million
expiring in 2037 and a state net operating loss of
$4.1 million
expiring through 2037. No valuation allowance has been recorded as management believes that there will be sufficient future taxable income to fully utilize deferred tax assets.
The Company periodically assesses whether it is more likely than not that it will generate sufficient taxable income to realize its deferred income tax assets. In making this determination, the Company considers all available positive and negative evidence and makes certain assumptions. The Company considers, among other things, its deferred tax liabilities, the overall business environment, its historical earnings and losses, current industry trends, and its outlook for future years. The Company believes it is more likely than not that the deferred tax assets will be utilized.
On February 3, 2016, Retailco exchanged
2,000,000
of its Spark HoldCo units (together with a corresponding number of shares of Class B common stock) for shares of Class A common stock. The exchange resulted in a step up in tax basis, which gave rise to a deferred tax asset of approximately
$8.0 million
on the exchange date. In addition, the Company recorded an additional long-term liability as a result of the exchange of approximately
$10.3 million
pursuant to the Tax Receivable Agreement and a corresponding long-term deferred tax asset of approximately
$3.9 million
. The initial estimate for the deferred tax asset, net of the liability, under the Tax Receivable Agreement was recorded within additional paid-in capital on our consolidated balance sheet at
December 31, 2017
.
141
On April 1, 2016, Retailco exchanged
3,450,000
of its Spark HoldCo units (together with a corresponding number of shares of Class B common stock) for shares of Class A common stock. The exchange resulted
in a step up in tax basis, which gave rise to a deferred tax asset of approximately
$7.6 million
on the exchange date. In addition, the Company recorded an additional long-term liability as a result of the exchange of approximately
$10.3 million
pursuant to the Tax Receivable Agreement and a corresponding long-term deferred tax asset of approximately
$3.9 million
. The initial estimate for the deferred tax asset, net of the liability, under the Tax Receivable Agreement was recorded within additional paid-in capital on our consolidated balance sheet at
December 31, 2017
.
On June 8, 2016, Retailco exchanged
1,000,000
of its Spark HoldCo units (together with a corresponding number of shares of Class B common stock) for shares of Class A common stock. The exchange resulted in a step up in tax basis, which gave rise to a deferred tax asset of approximately
$5.3 million
on the exchange date. In addition, the Company recorded an additional long-term liability as a result of the exchange of approximately
$6.9 million
pursuant to the Tax Receivable Agreement and a corresponding long-term deferred tax asset of approximately
$2.6 million
. The initial estimate for the deferred tax asset, net of the liability, under the Tax Receivable Agreement was recorded within additional paid-in capital on our consolidated balance sheet at
December 31, 2017
.
Separate federal and state income tax returns are filed for Spark Energy, Inc. and Spark HoldCo. CenStar owns all the outstanding stock of Verde Corp and both are taxed as corporations. CenStar and Verde will file a federal consolidated return for 2017 and separate state income tax returns in the states that do not allow combined reporting. The tax years 2013 through 2016 remain open to examination by the major taxing jurisdictions to which the Company is subject to income tax. NuDevco would be responsible for any audit adjustments incurred in connection with transactions occurring up to July 31, 2014 for Spark Energy, Inc. and Spark HoldCo. The last closed audit period of exam was for the 2011 Spark Energy, LLC’s federal tax return and resulted in no adjustments by the IRS. Spark Energy, Inc., Spark HoldCo, ,CenStar, and Verde Corp are not currently under any income tax audits.
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, 2017
and
2016
there was no liability, and for the years ended
December 31, 2017
,
2016
and
2015
, there was
no
expense recorded for interest and penalties associated with uncertain tax positions or unrecognized tax positions. Additionally, the Company does
no
t have unrecognized tax benefits as of
December 31, 2017
and
2016
.
13. Commitment and Contingencies
From time to time, the Company may be involved in legal, tax, regulatory and other proceedings in the ordinary course of business. Other than proceedings discussed below, management does not believe that we are a party to any litigation, claims or proceedings that will have a material impact on the Company’s consolidated financial condition or results of operations. Liabilities for loss contingencies arising from claims, assessments, litigations or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.
Indirect Tax Audits
The Company is undergoing various types of indirect tax audits spanning from years 2009 to 2017 for which the Company 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, 2017
, we have accrued of
$1.7 million
related to indirect tax audits. The outcome of these indirect tax audits may result in additional expense.
Legal Proceedings
The Company is the subject of the following lawsuits. At the time of filing these consolidated financial statements, this litigation is at an early stage and subject to substantial uncertainties concerning the outcome of material factual
142
and legal issues. Accordingly, we cannot currently predict the manner and timing of the resolution of this litigation or estimate a range of possible losses or a minimum loss that could result from an adverse verdict in a potential lawsuit.
John Melville et al v. Spark Energy Inc. and Spark Energy Gas, LLC
is a purported class action filed on December 17, 2015 in the United States District Court for the District of New Jersey alleging, among other things, that (i)
sales representatives engaged as independent contractors for Spark Energy Gas, LLC engaged in deceptive acts in violation of the New Jersey Consumer Fraud Act, and (ii) Spark Energy Gas, LLC breached its contract with plaintiff, including a breach of the covenant of good faith and fair dealing. On September 5, 2017, the parties reached a confidential settlement in this matter, which the Company expensed and paid in the fourth quarter of 2017.
Halifax-American Energy Company, LLC et al v. Provider Power, LLC, Electricity N.H., LLC, Electricity Maine, LLC, Emile Clavet and Kevin Dean
is a lawsuit initially filed on June 12, 2014, in the Rockingham County Superior Court, State of New Hampshire, alleging various claims related to the Provider Companies’ employment of a sales contractor formerly employed with one or more of the plaintiffs, including misappropriation of trade secrets and tortious interference with a contractual relationship. The relief sought included compensatory and punitive damages and attorney's fees. The dispute occurred prior to the Company's acquisition of the Provider Companies. Portions of the original claim proceeded to trial and on January 19, 2016, a jury found in favor of the plaintiffs. Damages totaling approximately
$0.6 million
and attorneys' fees totaling approximately
$0.3 million
were awarded to the plaintiffs. On May 4, 2016, following post-verdict motions, the defendants filed an appeal in the State of New Hampshire Supreme Court, appealing, among other things the failure of the trial court to direct a verdict for the defendants, to set aside the verdict, or grant judgment for the defendants, and the trial court's award of certain attorneys' fees. The appellate hearing was held on June 1, 2017. The New Hampshire Supreme Court decided the appeal on February 9, 2018, upholding the jury's verdict and the trial court's rulings in all respects. As of
December 31, 2017
, the Company has accrued approximately
$1.0 million
in contingent liabilities related to this litigation. Initial damages and attorneys' fees have been factored into the purchase price for the Provider Companies, and the Company believes it has full indemnity coverage for any actual exposure in this appeal.
