NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. Formation and Organization
Organization
We are an independent retail energy services company that provides residential and commercial customers in competitive markets across the United States with an alternative choice for natural gas and electricity. Spark Energy, Inc. (the “Company”) is a holding company whose sole material asset consists of units in Spark HoldCo, LLC (“Spark HoldCo”). The Company is the sole managing member of Spark HoldCo, is responsible for all operational, management and administrative decisions relating to Spark HoldCo’s business and consolidates the financial results of Spark HoldCo and its subsidiaries. Spark HoldCo is the direct and indirect owner of the subsidiaries through which we operate. We conduct our business through several brands across our service areas, including Electricity Maine, Electricity N.H., Major Energy, Provider Power Massachusetts, Respond Power, Spark Energy, and Verde Energy.
2. Basis of Presentation and Summary of Significant Accounting Policies
Basis of Presentation
The accompanying interim unaudited condensed 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") as it applies to interim financial statements. This information should be read along with our consolidated financial statements and notes contained in our annual report on Form 10-K for the year ended December 31, 2020 (the “2020 Form 10-K”). Our unaudited condensed 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 unaudited condensed consolidated financial statements.
In the opinion of the Company's management, the accompanying condensed consolidated financial statements reflect all adjustments that are necessary to fairly present the financial position, the results of operations, the changes in equity and the cash flows of the Company for the respective periods. Such adjustments are of a normal recurring nature, unless otherwise disclosed.
Use of Estimates and Assumptions
The preparation of our condensed 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 interim financial statements and the reported amounts of revenues and expenses during the period. Actual results could materially differ from those estimates.
Relationship with our Founder and Majority Shareholder
W. Keith Maxwell, III (our "Founder") is the Company's Chief Executive Officer, a director, and the owner of a majority of the voting power of our common stock through his ownership of NuDevco Retail, LLC ("NuDevco Retail") and Retailco, LLC ("Retailco"). Retailco is a wholly owned subsidiary of TxEx Energy Investments, LLC ("TxEx"), which is wholly owned by Mr. Maxwell. NuDevco Retail is a wholly owned subsidiary of NuDevco Retail Holdings LLC ("NuDevco Retail Holdings"), which is a wholly owned subsidiary of Electric HoldCo, LLC, which is also a wholly owned subsidiary of TxEx.
New Accounting Standards Recently Adopted
There have been no changes to our significant accounting policies as disclosed in our 2020 Form 10-K, except as follows:
In December 2019, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2019-12, Income Taxes (Topic 740), Simplifying the Accounting for Income Taxes ("ASU 2019-12"). These amendments simplify the accounting for income taxes by removing certain exceptions to the general principles in Topic 740. For public business entities, the amendments in ASU 2019-12 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020. We adopted ASU 2019-12 effective January 1, 2021 and the adoption did not have a material impact on our consolidated financial statements.
Standards Being Evaluated/Standards Not Yet Adopted
Below are accounting standards that have been issued by the FASB but have not yet been adopted by the Company at March 31, 2021. The Company considers the applicability and impact of all ASUs. ASUs not listed below were assessed and determined to be either not applicable or are expected to have minimal impact on our consolidated financial statements.
In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848), Facilitation of the Effects of Reference Rate Reform on Financial Reporting ("ASU 2020-04"). The amendments in ASU 2020-04 provide optional expedients and exceptions for applying GAAP to contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued because of reference rate reform. In January 2021, the FASB issued ASU 2021-01, Reference Rate Reform ("ASU 2021-01"), which clarifies the scope and application of certain optional expedients and exceptions regarding the original guidance. The amendments in these ASUs were effective upon issuance and can be applied prospectively through December 31, 2022. The Company's Senior Credit Facility is the only agreement that makes reference to a LIBOR rate and the agreement outlines the specific procedures that will be undertaken once an appropriate alternative benchmark is identified.We do not expect adoption of the new standard to have a material impact to our consolidated financial statements.
3. Revenues
Our revenues are derived primarily from the sale of natural gas and electricity to customers, including affiliates. Revenue is measured based upon the quantity of gas or power delivered at prices contained or referenced in the customer's contract, and excludes any sales incentives (e.g. rebates) and amounts collected on behalf of third parties (e.g. sales tax).
Our revenues also include asset optimization activities. Asset optimization activities consist primarily of purchases and sales of gas that meet the definition of trading activities per FASB ASC Topic 815, Derivatives and Hedging. They are therefore excluded from the scope of FASB ASC Topic 606, Revenue from Contracts with Customers.
Revenues for electricity and natural gas sales are recognized under the accrual method when our performance obligation to a customer is satisfied, which is the point in time when the product is delivered and control of the product passes to the customer. Electricity and natural gas products may be sold as fixed-price or variable-price products. The typical length of a contract to provide electricity and/or natural gas is twelve months. Customers are billed and typically pay at least monthly, based on usage. Electricity and natural gas sales that have been delivered but not billed by period end are estimated and recorded as accrued unbilled revenues based on estimates of customer usage since the date of the last meter read provided by the utility. Volume estimates are based on forecasted volumes and estimated residential and commercial customer usage. Unbilled revenues are calculated by multiplying these volume estimates by the applicable rate by customer class (residential or commercial). Estimated amounts are adjusted when actual usage is known and billed.
The following table discloses revenue by primary geographical market, customer type, and customer credit risk profile (in thousands). The table also includes a reconciliation of the disaggregated revenue to revenue by reportable segment (in thousands).
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Reportable Segments
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Three Months Ended March 31, 2021
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Three Months Ended March 31, 2020
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Retail Electricity
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Retail Natural Gas
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Total Reportable Segments
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Retail Electricity
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Retail Natural Gas
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Total Reportable Segments
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Primary markets (a)
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New England
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$
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26,241
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$
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4,377
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$
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30,618
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$
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46,593
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$
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7,054
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$
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53,647
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Mid-Atlantic
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28,550
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13,455
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42,005
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45,842
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15,804
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61,646
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Midwest
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11,059
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10,238
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21,297
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14,989
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13,607
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28,596
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Southwest
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12,905
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6,320
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19,225
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14,344
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8,127
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22,471
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$
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78,755
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$
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34,390
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$
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113,145
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$
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121,768
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$
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44,592
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$
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166,360
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Customer type
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Commercial
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$
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15,216
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$
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11,516
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$
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26,732
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$
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40,015
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$
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15,517
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$
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55,532
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Residential
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73,272
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26,490
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99,762
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93,228
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33,363
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126,591
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Unbilled revenue (b)
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(9,733)
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(3,616)
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(13,349)
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(11,475)
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(4,288)
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(15,763)
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$
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78,755
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$
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34,390
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$
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113,145
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$
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121,768
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$
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44,592
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$
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166,360
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Customer credit risk
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POR
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$
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50,850
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$
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19,600
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$
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70,450
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$
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84,913
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$
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23,037
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$
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107,950
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Non-POR
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27,905
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14,790
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42,695
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36,855
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21,555
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58,410
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$
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78,755
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$
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34,390
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$
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113,145
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$
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121,768
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$
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44,592
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$
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166,360
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(a) The primary markets include the following states:
•New England - Connecticut, Maine, Massachusetts, New Hampshire;
•Mid-Atlantic - Delaware, Maryland (including the District of Colombia), New Jersey, New York and Pennsylvania;
•Midwest - Illinois, Indiana, Michigan and Ohio; and
•Southwest - Arizona, California, Colorado, Florida, Nevada, and Texas.