Katherine Veilleux and Jennifer Chon, individually and on behalf of all other similarly situated v. Electricity Maine. LLC, Provider Power, LLC, Spark HoldCo, LLC, Kevin Dean and Emile Clavet
is a purported class action lawsuit filed on November 18, 2016 in the United States District Court of Maine, alleging that Electricity Maine, LLC, an entity acquired by Spark HoldCo, LLC in mid-2016, enrolled and re-enrolled customers through fraudulent and misleading advertising, promotions, and other communications prior to the acquisition. Plaintiffs further allege that some improper enrollment and re-enrollment practices have continued to the present date. Plaintiffs allege the following claims against all defendants: violation of the Maine Unfair Trade Practices Act, violation of RICO, negligence, negligent misrepresentation, fraudulent misrepresentation, unjust enrichment and breach of contract. Plaintiffs seek unspecified damages for themselves and the purported class, rescission of contracts with Electricity Maine, injunctive relief, restitution, and attorney’s fees. By order dated November 15, 2017, the Court, pursuant to Rule 12(b)(6), dismissed all claims against Spark HoldCo except the claims for violation of the Maine Unfair Trade Practices Act and for unjust enrichment. Discovery limited to issues relevant to class certification under Rule 23 of the Federal Rules of Civil Procedure has just begun. Spark HoldCo intends to vigorously defend this matter and the allegations asserted therein, including the request to certify a class. Given the early stages of this matter, we cannot predict the outcome or consequences of this case at this time. The Company believes it is fully indemnified for this litigation matter, subject to certain limitations.
Gillis et al. v. Respond Power, LLC
is a purported class action lawsuit that was originally filed on May 21, 2014 in the Philadelphia Court of Common Pleas. On June 23, 2014, the case was removed to the United States District Court for the Eastern District of Pennsylvania. On September 15, 2014, the plaintiffs filed an amended class action complaint seeking a declaratory judgment that the disclosure statement contained in Respond Power, LLC’s variable rate contracts with Pennsylvania consumers limited the variable rate that could be charged to no more than the monthly rate charged by the consumers’ local utility company. The plaintiffs also allege that Respond Power, LLC (i) breached its variable rate contract with Pennsylvania consumers, and the covenant of good faith and fair dealing therein, by charging rates in excess of the monthly rate charged by the consumers’ local utility company; (ii)
143
engaged in deceptive conduct in violation of the Pennsylvania Unfair Trade Practices and Consumer Protection Law; and (iii) engaged in negligent misrepresentation and fraudulent concealment in connection with purported promises of savings. The amount of damages sought is not specified. By order dated August 31, 2015, the district court denied class certification. The plaintiffs appealed the district court’s denial of class certification to the United States Court of Appeals for the Third Circuit. The United States Court of Appeals for the Third Circuit vacated the district court’s denial of class certification and remanded the matter to the district court for further proceedings. The district court ordered briefing on defendant’s motion to dismiss. Respond Power LLC filed a motion to dismiss the plaintiffs’ declaratory judgment and breach of contract claims (the class claims) on June 30, 2017. The motion is fully briefed and submitted, and the parties are awaiting a decision from the Court. The Company currently cannot predict the outcome or consequences of this case at this time. The Company believes it is fully indemnified for this litigation matter, subject to certain limitations.
Jurich v. Verde Energy USA, Inc
., is a purported class action originally filed on March 3, 2015 in the United States District Court for the District of Connecticut and subsequently re-filed on October 8, 2015 in the Superior Court of Judicial District of Hartford, State of Connecticut. The Amended Complaint asserts that the Verde Companies charged rates in violation of its contracts with Connecticut customers and alleges (i) violation of the Connecticut Unfair Trade Practices Act and (ii) breach of the covenant of good faith and fair dealing. Plaintiffs are seeking unspecified actual and punitive damages for the purported class and injunctive relief. The parties have exchanged initial discovery. Plaintiffs’ motion for class certification was briefed and the Verde Companies filed its opposition to plaintiffs’ motion for class certification on October 17, 2017. On December 6, 2017, the Court granted the plaintiffs’ class certification motion. However, the Court opted not to send out class notices, and instead directed the parties to submit briefing on legal issues that could result in a modification or decertification of the class. The parties have proposed to the Court that initial briefing on such motions would be due March 16, 2018. As part of an agreement in connection with the acquisition of the Verde Companies, the original owners of the Verde Companies are handling this matter. Given the early stage of this matter, we cannot predict the outcome or consequences of this case at this time. The Company believes it is fully indemnified for this litigation matter by the original owners of the Verde Companies, subject to certain limitations.
Richardson et al v. Verde Energy USA, Inc.
is a purported class action filed on November 25, 2015 in the United States District Court for the Eastern District of Pennsylvania alleging that the Verde Companies violated the Telephone Consumer Protection Act by placing marketing calls using an automatic telephone dialing system or a prerecorded voice to the purported class members’ cellular phones without prior express consent and by continuing to make such calls after receiving requests for the calls to cease. Plaintiffs are seeking statutory damages for the purported class and injunctive relief prohibiting Verde Companies' alleged conduct. Discovery on the claims of the named plaintiffs closed on November 10, 2017, and dispositive motions on the named plaintiffs’ claims was filed on November 24, 2017. Plaintiffs’ response to dispositive motions’ pleadings was filed on December 22, 2017 and Verde Companies’ reply briefs were filed on January 5, 2018. To date, no hearing has been set on these motions. As part of an agreement in connection with the acquisition of the Verde Companies, the original owners of the Verde Companies is handling this matter. Given the early stages of this matter, we cannot predict the outcome or consequences of this case at this time. The Company believes it is fully indemnified for this litigation matter by the original owners of the Verde Companies, subject to certain limitations.
Coleman v. Verde Energy USA Illinois, LLC
is a purported class action filed on January 23, 2017 in the United States District Court for the Southern District of Illinois alleging that the Verde Companies violated the Telephone Consumer Protection Act by placing marketing calls using an automatic telephone dialing system or a prerecorded voice to the purported class members’ cellular phones without prior express consent. The parties have reached a confidential settlement in this matter that was paid in the fourth quarter of 2017.
Saul Horowitz, as Sellers’ Representative for the former owners of the Major Energy Companies v. National Gas & Electric, LLC (NG&E) and Spark Energy, Inc. (Spark)
, has filed a lawsuit asserting claims of fraudulent inducement against NG&E, breach of contract against NG&E and the Company, and tortious interference with contract against the Company related to the membership interest purchase, subsequent transfer, and associated earnout agreements with the Major Energy Companies' former owners. The relief sought includes unspecified compensatory and punitive damages, prejudgment and post judgment interest, and attorneys’ fees. The lawsuit was
144
filed on October 10, 2017 in the United States District Court for the Southern District of New York, and after the Company and NG&E filed a motion to dismiss, Horowitz filed an Amended Complaint, asserting the same
four
claims. The Company and NG&E filed a motion to dismiss the fraud and tortious interference claims on January 15, 2018. Briefing on the motion to dismiss concluded on March 1, 2018, and the Court's decision to rule or schedule oral argument is pending as of the date these financial statements are issued. The Company and NG&E deny the allegations asserted and intend to vigorously defend this matter. Given the early stages of this matter, we cannot predict the outcome or consequences of this case at this time.
14. Transactions with Affiliates
The Company enters into transactions with and pays 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. The Company also sells and purchases natural gas and electricity with affiliates. The Company presents 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.
Acquisition of Oasis Power Holdings, LLC
The acquisition of Oasis by the Company from RAC was a transfer of equity interests of entities under common control on July 31, 2015. Refer to Note
3 "Acquisitions"
for further discussion.
Acquisition of Major Energy Companies and Perigee
The acquisition of Major Energy Companies and Perigee by the Company from NG&E was a transfer of equity interests of entities under common control on August 23, 2016 and April 1, 2017, respectively. Refer to Note
3 "Acquisitions"
for further discussion.