(b) Unbilled revenue is recorded in total until it is actualized, at which time it is categorized between commercial and residential customers.
We record gross receipts taxes on a gross basis in retail revenues and retail cost of revenues. During the three months ended March 31, 2021 and 2020, our retail revenues included gross receipts taxes of $0.3 million and $0.3 million, respectively, and our retail cost of revenues included gross receipts taxes of $1.2 million and $1.7 million, respectively.
Accounts receivables and Allowance for Credit Losses
The Company conducts business in many utility service markets where the local regulated utility purchases our receivables, and then becomes responsible for billing the customer and collecting payment from the customer (“POR programs”). These POR programs result in substantially all of the Company’s credit risk being linked to the applicable utility, which generally has an investment-grade rating, and not to the end-use customer. The Company monitors the financial condition of each utility and currently believes its receivables are collectible.
In markets that do not offer POR programs or when the Company chooses to directly bill its customers, certain receivables are billed and collected by the Company. The Company bears the credit risk on these accounts and records an appropriate allowance for doubtful accounts to reflect any losses due to non-payment by customers. The Company’s customers are individually insignificant and geographically dispersed in these markets. The Company
writes off customer balances when it believes that amounts are no longer collectible and when it has exhausted all means to collect these receivables.
For trade accounts receivables, the Company accrues an allowance for doubtful accounts by business segment by pooling customer accounts receivables based on similar risk characteristics, such as customer type, geography, aging analysis, payment terms, and related macro-economic factors. Expected credit loss exposure is evaluated for each of our accounts receivables pools. Expected credits losses are established using a model that considers historical collections experience, current information, and reasonable and supportable forecasts. The Company writes off accounts receivable balances against the allowance for doubtful accounts when the accounts receivable is deemed to be uncollectible.
A rollforward of our allowance for credit losses for the three months ended March 31, 2021 are presented in the table below (in thousands):
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Balance at December 31, 2020
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$
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(3,942)
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Current period bad debt provision
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490
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Write-offs
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934
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Recovery of previous write offs
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(180)
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Balance at March 31, 2021
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$
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(2,698)
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4. Equity
Non-controlling Interest
We hold an economic interest and are the sole managing member in Spark HoldCo, with affiliates of our Founder holding the remaining economic interests in Spark HoldCo. As a result, we consolidate the financial position and results of operations of Spark HoldCo, and reflect the economic interests owned by these affiliates as a non-controlling interest. The Company and affiliates owned the following economic interests in Spark HoldCo at March 31, 2021 and December 31, 2020, respectively.
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The Company
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Affiliated Owners
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March 31, 2021
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41.53
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%
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58.47
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%
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December 31, 2020
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41.53
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%
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58.47
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%
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The following table summarizes the portion of net (loss) income and income tax expense (benefit) attributable to non-controlling interest (in thousands):
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Three Months Ended March 31,
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2021
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2020
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Net (loss) income allocated to non-controlling interest
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$
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(18,321)
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$
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6,085
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Income tax expense allocated to non-controlling interest
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1,608
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496
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Net (loss) income attributable to non-controlling interest
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$
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(19,929)
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$
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5,589
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Class A Common Stock and Class B Common Stock
Holders of the Company's Class A common stock and Class B common stock vote together as a single class on all matters presented to our stockholders for their vote or approval, except as otherwise required by applicable law or by our certificate of incorporation.
Dividends on Class A Common Stock
Dividends declared for the Company's Class A common stock are reported as a reduction of retained earnings, or a reduction of additional paid in capital to the extent retained earnings are exhausted. During the three months ended March 31, 2021, we paid $2.7 million in dividends to the holders of the Company's Class A common stock. This dividend represented a quarterly rate of $0.18125 per share on each share of Class A common stock.
Dividends declared for the Company's Class A common stock are reported as a reduction of retained earnings, or additional paid in capital in the case retained earnings is exhausted.
In order to pay our stated dividends to holders of our Class A common stock, our subsidiary, Spark HoldCo is required to make corresponding distributions to holders of its units, including those holders that own our Class B common stock (our non-controlling interest holder). As a result, during the three months ended March 31, 2021, Spark HoldCo made corresponding distributions of $3.8 million to our non-controlling interest holders.
Share Repurchase Program
On August 18, 2020, our Board of Directors authorized a share repurchase program of up to $20.0 million of Class A common stock through August 18, 2021. Purchases may be made with available cash balances, our Senior Credit Facility and operating cash flows.
The shares of Class A common stock may be repurchased from time to time in the open market at prevailing market prices or in privately negotiated transactions based on ongoing assessments of capital needs, the market price of the stock, and other factors, including general market conditions. The repurchase program does not obligate us to acquire any particular amount of Class A common stock, may be modified or suspended at any time, and could be terminated prior to completion.
During the three months ended March 31, 2021, we did not repurchase our Class A common stock. The share repurchase program was suspended in March 2021 pursuant to an agreement with lenders under our Senior Credit Facility.
Earnings Per Share
Basic earnings per share (“EPS”) is computed by dividing net income attributable to stockholders (the numerator) by the weighted-average number of Class A common shares outstanding for the period (the denominator). Class B common shares are not included in the calculation of basic earnings per share because they are not participating securities and have no economic interests. Diluted earnings per share is similarly calculated except that the denominator is increased by potentially dilutive securities.
The following table presents the computation of basic and diluted income (loss) per share for the three months ended March 31, 2021 and 2020 (in thousands, except per share data):
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Three Months Ended March 31,
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2021
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2020
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Net (loss) income attributable to Spark Energy, Inc. stockholders
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$
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(7,631)
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$
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4,479
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Less: Dividends on Series A preferred stock
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1,951
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|
|
1,500
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Net (loss) income attributable to stockholders of Class A common stock
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$
|
(9,582)
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|
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$
|
2,979
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Basic weighted average Class A common shares outstanding
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14,627
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|
|
14,381
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Basic (loss) income per share attributable to stockholders
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$
|
(0.66)
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|
|
$
|
0.21
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|
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Net (loss) income attributable to stockholders of Class A common stock
|
$
|
(9,582)
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$
|
2,979
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Effect of conversion of Class B common stock to shares of Class A common stock
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—
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|
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—
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|
|
|
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Diluted net (loss) income attributable to stockholders of Class A common stock
|
$
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(9,582)
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|
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$
|
2,979
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|
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|
|
|
|
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Basic weighted average Class A common shares outstanding
|
14,627
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|
|
14,381
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|
|
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Effect of dilutive Class B common stock
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—
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|
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—
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|
|
|
|
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|
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Effect of dilutive restricted stock units
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—
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|
403
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Diluted weighted average shares outstanding
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14,627
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|
|
14,784
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|
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|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted (loss) income per share attributable to stockholders
|
$
|
(0.66)
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|
|
$
|
0.20
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|
The computation of diluted earnings per share for the three months ended March 31, 2021 and 2020 excludes 20.8 million shares of Class B common stock because the effect of their conversion was antidilutive. The Company's outstanding shares of Series A Preferred Stock were not included in the calculation of diluted earnings per share because they contain only contingent redemption provisions that have not occurred.