Master Service Agreement with Retailco Services, LLC
We entered into a Master Service Agreement (the “Master Service Agreement”) effective January 1, 2016 with Retailco Services, LLC ("Retailco Services"), which is wholly owned by our Founder. The Master Service Agreement is for a
one
-year term and renews automatically for successive
one
-year terms unless the Master Service Agreement is terminated by either party. Retailco Services provides us with operational support services such as: enrollment and renewal transaction services; customer billing and transaction services; electronic payment processing services; customer services and information technology infrastructure and application support services under the Master Service Agreement. See "Cost Allocations" for further discussion of the fees paid in connection with the Master Service Agreement during the year ended
December 31, 2017
and
2016
, respectively.
Accounts Receivable and Payable
—
Affiliates
The Company recorded current accounts receivable—affiliates of
$3.7 million
and
$2.6 million
as of
December 31, 2017
and
2016
, respectively, and current accounts payable—affiliates of
$4.6 million
and
$3.8 million
as of
December 31, 2017
and
2016
, respectively, for certain direct billings and cost allocations for services the Company provided to affiliates, services our affiliates provided to us, and sales or purchases of natural gas and electricity with affiliates.
Convertible Subordinated Notes to Affiliate
In connection with the financing of the CenStar acquisition, the Company, together with Spark HoldCo, issued the CenStar Note to Retailco Acquisition Co, LLC ("RAC"), which is wholly owned by our Founder, for
$2.1 million
on July 8, 2015. In connection with the financing of the Oasis acquisition, the Company, together with Spark HoldCo, issued the Oasis Note to RAC for
$5.0 million
on July 31, 2015. RAC converted the CenStar Note and the Oasis Note into shares of Class B common stock on January 8, 2017 and January 31, 2017, respectively. Refer to Note
8 "Debt"
for further discussion.
145
Revenues and Cost of Revenues
—
Affiliates
Cost of revenues—affiliates, recorded in net asset optimization revenues in the consolidated statements of operations for the years ended
December 31,
2017
,
2016
and
2015
related to this agreement were
$0.1 million
,
$1.6 million
and
$11.3 million
Revenues—affiliates, recorded in net asset optimization revenues in the consolidated statements of operations for the years ended
December 31,
2017
,
2016
and
2015
related to these sales were
$1.3 million
,
$0.2 million
, and
$1.1 million
, respectively.
Additionally, the Company entered into a natural gas transportation agreement with another affiliate at its pipeline, whereby the Company transports retail natural gas and pays the higher of (i) a minimum monthly payment or (ii) a transportation fee per MMBtu times actual volumes transported. The current transportation agreement renews annually on February 28 at a fixed rate per MMBtu without a minimum monthly payment. While this transportation agreement remains in effect, this entity is no longer an affiliate as our Founder terminated his interest in the affiliate on May 16, 2016. Cost of revenues —affiliates, recorded in retail cost of revenues in the consolidated statements of operations related to this activity, was
zero
for the year ended
December 31,
2017
and less than
$0.1 million
for the years ended
December 31,
2016
and
2015
, respectively.
Cost Allocations
The Company paid certain expenses on behalf of affiliates, which are reimbursed by the affiliates to the Company, and our affiliates paid certain expenses on our behalf, which are reimbursed by us. These transactions include costs that can be specifically identified and certain allocated overhead costs associated with general and administrative services, including executive management, due diligence work, recurring management consulting, facilities, banking arrangements, professional fees, insurance, information services, human resources and other support departments to the affiliates. Where costs incurred on behalf of the affiliate or us could not be determined by specific identification for direct billing, the costs were primarily allocated to the affiliated entities or us based on percentage of departmental usage, wages or headcount. The total net amount direct billed and allocated from affiliates w
as
$25.4 million
,
$17.0 million
and
$2.1 million
for the years ended
December 31, 2017
,
2016
and
2015
, respectively.
Of the
$25.4 million
and
$17.0 million
total net amount directly billed and allocated from affiliates, the Company recorded general and administrative expense of
$22.0 million
and
$14.7 million
for the years ended
December 31, 2017
and
2016
, in the consolidated statement of operations in connection with fees paid, net of damages charged, under the Master Service Agreement with Retailco Services. Additionally under the Master Service Agreement, we capitalized
$0.7 million
and
1.3 million
of property and equipment for the application, development and implementation of various systems during the years ended
December 31, 2017
and
2016
.
The total net amount direct billed and allocated to affiliates was
$2.1 million
for the year ended
December 31,
2015
, which was recorded as a reduction in general and administrative expense in the consolidated statement of operations.
Distributions to and Contributions from Affiliates
During the years ended
December 31, 2017
,
2016
and
2015
, the Company made net capital distributions to NuDevco Retail and Retailco of
$15.6 million
,
$23.7 million
and
$15.6 million
, respectively, in conjunction with the payment of quarterly distributions attributable to its Spark HoldCo units. During the year ended
December 31, 2017
and
2016
, respectively, the Company made distributions to NuDevco Retail and Retailco for gross-up distributions of
$18.2 million
and
$11.3 million
in connection with distributions made between Spark HoldCo and Spark Energy, Inc. for payment of income taxes incurred by Spark Energy, Inc.
Additionally, during the year ended
December 31,
2015
the Company received a capital contribution from NuDevco of
$0.1 million
as NuDevco forgave an account payable due to NuDevco that arose from the payment of
146
withholding taxes related to the vesting of restricted stock units of certain employees of NuDevco who perform services for the Company.
Proceeds from Disgorgement of Stockholder Short-swing Profits
During the year ended
December 31, 2017
and 2016, respectively, the Company recorded
$0.7 million
and
$1.6 million
from Retailco 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, 2017
and
2016
. Of the
$0.7 million
recorded in 2017, the Company received
$0.5 million
cash during the year ended
December 31, 2017
and received
$0.2 million
cash in February 2018. In addition, the Company received
$0.7 million
cash during the year ended
December 31, 2017
related to the disgorgement of stockholder short-swing profit recorded in our consolidated balance sheet as of December 31, 2016.
Class B Common Stock
In connection with the Major Energy Companies acquisition, the Company issued RetailCo
4,000,000
shares of Class B common stock (and a corresponding number of Spark HoldCo units) to NG&E. In connection with the financing of the Provider Companies acquisition, the Company sold
1,399,484
shares of Class B common stock (and a corresponding number of Spark HoldCo units) to RetailCo, valued at
$14.0 million
based on a value of
$10
per share. See Note
3 "Acquisitions"
for further discussion.
Subordinated Debt Facility
On December 27, 2016, the Company and Spark HoldCo jointly issued to Retailco, an entity owned by our Founder, a
5%
subordinated note in the principal amount of up to
$25.0 million
. The subordinated note allows the Company and Spark HoldCo to draw advances in increments of no less than
$1.0 million
per advance up to the maximum principal amount of the subordinated note. The subordinated note matures approximately three and a half years following the date of issuance, and advances thereunder accrue interest at
5%
per annum from the date of the advance. The Company has the right to capitalize interest payments under the subordinated note. The subordinated note is subordinated in certain respects to the Company's Senior Credit Facility pursuant to a subordination agreement. The Company may pay interest and prepay principal on the subordinated note so long as it is in compliance with its covenants under the Senior Credit Facility, is not in default under the Senior Credit Facility and has minimum availability of
$5.0 million
under its borrowing base under the Senior Credit Facility. Payment of principal and interest under the subordinated note is accelerated upon the occurrence of certain change of control or sale transactions. As of
December 31, 2017
and
2016
, there were
zero
and
$5.0 million
, respectively,
in outstanding borrowings under the subordinated note.
Tax Receivable Agreement
Concurrently with the closing of the IPO, the Company entered into a Tax Receivable Agreement with Spark HoldCo, NuDevco Retail Holdings and NuDevco Retail. This agreement generally provides for the payment by the Company to Retailco, LLC (as the successor to NuDevco Retail Holdings) and NuDevco Retail of
85%
of the net cash savings, if any, in U.S. federal, state and local income tax or franchise tax that the Company actually realizes (or is deemed to realize in certain circumstances) in future periods as a result of (i) any tax basis increases resulting from the purchase by the Company of Spark HoldCo units from NuDevco Retail Holdings, (ii) any tax basis increases resulting from the exchange of Spark HoldCo units for shares of Class A common stock pursuant to the Exchange Right (or resulting from an exchange of Spark HoldCo units for cash pursuant to the Cash Option) and (iii) any imputed interest deemed to be paid by the Company as a result of, and additional tax basis arising from, any payments the Company makes under the Tax Receivable Agreement. The Company retains the benefit of the remaining
15%
of these tax savings. See Note
12 "Income Taxes"
for further discussion.
In certain circumstances, the Company may defer or partially defer any payment due (a “TRA Payment”) to the holders of rights under the Tax Receivable Agreement, which are currently Retailco and NuDevco Retail. During the
five
-year period ending September 30, 2019, the Company will defer all or a portion of any TRA Payment owed
147
pursuant to the Tax Receivable Agreement to the extent that Spark HoldCo does not generate sufficient Cash Available for Distribution (as defined below) during the four-quarter period ending September 30th of the applicable year in which the TRA Payment is to be made in an amount that equals or exceeds
130%
(the “TRA Coverage Ratio”) of the Total Distributions (as defined below) paid in such four-quarter period by Spark HoldCo. For purposes of computing the TRA Coverage Ratio:
|
•
|
“Cash Available for Distribution” is generally defined as the Adjusted EBITDA of Spark HoldCo for the applicable period, less (i) cash interest paid by Spark HoldCo, (ii) capital expenditures of Spark HoldCo (exclusive of customer acquisition costs) and (iii) any taxes payable by Spark HoldCo; and
|
|
•
|
“Total Distributions” are defined as the aggregate distributions necessary to cause the Company to receive distributions of cash equal to (i) the targeted quarterly distribution the Company intends to pay to holders of its Class A common and Series A Preferred Stock payable during the applicable four-quarter period, plus (ii) the estimated taxes payable by the Company during such four-quarter period, plus (iii) the expected TRA Payment payable during the calendar year for which the TRA Coverage Ratio is being tested.
|
In the event that the TRA Coverage Ratio is not satisfied in any calendar year, the Company will defer all or a portion of the TRA Payment to NuDevco Retail or Retailco under the Tax Receivable Agreement to the extent necessary to permit Spark HoldCo to satisfy the TRA Coverage Ratio (and Spark HoldCo is not required to make and will not make the pro rata distributions to its members with respect to the deferred portion of the TRA Payment). If the TRA Coverage Ratio is satisfied in any calendar year, the Company will pay NuDevco Retail or Retailco the full amount of the TRA Payment.
Following the
five
-year deferral period ending September 30, 2019, the Company will be obligated to pay any outstanding deferred TRA Payments to the extent such deferred TRA Payments do not exceed (i) the lesser of the Company’s proportionate share of aggregate Cash Available for Distribution of Spark HoldCo during the
five
-year deferral period or the cash distributions actually received by the Company during the
five
-year deferral period, reduced by (ii) the sum of (a) the aggregate target quarterly dividends (which, for the purposes of the Tax Receivable Agreement, will be
$0.18125
per Class A common stock share and
$0.546875
per Series A Preferred Stock share per quarter) during the
five
-year deferral period, (b) the Company’s estimated taxes during the
five
-year deferral period, and (c) all prior TRA Payments and (d) if with respect to the quarterly period during which the deferred TRA Payment is otherwise paid or payable, Spark HoldCo has or reasonably determines it will have amounts necessary to cause the Company to receive distributions of cash equal to the target quarterly distribution payable during that quarterly period. Any portion of the deferred TRA Payments not payable due to these limitations will no longer be payable.
We did not meet the threshold coverage ratio required to fund the first payment to Retailco under the Tax Receivable Agreement during the four-quarter period ended September 30, 2015. As such, the initial payment under the Tax Receivable Agreement due in late 2015 was deferred pursuant to the terms thereof.
We met the threshold coverage ratio required to fund the second TRA Payment to Retailco and NuDevco Retail under the Tax Receivable Agreement during the four-quarter period ending September 30, 2016, resulting in an initial TRA Payment of
$1.4 million
becoming due in December 2016. On November 6, 2016, Retailco and NuDevco Retail granted the Company the right to defer the TRA Payment until May 2018. During the period of time when the Company has elected to defer the TRA Payment, the outstanding payment amount will accrue interest at a rate calculated in the manner provided for under the Tax Receivable Agreement. The liability has been classified as current in our consolidated balance sheet at
December 31, 2017
.
We met the threshold coverage ratio required to fund the third TRA Payment to Retailco and NuDevco Retail under the Tax Receivable Agreement during the four-quarter period ending September 30, 2017. As such, the third payment under the Tax Receivable Agreement due in April 2018 has been classified as current in our consolidated balance sheet at December 31, 2017.
148
We expect to meet the threshold coverage ratio required to fund the fourth payment to Retailco and NuDevco Retail under the Tax Receivable Agreement during the four-quarter period ending September 30, 2018. As such, the fourth payment under the Tax Receivable Agreement due in late 2018 has been classified as current in our consolidated balance sheet at December 31, 2017.
15. Segment Reporting
The Company’s determination of reportable business segments considers the strategic operating units under which the Company makes financial decisions, allocates resources and assesses performance of its retail and asset optimization businesses.
The Company’s reportable business segments are retail natural gas and retail electricity. The retail natural gas segment consists of natural gas sales to, and natural gas transportation and distribution for, residential and commercial customers. Asset optimization activities, considered an integral part of securing the lowest price natural gas to serve retail gas load, are part of the retail natural gas segment. The Company recorded asset optimization revenues of
$178.3 million
,
$133.0 million
and
$154.1 million
and asset optimization cost of revenues of
$179.0 million
,
$133.6 million
and
$152.6 million
for the
years ended
December 31, 2017
,
2016
and
2015
, respectively, which are presented on a net basis in asset optimization revenues. The retail electricity segment consists of electricity sales and transmission to residential and commercial customers. Corporate and other consists of expenses and assets of the retail natural gas and retail electricity segments that are managed at a consolidated level such as general and administrative expenses.
The acquisitions of CenStar and Oasis in 2015, acquisitions of Major Energy Companies and Provider Energy Companies in 2016, and acquisitions of the Perigee Companies and Verde Companies in 2017 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.
To assess the performance of the Company’s operating segments, the Chief Operating Decision Maker analyzes retail gross margin. The Company defines retail gross margin 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. The Company deducts 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 non-trading derivative instruments.
Retail gross margin is a primary performance measure used by our management to determine the performance of our retail natural gas and electricity business by removing the impacts of our asset optimization activities and net non-cash income (loss) impact of our economic hedging activities. As an indicator of our retail energy business’ operating performance, retail gross margin should not be considered an alternative to, or more meaningful than, operating income, as determined in accordance with GAAP.