Variable Interest Entity
Spark HoldCo is a variable interest entity due to its lack of rights to participate in significant financial and operating decisions and its inability to dissolve or otherwise remove its management. Spark HoldCo owns all of the outstanding membership interests in each of our operating subsidiaries. We are the sole managing member of Spark HoldCo, manage Spark HoldCo's operating subsidiaries through this managing membership interest, and are considered the primary beneficiary of Spark HoldCo. The assets of Spark HoldCo cannot be used to settle our obligations except through distributions to us, and the liabilities of Spark HoldCo cannot be settled by us except through contributions to Spark HoldCo. The following table includes the carrying amounts and classification of the assets and liabilities of Spark HoldCo that are included in our condensed consolidated balance sheet as of March 31, 2021 and December 31, 2020 (in thousands):
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March 31, 2021
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December 31, 2020
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Assets
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Current assets:
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Cash and cash equivalents
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$
|
81,290
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$
|
71,442
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Accounts receivable
|
55,671
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|
70,350
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|
|
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Other current assets
|
56,390
|
|
55,575
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Total current assets
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193,351
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|
197,367
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|
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Non-current assets:
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Goodwill
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120,343
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|
120,343
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Other assets
|
13,182
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|
15,259
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Total non-current assets
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133,525
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|
135,602
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|
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Total Assets
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$
|
326,876
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|
$
|
332,969
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|
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|
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Liabilities
|
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|
Current liabilities:
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|
|
Accounts payable and accrued liabilities
|
$
|
54,883
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|
$
|
61,436
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|
|
|
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|
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|
|
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Other current liabilities
|
44,228
|
|
43,676
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|
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Total current liabilities
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99,111
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|
105,112
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Long-term liabilities:
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|
|
|
Long-term portion of Senior Credit Facility
|
135,000
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|
100,000
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Subordinated debt — affiliate
|
10,000
|
|
—
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|
|
|
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Other long-term liabilities
|
183
|
|
256
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|
|
Total long-term liabilities
|
145,183
|
|
100,256
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|
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Total Liabilities
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$
|
244,294
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|
$
|
205,368
|
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5. Preferred Stock
Holders of the Series A Preferred Stock have no voting rights, except in specific circumstances of delisting or in the case the dividends are in arrears as specified in the Series A Preferred Stock Certificate of Designations. The Series A Preferred Stock accrue dividends at an annual percentage rate of 8.75%, and the liquidation preference provisions of the Series A Preferred Stock are considered contingent redemption provisions because there are rights granted to the holders of the Series A Preferred Stock that are not solely within our control upon a change in control of the Company. Accordingly, the Series A Preferred Stock is presented between liabilities and the equity sections in the accompanying condensed consolidated balance sheet.
During the three months ended March 31, 2021, we paid $2.0 million in dividends to holders of the Series A Preferred Stock. As of March 31, 2021, we had accrued $2.0 million related to dividends to holders of the Series A Preferred Stock. This dividend was paid on April 15, 2021.
A summary of our preferred equity balance for the three months ended March 31, 2021 is as follows:
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(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2020
|
|
$
|
87,288
|
|
|
Repurchase of Series A Preferred Stock
|
|
—
|
|
|
Accumulated dividends on Series A Preferred Stock
|
|
—
|
|
|
Balance at March 31, 2021
|
|
$
|
87,288
|
|
6. Derivative Instruments
We are exposed to the impact of market fluctuations in the price of electricity and natural gas, basis differences in the price of natural gas, storage charges, renewable energy credits ("RECs"), and capacity charges from independent system operators. We use derivative instruments in an effort to manage our cash flow exposure to these risks. These instruments are not designated as hedges for accounting purposes, and, accordingly, changes in the market value of these derivative instruments are recorded in the cost of revenues. As part of our strategy to optimize pricing in our natural gas related activities, we also manage a portfolio of commodity derivative instruments held for trading purposes. Our commodity trading activities are subject to limits within our Risk Management Policy. For these derivative instruments, changes in the fair value are recognized currently in earnings in net asset optimization revenues.
Derivative assets and liabilities are presented net in our condensed consolidated balance sheets when the derivative instruments are executed with the same counterparty under a master netting arrangement. Our derivative contracts include transactions that are executed both on an exchange and centrally cleared, as well as over-the-counter, bilateral contracts that are transacted directly with third parties. To the extent we have paid or received collateral related to the derivative assets or liabilities, such amounts would be presented net against the related derivative asset or liability’s fair value. As of March 31, 2021 and December 31, 2020, we paid less than $0.1 million and $0.1 million in collateral to net against the related derivative liability's fair value. The specific types of derivative instruments we may execute to manage the commodity price risk include the following:
•Forward contracts, which commit us to purchase or sell energy commodities in the future;
•Futures contracts, which are exchange-traded standardized commitments to purchase or sell a commodity or financial instrument;
•Swap agreements, which require payments to or from counterparties based upon the differential between two prices for a predetermined notional quantity; and
•Option contracts, which convey to the option holder the right but not the obligation to purchase or sell a commodity.
The Company has entered into other energy-related contracts that do not meet the definition of a derivative instrument or for which we made a normal purchase, normal sale election and are therefore not accounted for at fair value including the following:
•Forward electricity and natural gas purchase contracts for retail customer load;
•Renewable energy credits; and
•Natural gas transportation contracts and storage agreements.
Volumes Underlying Derivative Transactions
The following table summarizes the net notional volumes of our open derivative financial instruments accounted for at fair value by commodity. Positive amounts represent net buys while bracketed amounts are net sell transactions (in thousands):
Non-trading
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
|
Notional
|
|
March 31, 2021
|
|
December 31, 2020
|
|
Natural Gas
|
MMBtu
|
|
2,183
|
|
|
2,880
|
|
|
|
|
|
|
|
|
|
Electricity
|
MWh
|
|
1,843
|
|
|
1,845
|
|
Trading
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
|
Notional
|
|
March 31, 2021
|
|
December 31, 2020
|
|
Natural Gas
|
MMBtu
|
|
105
|
|
|
102
|
|
|
|
|
|
|
|
|
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):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
2021
|
|
2020
|
|
Gain (Loss) on non-trading derivatives, net
|
$
|
7,054
|
|
|
$
|
(24,533)
|
|
|
Loss on trading derivatives, net
|
(30)
|
|
|
(54)
|
|
|
Gain (Loss) on derivatives, net
|
7,024
|
|
|
(24,587)
|
|
|
Current period settlements on non-trading derivatives (1)
|
$
|
(1,189)
|
|
|
$
|
16,609
|
|
|
Current period settlements on trading derivatives
|
4
|
|
|
(1)
|
|
|
Total current period settlements on derivatives
|
$
|
(1,185)
|
|
|
$
|
16,608
|
|
(1) Excludes settlements of $(0.3) million, for the three months ended March 31, 2020 related to power call options.
Gains (losses) on trading derivative instruments are recorded in net asset optimization revenues and gains (losses) on non-trading derivative instruments are recorded in retail cost of revenues on the condensed consolidated statements of operations.