Below is a reconciliation of retail gross margin to income before income tax expense (in thousands):
149
|
|
Years Ended December 31,
|
|||||||||||
|
(in thousands)
|
2017
|
2016
|
2015
|
|||||||||
|
Reconciliation of Retail Gross Margin to Income before taxes
|
|
|
|
|||||||||
|
Income before income tax expense
|
$
|
113,809
|
|
$
|
76,099
|
|
$
|
27,949
|
|
|||
|
Change in Tax Receivable Agreement Liability
|
(22,267
|
)
|
—
|
|
—
|
|
||||||
|
Interest and other income
|
(256
|
)
|
(957
|
)
|
(324
|
)
|
||||||
|
Interest expense
|
11,134
|
|
8,859
|
|
2,280
|
|
||||||
|
Operating Income
|
102,420
|
|
84,001
|
|
29,905
|
|
||||||
|
Depreciation and amortization
|
42,341
|
|
32,788
|
|
25,378
|
|
||||||
|
General and administrative
|
101,127
|
|
84,964
|
|
61,682
|
|
||||||
|
Less:
|
|
|
|
|
||||||||
|
Net asset optimization (expenses) revenue
|
(717
|
)
|
(586
|
)
|
1,494
|
|
||||||
|
Net, Gain (losses) on non-trading derivative instruments
|
5,588
|
|
22,254
|
|
(18,423
|
)
|
||||||
|
Net, Cash settlements on non-trading derivative instruments
|
16,508
|
|
(2,284
|
)
|
20,279
|
|
||||||
|
Retail Gross Margin
|
$
|
224,509
|
|
$
|
182,369
|
|
$
|
113,615
|
|
|||
The Company uses retail gross margin and net asset optimization revenues as the measure of profit or loss for its business segments. This measure represents the lowest level of information that is provided to the chief operating decision maker for our reportable segments.
Financial data for business segments are as follows (in thousands):
|
Year Ended December 31, 2017
|
Retail
Electricity |
Retail
Natural Gas |
Corporate
and Other |
Eliminations
|
Spark Retail
|
||||||||||||||
|
Total Revenues
|
$
|
657,561
|
|
$
|
140,494
|
|
$
|
—
|
|
$
|
—
|
|
$
|
798,055
|
|
||||
|
Retail cost of revenues
|
477,012
|
|
75,155
|
|
—
|
|
—
|
|
552,167
|
|
|||||||||
|
Less:
|
|
|
|
|
|
||||||||||||||
|
Net asset optimization (expense)
|
(5
|
)
|
(712
|
)
|
—
|
|
—
|
|
(717
|
)
|
|||||||||
|
Net, Gains (losses) on non-trading derivative instruments
|
5,784
|
|
(196
|
)
|
—
|
|
—
|
|
5,588
|
|
|||||||||
|
Current period settlements on non-trading derivatives
|
16,302
|
|
206
|
|
—
|
|
—
|
|
16,508
|
|
|||||||||
|
Retail gross margin
|
$
|
158,468
|
|
$
|
66,041
|
|
$
|
—
|
|
$
|
—
|
|
$
|
224,509
|
|
||||
|
Total Assets
|
$
|
1,228,552
|
|
$
|
421,896
|
|
$
|
209,428
|
|
$
|
(1,353,927
|
)
|
$
|
505,949
|
|
||||
|
Goodwill
|
$
|
117,624
|
|
$
|
2,530
|
|
$
|
—
|
|
$
|
—
|
|
$
|
120,154
|
|
||||
|
Year Ended December 31, 2016
|
Retail
Electricity |
|
Retail
Natural Gas |
|
Corporate
and Other |
|
Eliminations
|
|
Spark Retail
|
||||||||||
|
Total Revenues
|
$
|
417,229
|
|
|
$
|
129,468
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
546,697
|
|
|
Retail cost of revenues
|
286,795
|
|
|
58,149
|
|
|
—
|
|
|
—
|
|
|
344,944
|
|
|||||
|
Less:
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Net asset optimization (expense)
|
—
|
|
|
(586
|
)
|
|
—
|
|
|
—
|
|
|
(586
|
)
|
|||||
|
Net, Gains on non-trading derivative instruments
|
17,187
|
|
|
5,067
|
|
|
—
|
|
|
—
|
|
|
22,254
|
|
|||||
|
Current period settlements on non-trading derivatives
|
(4,889
|
)
|
|
2,605
|
|
|
—
|
|
|
—
|
|
|
(2,284
|
)
|
|||||
|
Retail gross margin
|
$
|
118,136
|
|
|
$
|
64,233
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
182,369
|
|
|
Total Assets
|
$
|
576,757
|
|
|
$
|
242,739
|
|
|
$
|
169,404
|
|
|
$
|
(613,670
|
)
|
|
$
|
375,230
|
|
|
Goodwill
|
$
|
76,617
|
|
$
|
2,530
|
|
$
|
—
|
|
$
|
—
|
|
$
|
79,147
|
|
||||
150
|
Year Ended December 31, 2015
|
Retail
Electricity |
|
Retail
Natural Gas |
|
Corporate
and Other |
|
Eliminations
|
|
Spark Retail
|
||||||||||
|
Total Revenues
|
$
|
229,490
|
|
|
$
|
128,663
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
358,153
|
|
|
Retail cost of revenues
|
170,684
|
|
|
70,504
|
|
|
—
|
|
|
—
|
|
|
241,188
|
|
|||||
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|||||||||
|
Net asset optimization revenues
|
—
|
|
|
1,494
|
|
|
—
|
|
|
—
|
|
|
1,494
|
|
|||||
|
Net, (Losses) on non-trading derivative instruments
|
(13,348
|
)
|
|
(5,075
|
)
|
|
—
|
|
|
—
|
|
|
(18,423
|
)
|
|||||
|
Current period settlements on non-trading derivatives
|
11,899
|
|
|
8,380
|
|
|
—
|
|
|
—
|
|
|
20,279
|
|
|||||
|
Retail gross margin
|
$
|
60,255
|
|
|
$
|
53,360
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
113,615
|
|
|
Total Assets
|
$
|
150,245
|
|
$
|
113,583
|
|
$
|
88,823
|
|
$
|
(190,417
|
)
|
$
|
162,234
|
|
||||
|
Goodwill
|
$
|
16,476
|
|
|
$
|
1,903
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
18,379
|
|
Significant Customers
For each of the years ended
December 31, 2017
,
2016
and
2015
, the Company did not have any significant customers that individually accounted for more than
10%
of the Company’s consolidated retail revenue.
Significant Suppliers
For the years ended
December 31, 2017
,
2016
and
2015
, the Company had
two
,
two
and
one
significant suppliers, respectively, that individually accounted for more than
10%
of the Company’s consolidated retail cost of revenues and net asset optimization.
16. Customer Acquisitions
On April 3, 2017, the Company and Spark HoldCo exercised an option to acquire approximately
44,000
RCEs from the original owner of Perigee. As of
December 31, 2017
, the Company paid
$7.5 million
for customers transferred to date. The purchase price was capitalized as customer relationships and is being amortized over a three year period as customers begin using electricity under a contract with the Company.
During the first quarter of 2015, the Company entered into a purchase and sale agreement for the purchase of approximately
9,500
RCEs in Northern California for a purchase price of
$2.0 million
. The transaction closed in April 2015. The purchase price was capitalized as customer relationships in our consolidated balance sheet and is being amortized over a
three
-year period as customers use natural gas under a contract with the Company.
17. Equity Method Investment
Investment in eREX Spark Marketing Co., Ltd
In September 2015, the Company and Spark HoldCo, together with eREX Co., Ltd., a Japanese company, entered into an agreement ("eREX JV Agreement") to form a new joint venture, eREX Spark Marketing Co., Ltd ("eREX Spark"). As part of this agreement, the Company made contributions of
156.4 million
Japanese Yen, or
$1.4 million
, for a
20%
ownership interest in eREX Spark. The Company is entitled to share in
30%
of the dividends distributed by eREX Spark for the first year a qualifying dividend is paid and for the subsequent
four years
thereafter. After this period, dividends will be distributed proportionately with the equity ownership of eREX Spark. eREX Spark's board of directors consists of
four
directors,
one
of whom is appointed by the Company.
Based on the Company's significant influence, as reflected by the
20%
equity ownership and
25%
control of the eREX Spark board of directors, we recorded the investment in eREX Spark as an equity method investment. Our investment in eREX Spark was
$2.5 million
as of
December 31, 2017
, reflecting contributions made by the
151
Company through
December 31, 2017
and our proportionate share of earnings as determined under the HLBV method as of
December 31, 2017
, and recorded in other assets in the consolidated balance sheet. There were no basis differences between our initial contribution and the underlying net assets of eREX Spark. We recorded our proportionate share of eREX Spark's earnings of
$0.2 million
in our consolidated statement of operations for the year ended
December 31, 2017
.
18. Subsequent Events
Buyout of Verde Earnout Obligations
On
January 12, 2018
, we entered into an Agreement to Terminate Earnout Payments (the “Earnout Termination Agreement”) that terminated our obligation to make any required earnout payments under the agreement for our acquisition of the Verde Companies in exchange for CenStar’s issuance to Verde Energy of a promissory note in the principal amount of
$5.9 million
(the “Verde Earnout Termination Note”). See further discussion in Note
8 "Debt."
In addition, the Earnout Termination Agreement provided for CenStar’s issuance to Verde Energy USA Holdings, LLC of an amended and restated promissory note (the “Amended and Restated Verde Promissory Note”), which amended and restated the Verde Promissory Note. See further discussion in Note
8 "Debt."
Declaration of Dividends
On
January 18, 2018
, the Company declared a dividend of
$0.18125
per share to holders of record of our Class A common stock on
March 2, 2018
and payable on
March 16, 2018
.
On January 18, 2018, 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 16, 2018
to holders of record on
April 2, 2018
of the Series A Preferred Stock. The Company anticipates Series A Preferred Stock dividends declared of
$8.1 million
in the aggregate for the year ended December 31, 2018 based on the Series A Preferred Stock outstanding as of the date these financial statements are issued.
Expansion of Credit Facility
On January 11, 2018 and January 23, 2018, we exercised the accordion feature in the Senior Credit Facility, which when combined with prior exercises, increased the total commitments under the Senior Credit Facility from
$150.0 million
to
$200.0 million
. Please see Note
8 "Debt"
and “—Liquidity and Capital Resources—Senior Credit Facility.”
Series A Preferred Stock Offering
On
January 26, 2018
, we issued
2,000,000
shares of Series A Preferred Stock and received net proceeds from the offering of approximately
$48.9 million
(net of underwriting discounts, commissions and a structuring fee). See Note
5 "Preferred Stock"
for further discussion.
Acquisition of HIKO
On March 1, 2018, we entered into a Membership Interest Purchase Agreement pursuant to which we acquired all of the issued and outstanding membership interests of HIKO Energy, LLC, a New York limited liability company, for a total purchase price of
$6.0 million
in cash, plus working capital. HIKO Energy, LLC ("HIKO") has a total of approximately
29,000
RCEs located in
42
markets in
7
states. Initial accounting for the HIKO business combination is incomplete as of the date these financial statements are issued. Please see "Item 9B—Other Information—Acquisition of HIKO" for a more detailed description.
152
Acquisition of Customers from NG&E
On March 7, 2018, we entered into an asset purchase agreement with NG&E pursuant to which we will acquire approximately
50,000
RCEs from NG&E for a cash purchase price of
$250
for each RCE, or approximately
$12.5 million
in the aggregate. These customers are expected to begin transferring after April 1, 2018 and are located in
24
markets in
8
states. Please see “Item 9B—Other Information—Acquisition of Customers from NG&E” for a more detailed description.
Termination of Master Service Agreement
On March 7, 2018, we, Retailco Services and NuDevco Retail mutually agreed to terminate the Master Services Agreement, effective April 1, 2018. We believe that Retailco Services was able to recognize cost savings and stabilize operating costs related to the operational support services in 2016 and 2017. Under the terms of the termination agreement, the operational support services will be transferred back to the Company, which may allow us to extract further savings by eliminating overhead attributable to managing and accounting for Retailco Services as a stand-alone business. Please see “Item 9B—Other Information—Termination of Master Service Agreement” for a more detailed description.
Supplemental Quarterly Financial Data (unaudited)
Summarized unaudited quarterly financial data is as follows:
|
|
Quarter Ended
|
||||||||||||||
|
2017
|
|||||||||||||||
|
|
December 31, 2017
|
|
September 30,
2017 |
|
June 30,
2017 |
|
March 31,
2017 (1) |
||||||||
|
|
(In thousands, except per share data)
|
||||||||||||||
|
Total Revenues
|
$
|
234,776
|
|
|
$
|
215,536
|
|
|
$
|
151,436
|
|
|
$
|
196,307
|
|
|
Operating income
|
59,752
|
|
|
18,088
|
|
|
7,797
|
|
|
16,783
|
|
||||
|
Net income
|
47,536
|
|
|
12,942
|
|
|
4,671
|
|
|
11,132
|
|
||||
|
Net income attributable to Spark Energy, Inc. stockholders
|
13,158
|
|
|
2,347
|
|
|
1,079
|
|
|
2,270
|
|
||||
|
Net income attributable to stockholders of Class A common stock
|
12,226
|
|
|
1,415
|
|
|
88
|
|
|
2,087
|
|
||||
|
Net income attributable to Spark Energy, Inc. per common share - basic
|
$
|
0.92
|
|
|
$
|
0.11
|
|
|
$
|
0.01
|
|
|
$
|
0.16
|
|
|
Net (loss) income attributable to Spark Energy, Inc. per common share - diluted
|
$
|
0.92
|
|
|
$
|
0.11
|
|
|
$
|
0.01
|
|
|
$
|
0.16
|
|
|
(1)
|
Financial information has been recast to include results attributable to the acquisition of Perigee Energy, LLC by an affiliate on February 3, 2017. See Notes
2
and
3
"Basis of Presentation and Summary of Significant Accounting Policies" and "Acquisitions," respectively, for further discussion.
|
|
Quarter Ended
|
|||||||||||||||
|
|
2016
|
||||||||||||||
|
|
December 31, 2016
|
|
September 30,
2016 |
|
June 30,
2016 (1) |
|
March 31,
2016 |
||||||||
|
|
(In thousands, except per share data)
|
||||||||||||||
|
Total Revenues
|
$
|
168,676
|
|
|
$
|
158,094
|
|
|
$
|
109,381
|
|
|
$
|
110,546
|
|
|
Operating income
|
33,098
|
|
|
8,960
|
|
|
24,366
|
|
|
17,577
|
|
||||
|
Net income
|
24,137
|
|
|
6,801
|
|
|
18,994
|
|
|
15,741
|
|
||||
|
Net income attributable to Spark Energy, Inc. stockholders
|
7,747
|
|
|
183
|
|
|
2,341
|
|
|
4,173
|
|
||||
|
Net income attributable to stockholders of Class A common stock
|
7,747
|
|
|
183
|
|
|
2,341
|
|
|
4,173
|
|
||||
|
Net income attributable to Spark Energy, Inc. per common share - basic
|
$
|
0.60
|
|
|
$
|
0.02
|
|
|
$
|
0.05
|
|
|
$
|
0.56
|
|
|
Net (loss) income attributable to Spark Energy, Inc. per common share - diluted
|
$
|
0.52
|
|
|
$
|
(0.02
|
)
|
|
$
|
0.21
|
|
|
$
|
0.34
|
|
|
(1)
|
Financial information has been recast to include results attributable to the acquisition of Major Energy Companies by an affiliate on April 15, 2016. See Notes
2
and
3
"Basis of Presentation and Summary of Significant Accounting Policies" and "Acquisitions," respectively, for further discussion.
|
153
None.