Fair Value of Derivative Instruments
The following tables summarize the fair value and offsetting amounts of our derivative instruments by counterparty and collateral received or paid (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2021
|
|
Description
|
Gross Assets
|
|
Gross
Amounts
Offset
|
|
Net Assets
|
|
Cash
Collateral
Offset
|
|
Net Amount
Presented
|
|
Non-trading commodity derivatives
|
$
|
3,759
|
|
|
$
|
(2,094)
|
|
|
$
|
1,665
|
|
|
$
|
—
|
|
|
$
|
1,665
|
|
|
Trading commodity derivatives
|
14
|
|
|
(1)
|
|
|
13
|
|
|
—
|
|
|
13
|
|
|
Total Current Derivative Assets
|
3,773
|
|
|
(2,095)
|
|
|
1,678
|
|
|
—
|
|
|
1,678
|
|
|
Non-trading commodity derivatives
|
233
|
|
|
(172)
|
|
|
61
|
|
|
—
|
|
|
61
|
|
|
Trading commodity derivatives
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total Non-current Derivative Assets
|
233
|
|
|
(172)
|
|
|
61
|
|
|
—
|
|
|
61
|
|
|
Total Derivative Assets
|
$
|
4,006
|
|
|
$
|
(2,267)
|
|
|
$
|
1,739
|
|
|
$
|
—
|
|
|
$
|
1,739
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Description
|
Gross
Liabilities
|
|
Gross
Amounts
Offset
|
|
Net
Liabilities
|
|
Cash
Collateral
Offset
|
|
Net Amount
Presented
|
|
Non-trading commodity derivatives
|
$
|
(6,623)
|
|
|
$
|
3,394
|
|
|
$
|
(3,229)
|
|
|
$
|
13
|
|
|
$
|
(3,216)
|
|
|
Trading commodity derivatives
|
(3)
|
|
|
—
|
|
|
(3)
|
|
|
—
|
|
|
(3)
|
|
|
Total Current Derivative Liabilities
|
(6,626)
|
|
|
3,394
|
|
|
(3,232)
|
|
|
13
|
|
|
(3,219)
|
|
|
Non-trading commodity derivatives
|
(490)
|
|
|
315
|
|
|
(175)
|
|
|
—
|
|
|
(175)
|
|
|
Trading commodity derivatives
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total Non-current Derivative Liabilities
|
(490)
|
|
|
315
|
|
|
(175)
|
|
|
—
|
|
|
(175)
|
|
|
Total Derivative Liabilities
|
$
|
(7,116)
|
|
|
$
|
3,709
|
|
|
$
|
(3,407)
|
|
|
$
|
13
|
|
|
$
|
(3,394)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2020
|
|
Description
|
Gross Assets
|
|
Gross
Amounts
Offset
|
|
Net Assets
|
|
Cash
Collateral
Offset
|
|
Net Amount
Presented
|
|
Non-trading commodity derivatives
|
$
|
308
|
|
|
$
|
(105)
|
|
|
$
|
203
|
|
|
$
|
—
|
|
|
$
|
203
|
|
|
Trading commodity derivatives
|
112
|
|
|
(4)
|
|
|
108
|
|
|
—
|
|
|
108
|
|
|
Total Current Derivative Assets
|
420
|
|
|
(109)
|
|
|
311
|
|
|
—
|
|
|
311
|
|
|
Non-trading commodity derivatives
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Trading commodity derivatives
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total Non-current Derivative Assets
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total Derivative Assets
|
$
|
420
|
|
|
$
|
(109)
|
|
|
$
|
311
|
|
|
$
|
—
|
|
|
$
|
311
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Description
|
Gross
Liabilities
|
|
Gross
Amounts
Offset
|
|
Net
Liabilities
|
|
Cash
Collateral
Offset
|
|
Net Amount
Presented
|
|
Non-trading commodity derivatives
|
$
|
(11,139)
|
|
|
$
|
3,620
|
|
|
$
|
(7,519)
|
|
|
$
|
86
|
|
|
$
|
(7,433)
|
|
|
Trading commodity derivatives
|
(74)
|
|
|
2
|
|
|
(72)
|
|
|
—
|
|
|
(72)
|
|
|
Total Current Derivative Liabilities
|
(11,213)
|
|
|
3,622
|
|
|
(7,591)
|
|
|
86
|
|
|
(7,505)
|
|
|
Non-trading commodity derivatives
|
(838)
|
|
|
611
|
|
|
(227)
|
|
|
—
|
|
|
(227)
|
|
|
Trading commodity derivatives
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total Non-current Derivative Liabilities
|
(838)
|
|
|
611
|
|
|
(227)
|
|
|
—
|
|
|
(227)
|
|
|
Total Derivative Liabilities
|
$
|
(12,051)
|
|
|
$
|
4,233
|
|
|
$
|
(7,818)
|
|
|
$
|
86
|
|
|
$
|
(7,732)
|
|
7. Property and Equipment
Property and equipment consist of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated useful
lives (years)
|
|
March 31, 2021
|
|
December 31, 2020
|
|
|
|
|
|
|
Information technology
|
2 – 5
|
|
$
|
5,307
|
|
|
$
|
5,821
|
|
|
|
|
|
|
|
|
|
Furniture and fixtures
|
2 – 5
|
|
957
|
|
|
957
|
|
|
Total
|
|
|
6,264
|
|
|
6,778
|
|
|
Accumulated depreciation
|
|
|
(2,808)
|
|
|
(3,424)
|
|
|
Property and equipment—net
|
|
|
$
|
3,456
|
|
|
$
|
3,354
|
|
Information technology assets include software and consultant time used in the application, development and implementation of various systems including customer billing and resource management systems. As of each of March 31, 2021 and December 31, 2020, information technology includes $0.8 million and $0.7 million, respectively, of costs associated with assets not yet placed into service.
Depreciation expense recorded in the condensed consolidated statements of operations was $0.4 million and $0.6 million, respectively, for the three months ended March 31, 2021 and 2020.
8. Intangible Assets
Goodwill, customer relationships and trademarks consist of the following amounts (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2021
|
|
December 31, 2020
|
|
Goodwill
|
$
|
120,343
|
|
|
$
|
120,343
|
|
|
Customer relationships—Acquired
|
|
|
|
|
Cost
|
$
|
58,688
|
|
|
$
|
58,688
|
|
|
Accumulated amortization
|
(46,445)
|
|
|
(44,175)
|
|
|
Customer relationships—Acquired
|
$
|
12,243
|
|
|
$
|
14,513
|
|
|
Customer relationships—Other
|
|
|
|
|
Cost
|
$
|
8,898
|
|
|
$
|
8,988
|
|
|
Accumulated amortization
|
(6,415)
|
|
|
(5,733)
|
|
|
Customer relationships—Other, net
|
$
|
2,483
|
|
|
$
|
3,255
|
|
|
Trademarks
|
|
|
|
|
Cost
|
$
|
7,570
|
|
|
$
|
7,570
|
|
|
Accumulated amortization
|
(3,249)
|
|
|
(2,972)
|
|
|
Trademarks, net
|
$
|
4,321
|
|
|
$
|
4,598
|
|
Changes in goodwill, customer relationships (including non-compete agreements) and trademarks consisted of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Goodwill
|
|
Customer Relationships— Acquired
|
|
Customer Relationships— Other
|
|
Trademarks
|
|
Balance at December 31, 2020
|
$
|
120,343
|
|
|
$
|
14,513
|
|
|
$
|
3,255
|
|
|
$
|
4,598
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments
|
—
|
|
|
—
|
|
|
(28)
|
|
|
—
|
|
|
Amortization
|
—
|
|
|
(2,270)
|
|
|
(744)
|
|
|
(277)
|
|
|
Balance at March 31, 2021
|
$
|
120,343
|
|
|
$
|
12,243
|
|
|
$
|
2,483
|
|
|
$
|
4,321
|
|
Estimated future amortization expense for customer relationships and trademarks at March 31, 2021 is as follows (in thousands):
|
|
|
|
|
|
|
|
Year ending December 31,
|
|
|
|
|
|
2021 (remaining nine months)
|
$
|
9,823
|
|
|
2022
|
6,194
|
|
|
2023
|
605
|
|
|
2024
|
404
|
|
|
2025
|
404
|
|
|
> 5 years
|
1,617
|
|
|
Total
|
$
|
19,047
|
|
9. Debt
Debt consists of the following amounts as of March 31, 2021 and December 31, 2020 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2021
|
|
December 31, 2020
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt:
|
|
|
|
|
Senior Credit Facility (1) (2)
|
$
|
135,000
|
|
|
$
|
100,000
|
|
|
Subordinated Debt
|
10,000
|
|
|
—
|
|
|
|
|
|
|
|
Total long-term debt
|
145,000
|
|
|
100,000
|
|
|
Total debt
|
$
|
145,000
|
|
|
$
|
100,000
|
|
(1) As of March 31, 2021 and December 31, 2020, the weighted average interest rate on the Senior Credit Facility was 3.75% and 3.75%, respectively.
(2) As of March 31, 2021 and December 31, 2020, we had $29.7 million and $31.0 million in letters of credit issued, respectively.
Capitalized financing costs associated with our Senior Credit Facility were $1.4 million and $1.6 million as of March 31, 2021 and December 31, 2020, respectively. Of these amounts, $1.0 million and $1.0 million are recorded in other current assets, and $0.4 million and $0.6 million are recorded in other non-current assets in the condensed consolidated balance sheets as of March 31, 2021 and December 31, 2020, respectively.
Interest expense consists of the following components for the periods indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
|
|
|
2021
|
|
2020
|
|
|
|
|
|
|
|
|
|
Senior Credit Facility
|
$
|
468
|
|
|
$
|
911
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Letters of credit fees and commitment fees
|
402
|
|
|
392
|
|
|
|
|
|
|
|
|
|
|
Amortization of deferred financing costs
|
259
|
|
|
250
|
|
|
|
|
|
|
|
|
|
|
Other
|
182
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
Interest Expense
|
$
|
1,311
|
|
|
$
|
1,553
|
|
|
|
|
|
|
|
|
|
Senior Credit Facility
The Company, as guarantor, and Spark HoldCo (the “Borrower” and, together with each subsidiary of Spark HoldCo (“Co-Borrowers”)) maintain a senior secured borrowing base credit facility (as amended from time to time, “Senior Credit Facility”) that allows us to borrow on a revolving basis and has a maximum borrowing capacity of $227.5 million as of March 31, 2021.
Subject to applicable sub-limits 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 (“Working Capital Loans”), and share buyback loans (“Share Buyback Loans”).
The Senior Credit Facility will mature on July 31, 2022, and all amounts outstanding thereunder will be payable on the maturity date. Borrowings under the Senior Credit Facility may be used to pay fees and expenses in connection with the Senior Credit Facility, finance ongoing working capital requirements and general corporate purpose requirements of the Co-Borrowers, to provide partial funding for acquisitions, as allowed under terms of the Senior Credit Facility, and to make open market purchases of our Class A common stock and Series A Preferred Stock. The Senior Credit Facility provides for Share Buyback Loans of up to $80.0 million, which permit the Company to repurchase up to an aggregate of 8,000,000 shares of Class A common stock or $80.0 million of Series A Preferred Stock, however this provision was suspended in March 2021 pursuant to an agreement with lenders under the Senior Credit Facility.
Pursuant to the Senior Credit Facility, 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
3.25% per annum (based on the prevailing utilization) or an alternate base rate plus an applicable margin of up to 2.25% 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%.
Borrowings under the Senior Credit Facility for Share Buyback Loans, are generally determined by reference to the Eurodollar rate plus an applicable margin of 4.50% per annum or the alternate base rate plus an applicable margin of 3.50% per annum.
The Co-Borrowers pay a commitment fee of 0.50% quarterly in arrears on the unused portion of the Senior Credit Facility. In addition, the Co-Borrowers are subject to additional fees including an upfront fee, an annual agency fee, and letter of credit fees based on a percentage of the face amount of letters of credit payable to any syndicate member that issues a letter of credit.
The Senior Credit Facility contains covenants that, among other things, require the maintenance of specified ratios or conditions including:
•Minimum Fixed Charge Coverage Ratio. We must maintain a minimum fixed charge coverage ratio of not less than 1.25 to 1.00. The Minimum 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, letter of credit fees, commitment fees, acquisition earn-out payments (excluding earnout payments funded with proceeds from newly issued preferred or common equity), distributions, scheduled amortization payments, and payments made on or after the closing of the Fourth Amendment to the Senior Credit Facility (other than such payments made from escrow accounts which were funded in connection with a permitted acquisition) related to the settlement of civil and regulatory matters if not included in the calculation of Adjusted EBITDA. Our Minimum Fixed Charge Coverage Ratio as of March 31, 2021 was 1.48 to 1.00.
•Maximum Total Leverage Ratio. We must maintain a ratio of (x) the sum of total indebtedness (excluding eligible subordinated debt and letter of credit obligations), plus (y) gross amounts reserved for civil and regulatory liabilities identified in SEC filings, to Adjusted EBITDA of no more than 2.50 to 1.00. Our Maximum Total Leverage Ratio as of March 31, 2021 was 1.45 to 1.00.
•Maximum Senior Secured Leverage Ratio. We must maintain a Senior Secured Leverage Ratio of no more than 1.85 to 1.00. The Senior Secured Leverage Ratio is defined as the ratio of (a) all indebtedness of the loan parties on a consolidated basis that is secured by a lien on any property of any loan party (including the effective amount of all loans then outstanding under the Senior Credit Facility) to (b) Adjusted EBITDA. Our Maximum Senior Secured Leverage Ratio as of March 31, 2021 was 1.24 to 1.00.
The Senior Credit Facility contains various negative covenants that limit our ability to, among other things, incur certain additional indebtedness, grant certain liens, engage in certain asset dispositions, merge or consolidate, make certain payments, distributions, investments, acquisitions or loans, materially modify certain agreements, or enter into transactions with affiliates. The Senior Credit Facility also contains affirmative covenants that are customary for credit facilities of this type. As of March 31, 2021, we were in compliance with our various covenants under the Senior Credit Facility.
The Senior Credit Facility is secured by pledges of the equity of the portion of Spark HoldCo owned by us, the equity of Spark HoldCo’s subsidiaries, the Co-Borrowers’ present and future subsidiaries, and substantially all of the Co-Borrowers’ and their subsidiaries’ present and future property and assets, including accounts receivable, inventory and liquid investments, and control agreements relating to bank accounts.
We are entitled to pay cash dividends to the holders of the Series A Preferred Stock and Class A common stock and will be entitled to repurchase up to an aggregate amount of 10,000,000 shares of our Class A common stock, and up to $92.7 million of Series A Preferred Stock through one or more normal course open market purchases through NASDAQ so long as: (a) no default exists or would result therefrom; (b) the Co-Borrowers are in pro forma compliance with all financial covenants before and after giving effect thereto; and (c) the outstanding amount of all
loans and letters of credit does not exceed the borrowing base limits. The share repurchase program was suspended in March 2021 pursuant to an agreement with lenders under our Senior Credit Facility.