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, 2017
at the reasonable assurance level.
Management's Annual Report on Internal Control Over Financial Reporting
See "Management's Report on Internal Control Over Financial Reporting" under Item 8 of this Annual Report on Form 10-K.
Attestation Report of the Independent Registered Public Accounting Firm
This Annual Report on Form 10-K does not include an attestation report of our independent registered public accounting firm on our internal control over financial reporting because Section 103 of the JOBS Act provides that an emerging growth company is not required to provide an auditor's report on internal control over financial reporting for as long as we qualify as an emerging growth company.
Changes in Internal Control over Financial Reporting
There was no change in our internal control over financial reporting identified in connection with the evaluation required by Rule 13a-15(d) and 15d-15(d) of the Exchange Act that occurred during the three months ended
December 31, 2017
that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting, expect as described below.
Acquisition of Customers from NG&E
On March 7, 2018, Spark HoldCo entered into an asset purchase agreement (the “Customer Purchase Agreement”) with NG&E. Pursuant to the terms of the Customer Purchase Agreement, Spark HoldCo has agreed to purchase, and NG&E has agreed to sell, a portfolio of approximately 50,000 RCEs located in 24 markets in eight states. We expect these customers will begin transferring after April 1, 2018. The purchase price under the Customer Purchase Agreement is a cash payment of $250 for each RCE, or approximately
$12.5 million
in the aggregate and will be funded with cash on hand.
154
Spark HoldCo and NG&E have made customary representations, warranties and covenants in the Customer Purchase Agreement. Consummation of the transactions contemplated by the Customer Purchase Agreement is subject to various conditions, including, among others, (1) that no order or decree prohibits the transaction, and (2) that the parties have not otherwise agreed to mutually terminate the agreement before the transfer of the customers. The Customer Purchase Agreement requires the parties to deliver certain ancillary documents. The Customer Purchase Agreement also contains termination provisions and indemnification provisions.
The terms of the Customer Purchase Agreement were approved by our Board of Directors after approval by a special committee of the Board of Directors. The special committee was composed exclusively of independent members of our Board of Directors. NG&E is owned by W. Keith Maxwell III, our Chairman of the Board, founder and majority shareholder.
The foregoing summary of the Customer Purchase Agreement does not purport to be complete and is qualified in its entirety by reference to the complete terms of the Customer Purchase Agreement, a copy of which is attached as Exhibit 2.7 to this Annual Report and is incorporated in this Item 9B by reference. The Customer Purchase Agreement has been filed as an exhibit to this Annual Report to provide investors and security holders with more complete information regarding its terms. The Customer Purchase Agreement is not intended to provide any other factual information about Spark HoldCo. The representations, warranties and covenants contained in the Customer Purchase Agreement were made only for purposes of the Customer Purchase Agreement and as of specific dates, were solely for the benefit of the parties to the Customer Purchase Agreement, and may be subject to limitations agreed upon by the contracting parties, including being qualified by confidential disclosures exchanged between the parties in connection with the execution of the Customer Purchase Agreement. The representations and warranties may have been made for the purposes of allocating contractual risk between the parties instead of establishing these matters as facts, and may be subject to standards of materiality applicable to the contracting parties that differ from those applicable to investors. Investors are not third-party beneficiaries under the agreements and should not rely on the representations, warranties and covenants or any descriptions thereof as characterizations of the actual state of facts or condition of Spark HoldCo or any of their respective subsidiaries or affiliates. Moreover, information concerning the subject matter of the representations and warranties may change after the date of the agreements, which subsequent information may or may not be fully reflected in the public disclosures of the Company.
Termination of Master Service Agreement
On March 7, 2018, the Company, Retailco Services and NuDevco Retail mutually agreed to terminate the Master Service Agreement, effective April 1, 2018, pursuant to that certain Termination Agreement, by and between Spark HoldcCo, Retailco Services and NuDevco Retail, as guarantor, (the “MSA Termination Agreement”). For a description of the terms and conditions of the Master Service Agreement, please see “Business and Properties-Relationship with our Founder and Majority Shareholder-Master Service Agreement.”
Pursuant to the MSA Termination Agreement, the operational support services such as enrollment and renewal transaction services; customer billing and transaction services; electronic payment processing services; customer services and information technology infrastructure and application support services previously provided to us by Retailco Services under the Master Service Agreement will be transferred back to Spark HoldCo. Additionally, certain of Retailco Services employees who previously provided services to Spark HoldCo under the Master Service Agreement will become employees of Spark HoldCo, and certain contracts, assets, and intellectual property that were assigned under the Master Service Agreement will be assigned back to Spark HoldCo. To assist in the transition of these services and assets back to Spark HoldCo, Retailco Services is obligated to provide transition services to Spark HoldCo for a period of six months. Spark HoldCo is not obligated to pay any consideration for the MSA Termination Agreement or the termination of the Master Service Agreement.
The MSA Termination Agreement and the termination of the Master Service Agreement was approved by our Board of Directors after approval by a special committee of the Board of Directors. The Special Committee was composed exclusively of independent members of our Board of Directors. Retailco Services is owned by W. Keith Maxwell III, our Chairman of the Board, founder and majority shareholder.
155
The foregoing summary of the MSA Termination Agreement does not purport to be complete and is qualified in its entirety by reference to the complete terms of the MSA Termination Agreement, a copy of which is attached as Exhibit 10.43 to this Annual Report and is incorporated in this Item 9B by reference.
156
Information as to Item 10 will be set forth in the Proxy Statement for the 2018 Annual Meeting of Shareholders (the “Annual Meeting”) and is incorporated herein by reference.
Information as to Item 11 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.
Information as to Item 12 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.
Information as to Item 13 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.
Information as to Item 14 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.
(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.
157
None.
|
INDEX TO EXHIBITS
|
||||||
|
|
Incorporated by Reference
|
|||||
|
Exhibit
|
Exhibit Description
|
Form
|
Exhibit Number
|
Filing Date
|
SEC File No.