The Senior Credit Facility contains certain customary representations and warranties and events of default. Events of default include, among other things, payment defaults, breaches of representations and warranties, covenant defaults, cross-defaults and cross-acceleration to certain indebtedness, certain events of bankruptcy, certain events under ERISA, material judgments in excess of $5.0 million, certain events with respect to material contracts, and actual or asserted failure of any guaranty or security document supporting the Senior Credit Facility to be in full force and effect. A default will also occur if at any time W. Keith Maxwell III ceases to, directly or indirectly, own at least 13,600,000 Class A and Class B shares on a combined basis (to be adjusted for any stock split, subdivisions or other stock reclassification or recapitalization), and a controlling percentage of the voting equity interest of the Company, and certain other changes in control. If such an event of default occurs, the lenders under the Senior Credit Facility would be entitled to take various actions, including the acceleration of amounts due under the facility and all actions permitted to be taken by a secured creditor.
Subordinated Debt Facility
The Company maintains an Amended and Restated Subordinated Promissory Note in the principal amount of up to $25.0 million (the “Subordinated Debt Facility”), by and among the Company, Spark HoldCo and Retailco. The Subordinated Debt Facility matures on January 31, 2023.
The Subordinated Debt Facility allows us to draw advances in increments of no less than $1.0 million per advance up to the maximum principal amount of the Subordinated Debt Facility. Advances thereunder accrue interest at 5% per annum from the date of the advance. We have the right to capitalize interest payments under the Subordinated Debt Facility. The Subordinated Debt Facility is subordinated in certain respects to our Senior Credit Facility pursuant to a subordination agreement. We may pay interest and prepay principal on the Subordinated Debt Facility so long as we are in compliance with the covenants under our Senior Credit Facility, are not in default under the Senior Credit Facility and have minimum availability of $5.0 million under the borrowing base under the Senior Credit Facility. Payment of principal and interest under the Subordinated Debt Facility is accelerated upon the occurrence of certain change of control or sale transactions.
As of March 31, 2021, and December 31, 2020, there were $10.0 million and zero outstanding borrowings under the Subordinated Debt Facility.
10. Fair Value Measurements
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. Fair values are based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. This includes the credit standing of counterparties involved and the impact of credit enhancements.
We apply fair value measurements to our commodity derivative instruments based on the following fair value hierarchy, which prioritizes the inputs to the valuation techniques used to measure fair value into three broad levels:
•Level 1—Quoted prices in active markets for identical assets and liabilities. Instruments categorized in Level 1 primarily consist of financial instruments such as exchange-traded derivative instruments.
•Level 2—Inputs other than quoted prices recorded in Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 primarily
include non-exchange traded derivatives such as over-the-counter commodity forwards and swaps and options.
•Level 3—Unobservable inputs for the asset or liability, including situations where there is little, if any, observable market activity for the asset or liability.
As the fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3), the Company maximizes the use of observable inputs and minimizes the use of unobservable inputs when measuring fair value. These levels can change over time. In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. In these cases, the lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
The following tables present assets and liabilities measured and recorded at fair value in our condensed consolidated balance sheets on a recurring basis by and their level within the fair value hierarchy (in thousands):
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|
|
|
|
|
|
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
March 31, 2021
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|
|
|
|
|
|
|
|
Non-trading commodity derivative assets
|
$
|
—
|
|
|
$
|
1,726
|
|
|
$
|
—
|
|
|
$
|
1,726
|
|
|
Trading commodity derivative assets
|
—
|
|
|
13
|
|
|
—
|
|
|
13
|
|
|
Total commodity derivative assets
|
$
|
—
|
|
|
$
|
1,739
|
|
|
$
|
—
|
|
|
$
|
1,739
|
|
|
Non-trading commodity derivative liabilities
|
$
|
(6)
|
|
|
$
|
(3,385)
|
|
|
$
|
—
|
|
|
$
|
(3,391)
|
|
|
Trading commodity derivative liabilities
|
—
|
|
|
(3)
|
|
|
—
|
|
|
(3)
|
|
|
Total commodity derivative liabilities
|
$
|
(6)
|
|
|
$
|
(3,388)
|
|
|
$
|
—
|
|
|
$
|
(3,394)
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|
|
|
|
|
|
|
|
|
|
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|
|
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|
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|
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|
|
|
|
|
|
|
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
December 31, 2020
|
|
|
|
|
|
|
|
|
Non-trading commodity derivative assets
|
$
|
104
|
|
|
$
|
99
|
|
|
$
|
—
|
|
|
$
|
203
|
|
|
Trading commodity derivative assets
|
—
|
|
|
108
|
|
|
—
|
|
|
108
|
|
|
Total commodity derivative assets
|
$
|
104
|
|
|
$
|
207
|
|
|
$
|
—
|
|
|
$
|
311
|
|
|
Non-trading commodity derivative liabilities
|
$
|
(5)
|
|
|
$
|
(7,655)
|
|
|
$
|
—
|
|
|
$
|
(7,660)
|
|
|
Trading commodity derivative liabilities
|
—
|
|
|
(72)
|
|
|
—
|
|
|
(72)
|
|
|
Total commodity derivative liabilities
|
$
|
(5)
|
|
|
$
|
(7,727)
|
|
|
$
|
—
|
|
|
$
|
(7,732)
|
|
|
|
|
|
|
|
|
|
|
We had no transfers of assets or liabilities between any of the above levels during the three months ended March 31, 2021 and the year ended December 31, 2020.
Our derivative contracts include exchange-traded contracts valued utilizing readily available quoted market prices and non-exchange-traded contracts valued using market price quotations available through brokers or over-the-counter and on-line exchanges. In addition, in determining the fair value of our derivative contracts, we apply a credit risk valuation adjustment to reflect credit risk, which is calculated based on our or the counterparty’s historical credit risks. As of March 31, 2021 and December 31, 2020, the credit risk valuation adjustment was a reduction of derivative liabilities, net of $0.2 million and $0.2 million, respectively.
11. Income Taxes
Income Taxes
We and our subsidiaries, CenStar and Verde Energy USA, Inc. ("Verde Corp"), are each subject to U.S. federal income tax as corporations. CenStar and Verde Corp file consolidated tax returns in jurisdictions that allow combined reporting. Spark HoldCo and its subsidiaries, with the exception of CenStar and Verde Corp, are treated as flow-through entities for U.S. federal income tax purposes and, as such, are generally not subject to U.S. federal income tax at the entity level. Rather, the tax liability with respect to their taxable income is passed through to their members or partners. Accordingly, we are subject to U.S. federal income taxation on our allocable share of Spark HoldCo’s net U.S. taxable income.
In our financial statements, we report federal and state income taxes for our share of the partnership income attributable to our ownership in Spark HoldCo and for the income taxes attributable to CenStar and Verde Corp. Net income attributable to non-controlling interest includes the provision for income taxes related to CenStar and Verde Corp.
We account for income taxes using the asset and liability method. Deferred tax assets and liabilities are recognized for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and the tax bases of the assets and liabilities. We apply existing tax law and the tax rate that we expect to apply to taxable income in the years in which those differences are expected to be recovered or settled in calculating the deferred tax assets and liabilities. Effects of changes in tax rates on deferred tax assets and liabilities are recognized in income in the period of the tax rate enactment. A valuation allowance is recorded when it is not more likely than not that some or all of the benefit from the deferred tax asset will be realized.
We periodically assess whether it is more likely than not that we will generate sufficient taxable income to realize our deferred income tax assets. In making this determination, we consider all available positive and negative evidence and make certain assumptions. We consider, among other things, our deferred tax liabilities, the overall business environment, our historical earnings and losses, current industry trends, and our outlook for future years. We believe it is more likely than not that our deferred tax assets will be utilized, and accordingly have not recorded a valuation allowance on these assets.
As of March 31, 2021, we had a net deferred tax asset of $33.0 million, of which approximately $15.6 million related to the original step up in tax basis resulting from the initial purchase of Spark HoldCo units from NuDevco Retail and NuDevco Retail Holdings (predecessor to Retailco) in connection with our initial public offering.
The effective U.S. federal and state income tax rate for the three months ended March 31, 2021 and 2020 was 5.3% and 16.1%, respectively. The effective tax rate for the three and three months ended March 31, 2021 differed from the U.S. federal statutory tax rate of 21% primarily due to state taxes and the benefit provided from Spark HoldCo operating as a limited liability company, which is 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 holders' taxable income.
12. Commitments and Contingencies
From time to time, we may be involved in legal, tax, regulatory and other proceedings in the ordinary course of business. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.
Legal Proceedings
Below is a summary of our currently pending material legal proceedings. We are subject to lawsuits and claims arising in the ordinary course of our business. The following legal proceedings are in various stages and are subject to substantial uncertainties concerning the outcome of material factual and legal issues. Accordingly, unless otherwise specifically noted, we cannot currently predict the manner and timing of the resolutions of these legal proceedings or estimate a range of possible losses or a minimum loss that could result from an adverse verdict in a potential lawsuit. While the lawsuits and claims are asserted for amounts that may be material should an unfavorable outcome occur, management does not currently expect that any currently pending matters will have a material adverse effect on our financial position or results of operations.
Consumer Lawsuits
Similar to other energy service companies (“ESCOs”) operating in the industry, from time-to-time, the Company is subject to class action lawsuits in various jurisdictions where the Company sells natural gas and electricity.
Variable Rate Cases
In the cases referred to as Variable Rate Cases, such actions involve consumers alleging they paid higher rates than they would have if they stayed with their default utility. The underlying claims of each case are similar; however, because numerous cases have been brought in several different jurisdictions, the varying applicable case law, the varying facts and stages of each case, the Company agreed to mediate in two aggregated mediations to avoid duplicative defense costs in numerous jurisdictions. The Company continues to deny the allegations asserted by Plaintiffs and intends to vigorously defend these matters.
In August 2020, the Company participated in mediation which covered three Spark brand matters: (1) Janet Rolland et al v. Spark Energy, LLC (D.N.J Apr. 2017); (2) Burger v. Spark Energy Gas, LLC (N.D. Ill. Dec. 2019); and (3) Local 901 v. Spark Energy, LLC (Sup . Ct. Allen County, Indiana Aug. 2019). The Company is working with the mediator to find a resolution to these cases, but is also simultaneously continuing to defend the cases in the respective courts. Given the ongoing mediation, discovery, and current stage of these matters, we cannot predict the outcome of these cases at this time.
In December of 2020, the Company participated in mediation which covered several Verde brand matters: (1) Marshall. Verde Energy USA, Inc. (D.N.J. Jan. 2018); (2) Mercado v. Verde Energy USA, Inc. (N.D. Ill. Mar. 2018); (3) Davis v. Verde Energy USA, Inc., et al. (D. Mass. Apr. 2019); (4) Panzer v. Verde Energy, USA Inc. and Oasis Power, LLC (E.D. Pa Aug. 2019); (5) LaQua v. Verde Energy USA New York, LLC (E.D.N Y. Jan. 2020); and (6) Abbate v. Verde Energy USA Ohio, LLC (S.D. Ohio Jun. 2020). The parties continue to work on a mediation resolution and the litigation has been stayed in these matters. Given the ongoing mediation and current stage of these matters, we cannot predict the outcome of these cases at this time.
On January 14, 2021, Glikin, et. all v. Major Energy Electric Services, LLC, a purported variable rate class action was filed in the United States District Court, Southern District of New York, attempting to represent a class of all Major Energy customers (including customers of companies Major Energy acts as a successor to) in the United States charged a variable rate for electricity or gas by Major Energy during the applicable statute of limitations period up to and including the date of judgment. The Company believes there is no merit to this case and plans to vigorously defend this matter; however, given the current early stage of this matter, we cannot predict the outcome of this case at this time.
Corporate Matter Lawsuits
Saul Horowitz, as Sellers’ Representative for the former owners of the Major Energy Companies v. National Gas & Electric, LLC (“NG&E”) and Spark Energy, Inc., is a lawsuit filed on October 17, 2017 in the United States District Court for the Southern District of New York asserting claims of fraudulent inducement against NG&E, breach of contract against NG&E and Spark, and tortious interference with contract against Spark related to a membership interest purchase agreement, subsequent dropdown, and associated earnout agreements with the Major Energy Companies' former owners. The relief sought includes unspecified compensatory and punitive damages,
prejudgment and post-judgment interest, and attorneys' fees. This case went to trial during the first two weeks of March 2020 and all material has been submitted to the Judge for his decision. Given the trial was in Manhattan, New York, which was previously under a shelter-in-place order and is currently re-opening, we are not able to predict when we receive a final decision on this matter. Spark and NG&E deny the allegations asserted by Plaintiffs and have vigorously defended this matter; however, we cannot predict the outcome or consequences of this case at this time. In addition, several smaller, related cases involving the same facts are pending in the United States District Court for the Southern District of New York regarding the Major Energy escrowed indemnification monies and three Major Energy executive compensation agreements. As to the indemnification matter, the parties have reached an agreement to release certain original escrowed monies by the Sellers of Major Energy to the Company, which would conclude that current case in favor of the Company.
In addition to the matters disclosed above, the Company may from time to time be subject to legal proceedings that arise in the ordinary course of business. Although there can be no assurance in this regard, the Company does not expect any of those legal proceedings to have a material adverse effect on the Company’s results of operations, cash flows or financial condition.
Regulatory Matters
Many state regulators have increased scrutiny on retail energy providers, across all industry providers. We are subject to regular regulatory inquiries, license renewal reviews, and preliminary investigations in the ordinary course of our business. Below is a summary of our currently pending material state regulatory matters. The following state regulatory matters are in various stages and are subject to substantial uncertainties concerning the outcome of material factual and legal issues. Accordingly, we cannot currently predict the manner and timing of the resolution of these state regulatory matters or estimate a range of possible losses or a minimum loss that could result from an adverse action. Management does not currently expect that any currently pending state regulatory matters will have a material adverse effect on our financial position or results of operations.
Connecticut. In 2019, PURA initiated review of two of the Company's brands in Connecticut, Spark and Verde, focusing on marketing, billing and enrollment practices. The Company has and is cooperating with PURA's requests to review Spark and Verde practices in Connecticut.
Illinois. Spark Energy, LLC received a verbal inquiry from the Illinois Commerce Commission (“ICC”) and the Illinois Attorney General ("IAG") on January 1, 2020 seeking to understand an increase in complaints from Illinois consumers. The Company met with the ICC and the IAG in February 2020 and plan to discuss a compliance plan to ensure its sales are in compliance with Illinois regulations. The parties also discussed possible restitution payments to any customers impacted by sales not in compliance with Illinois regulations.