|
|
|
2.1#
|
10-Q
|
2.1
|
5/5/2016
|
001-36559
|
||
|
2.2#
|
10-Q
|
2.2
|
5/5/2016
|
001-36559
|
||
|
2.3#
|
8-K
|
2.1
|
8/1/2016
|
001-36559
|
||
|
2.4#
|
10-Q
|
2.4
|
5/8/2017
|
001-36559
|
||
|
2.5
|
8-K
|
2.1
|
7/6/2017
|
001-36559
|
||
|
2.6#
|
8-K
|
2.1
|
1/16/2018
|
001-36559
|
||
|
2.7*#
|
||||||
|
3.1
|
8-K
|
3.1
|
8/4/2014
|
001-36559
|
||
|
3.2
|
8-K
|
3.2
|
8/4/2014
|
001-36559
|
||
|
3.3
|
8-A
|
5
|
3/11/2017
|
001-36559
|
||
|
4.1
|
S-1
|
4.1
|
6/30/2014
|
333-196375
|
||
|
4.2
|
10-Q
|
10.8
|
8/13/2015
|
001-36559
|
||
|
4.3
|
10-Q
|
10.9
|
8/13/2015
|
001-36559
|
||
|
4.4
|
8-K
|
10.1
|
7/6/2017
|
001-36559
|
||
158
|
4.5
|
8-K
|
10.2
|
1/16/2018
|
001-36559
|
||
|
4.6
|
8-K
|
10.1
|
1/16/2018
|
001-36559
|
||
|
10.1
|
8-K
|
10.1
|
5/24/2017
|
001-36559
|
||
|
10.2
|
10-Q
|
10.1
|
11/3/2017
|
001-36559
|
||
|
10.3
|
8-K
|
10.1
|
7/9/2015
|
001-36559
|
||
|
10.4
|
10-K
|
10.2
|
3/24/2016
|
001-36559
|
||
|
10.5
|
10-K
|
10.3
|
3/24/2016
|
001-36559
|
||
|
10.6
|
10-Q
|
10.4
|
8/11/2016
|
001-36559
|
||
159
|
10.7
|
|
8-K
|
10.2
|
8/1/2016
|
001-36559
|
|
|
10.8
|
8-K
|
10.1
|
8/4/2014
|
001-36559
|
||
|
10.9
|
8-K
|
10.2
|
8/4/2014
|
001-36559
|
||
|
10.10+
|
10-K
|
10.6
|
3/24/2016
|
001-36559
|
||
|
10.11†
|
S-8
|
4.3
|
7/31/2014
|
333-197738
|
||
|
10.12†
|
10-Q
|
10.3
|
11/10/2016
|
001-36559
|
||
|
10.13†
|
S-1
|
10.4
|
6/30/2014
|
333-196375
|
||
|
10.14†
|
S-1
|
10.5
|
6/30/2014
|
333-196375
|
||
|
10.15
|
8-K
|
10.3
|
8/4/2014
|
001-36559
|
||
|
10.16
|
10-Q
|
10.1
|
5/8/2017
|
001-36559
|
||
|
10.17
|
8-K
|
10.1
|
1/26/2018
|
001-36559
|
||
|
10.18†
|
8-K
|
10.5
|
8/4/2014
|
001-36559
|
||
|
10.19†
|
8-K
|
10.6
|
8/4/2014
|
001-36559
|
||
|
10.20†
|
8-K
|
10.7
|
8/4/2014
|
001-36559
|
||
|
10.21†
|
8-K
|
10.8
|
8/4/2014
|
001-36559
|
||
|
8-K
|
10.9
|
8/4/2014
|
001-36559
|
|||
|
10.22†
|
||||||
|
10.23†
|
8-K
|
10.10
|
8/4/2014
|
001-36559
|
||
160
|
10.24†
|
8-K
|
10.11
|
8/4/2014
|
001-36559
|
||
|
10.25†
|
8-K
|
10.12
|
8/4/2014
|
001-36559
|
||
|
10.26†
|
8-K
|
10.2
|
5/27/2016
|
001-36559
|
||
|
10.27†
|
8-K
|
10.1
|
5/27/2016
|
001-36559
|
||
|
10.28†
|
8-K
|
10.3
|
6/3/2016
|
001-36559
|
||
|
10.29
|
8-K
|
10.4
|
8/4/2014
|
001-36559
|
||
|
10.30
|
8-K
|
4.1
|
8/4/2014
|
001-36559
|
||
|
10.31†
|
8-K
|
10.1
|
4/20/2015
|
001-36559
|
||
|
10.32†
|
8-K
|
10.2
|
4/20/2015
|
001-36559
|
||
|
10.33†
|
8-K
|
10.3
|
4/20/2015
|
001-36559
|
||
|
10.34†
|
8-K
|
10.4
|
4/20/2015
|
001-36559
|
||
|
10.35†
|
8-K
|
10.1
|
8/4/2015
|
001-36559
|
||
|
10.36†
|
8-K
|
10.1
|
6/3/2016
|
001-36559
|
||
|
10.37
|
10-Q
|
10.5
|
5/14/2015
|
001-36559
|
||
|
10.38†
|
10-Q
|
10.5
|
11/12/2015
|
001-36559
|
||
|
10.39†
|
8-K
|
10.2
|
6/3/2016
|
001-36559
|
||
|
10.40
|
10-Q
|
10.1
|
5/5/2016
|
001-36559
|
||
|
10.41
|
8-K
|
10.1
|
8/1/2016
|
001-36559
|
||
|
10.42
|
8-K
|
10.1
|
12/30/2016
|
001-36559
|
||
|
10.43*
|
||||||
|
21.1*
|
||||||
|
23.1*
|
||||||
|
31.1*
|
||||||
161
|
31.2*
|
||||||
|
32**
|
||||||
|
101.INS*
|
XBRL Instance Document.
|
|||||
|
101.SCH*
|
XBRL Schema Document.
|
|||||
|
101.CAL*
|
XBRL Calculation Document.
|
|||||
|
101.LAB*
|
XBRL Labels Linkbase Document.
|
|||||
|
101.PRE*
|
XBRL Presentation Linkbase Document.
|
|||||
|
101.DEF*
|
XBRL Definition Linkbase Document.
|
|||||
* Filed herewith
** Furnished herewith
† Compensatory plan or arrangement
+ Portions of this exhibit have been omitted and filed separately with the SEC pursuant to an order granting confidential treatment.
# The registrant agrees to furnish supplementally a copy of any omitted schedule to the Commission upon request.
162
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
|
March 9, 2018
|
Spark Energy, Inc.
|
||||
|
By:
|
/s/ Robert Lane
|
||||
|
Robert Lane
|
|||||
|
Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)
|
|||||
|
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant in the capacities indicated on March 9, 2018:
|
|||||
|
By:
|
/s/ Nathan Kroeker
|
||||
|
Nathan Kroeker
|
|||||
|
Director, President and Chief Executive Officer
|
|||||
|
/s/ W. Keith Maxwell III
|
|||||
|
W. Keith Maxwell III
|
|||||
|
Chairman of the Board of Directors, Director
|
|||||
|
/s/ Robert Lane
|
|||||
|
Robert Lane
|
|||||
|
Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)
|
|||||
|
/s/ James G. Jones II
|
|||||
|
James G. Jones II
|
|||||
|
Director
|
|||||
|
/s/ Nick Evans Jr.
|
|||||
|
Nick Evans Jr.
|
|||||
|
Director
|
|||||
|
/s/ Kenneth M. Hartwick
|
|||||
|
Kenneth M. Hartwick
|
|||||
|
Director
|
|||||
163
TABLE OF CONTENTS
Part IItem 1A. Risk FactorsItem 1B. Unresolved Staff CommentsItem 3. Legal ProceedingsItem 4. Mine Safety DisclosuresPart IIItem 5. Market For Registrant S Common Equity, Related Stockholder Matters and Issuer Purchases Of Equity SecuritiesItem 6. Selected Financial DataItem 7. Management S Discussion and Analysis Of Financial ConditionItem 7A. Quantitative and Qualitative Disclosures About Market RiskItem 8. Financial Statements and Supplementary DataItem 9. Changes in and Disagreements with Accountants on Accounting and Financial DisclosureItem 9A. Controls and ProceduresItem 9B. Other InformationPart IIIItem 10. Directors, Executive Officers and Corporate GovernanceItem 11. Executive CompensationItem 12. Security Ownership Of Certain Beneficial Owners and Management, and Related Stockholder MattersItem 13. Certain Relationships and Related Transactions, and Director IndependenceItem 14. Principal Accounting Fees and ServicesPart IVItem 15. Exhibits, Financial Statement SchedulesItem 16. Form 10-k Summary