New York. Prior to the purchase of Major Energy by the Company, in 2015, Major Energy Services, LLC and Major Energy Electric Services were contacted by the Attorney General, Bureau of Consumer Frauds & Protection for State of New York relating to their marketing practices. Major Energy has exchanged information in response to various requests from the Attorney General and recently agreed to respond to additional questions via remote proceedings in October of 2020. The parties are in settlement negotiations at this time. While investigations of this nature may be resolved in a manner that allows the retail energy supplier to continue operating in New York with stipulations, there can be no assurances that the New York Attorney General will not take more severe action. Prior to the purchase of Major Energy by the Company, in 2015, Major Energy Services, LLC and Major Energy Electric Services were contacted by the Attorney General, Bureau of Consumer Frauds & Protection for State of New York relating to their marketing practices. Major Energy has exchanged information in response to various requests from the Attorney General. The Parties are in settlement negotiations at this time. While investigations of this nature may be resolved in a manner that allows the retail energy supplier to continue operating in New York with stipulations, there can be no assurances that the New York Attorney General will not take more severe action.
Pennsylvania. Verde Energy USA, Inc. (“Verde”) is the subject of a formal investigation by the Pennsylvania Public Utility Commission, Bureau of Investigation and Enforcement (“PPUC”) initiated on January 30, 2020. The
investigation asserts that Verde may have violated Pennsylvania retail energy supplier regulations. The Company met with the PPUC in February 2020 to discuss the matter and to work with the PPUC cooperatively. Verde reached a settlement, which includes a civil penalty of $1.0 million and a $0.1 million contribution to the PPL hardship fund. On June 30, 2020, Verde and PPUC Bureau of Investigation and Enforcement filed a Joint Petition for Approval of Settlement and Statements in Support of that Joint Petition with the Commission. Verde is currently awaiting final approval of this settlement.
In addition to the matters disclosed above, in the ordinary course of business, the Company may from time to time be subject to regulators initiating informal reviews or issuing subpoenas for information as means to evaluate the Company and its subsidiaries’ compliance with applicable laws, rule, regulations and practices. Although there can be no assurance in this regard, the Company does not expect any of those regulatory reviews to have a material adverse effect on the Company’s results of operations, cash flows or financial condition.
Indirect Tax Audits
We are undergoing various types of indirect tax audits spanning from years 2014 to 2020 for which additional liabilities may 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 March 31, 2021 and December 31, 2020, we had accrued $22.9 million and $26.6 million, respectively, related to litigation and regulatory matters and $1.1 million and $1.2 million, respectively, related to indirect tax audits. The outcome of each of these may result in additional expense.
13. Transactions with Affiliates
Transactions with Affiliates
We enter into transactions with and pay certain costs on behalf of affiliates that are commonly controlled in order to reduce risk, reduce administrative expense, create economies of scale, create strategic alliances and supply goods and services to these related parties. We also sell and purchase natural gas and electricity with affiliates and pay an affiliate to perform telemarketing activities. We present receivables and payables with the same affiliate on a net basis in the condensed consolidated balance sheets as all affiliate activity is with parties under common control. Affiliated transactions include certain services to the affiliated companies associated with employee benefits provided through our benefit plans, insurance plans, leased office space, administrative salaries, due diligence work, recurring management consulting, and accounting, tax, legal, or technology services. Amounts billed are based on the services provided, departmental usage, or headcount, which are considered reasonable by management. As such, the accompanying condensed consolidated financial statements include costs that have been incurred by us and then directly billed or allocated to affiliates, as well as costs that have been incurred by our affiliates and then directly billed or allocated to us, and are recorded net in general and administrative expense on the condensed consolidated statements of operations with a corresponding accounts receivable—affiliates or accounts payable—affiliates, respectively, recorded in the condensed consolidated balance sheets. Transactions with affiliates for sales or purchases of natural gas and electricity are recorded in retail revenues, retail cost of revenues, and net asset optimization revenues in the condensed consolidated statements of operations with a corresponding accounts receivable—affiliate or accounts payable—affiliate are recorded in the condensed consolidated balance sheets.
Cost Allocations
Where costs incurred on behalf of the affiliate or us cannot be determined by specific identification for direct billing, the costs are allocated to the affiliated entities or us based on estimates of percentage of departmental usage, wages or headcount. The total net amount direct billed and allocated (to)/from affiliates was $(0.8) million and $(0.2) million for the three months ended March 31, 2021 and 2020, respectively.
General and administrative costs of $0.1 million and zero were recorded for the three months ended March 31, 2021, and 2020 related to telemarketing activities performed by an affiliate.
Accounts Receivable and Payable—Affiliates
As of March 31, 2021 and December 31, 2020, we had current accounts receivable—affiliates of $5.3 million and $5.1 million, respectively, and current accounts payable—affiliates of $1.3 million and $0.8 million, respectively.
Revenues and Cost of Revenues—Affiliates
Revenues recorded in net asset optimization revenue in the condensed consolidated statements of operations for the three months ended March 31, 2021 and 2020 related to affiliated sales were $0.3 million and $0.5 million, respectively.
Cost of revenues recorded in net asset optimization revenues in the condensed consolidated statements of operations for the three months ended March 31, 2021 and 2020 related to affiliated purchases were less than $0.1 million and $0.2 million, respectively. These amounts are presented as net on the condensed consolidated statements of operations.
Distributions to and Contributions from Affiliates
During three months ended March 31, 2021 and 2020, Spark HoldCo made distributions to affiliates of our Founder of $3.8 million and $3.8 million, respectively, for the payments of quarterly distribution on their respective Spark HoldCo units. During the three months ended March 31, 2021 and 2020, Spark HoldCo also made distributions to these affiliates for gross-up distributions of $2.7 million and $3.4 million, respectively, in connection with distributions made between Spark HoldCo and Spark Energy, Inc. for payment of income taxes incurred by us.
Subordinated Debt Facility
In June 2019, we and Spark HoldCo entered into a Subordinated Debt Facility with an affiliate owned by our Founder, which allows the Company to borrow up to $25.0 million. The Subordinated Debt Facility allows us to draw advances in increments of no less than $1.0 million per advance up to the maximum principal amount of the Subordinated Debt Facility. Advances thereunder accrue interest at 5% per annum from the date of the advance. As of March 31, 2021 and December 31, 2020, there was $10.0 million and zero in outstanding borrowings under the Subordinated Debt Facility. See Note 9 "Debt" for a further description of terms and conditions of the Subordinated Debt Facility.
14. Segment Reporting
Our determination of reportable business segments considers the strategic operating units under which we make financial decisions, allocate resources and assess performance of our business. Our reportable business segments are retail electricity and retail natural gas. The retail electricity segment consists of electricity sales and transmission to residential and commercial customers. The retail natural gas segment consists of natural gas sales to, and natural gas transportation and distribution for, residential and commercial customers. Corporate and other consists of expenses and assets of the retail electricity and natural gas segments that are managed at a consolidated level such as general and administrative expenses. Asset optimization activities are also included in Corporate and other.
For the three months ended March 31, 2021 and 2020, we recorded asset optimization revenues of $25.7 million and $6.4 million and asset optimization cost of revenues of $25.8 million and $6.1 million, respectively, which are presented on a net basis in asset optimization revenues.
We use retail gross margin to assess the performance of our operating segments. We have historically defined retail gross margin as operating (loss) income plus (i) depreciation and amortization expenses and (ii) general and
administrative expenses, less (i) net asset optimization (expenses) revenues, (ii) net (losses) gains on non-trading derivative instruments, and (iii) net current period cash settlements on non-trading derivative instruments.
Based on the events described below related to Winter Storm Uri, and to ensure Retail Gross Margin reflects repeatable operating performance that is not distorted by non-recurring events or extreme market volatility, we have revised the definition of Retail Gross Margin in this Report to include gains (losses) from non-recurring events (including non-recurring market volatility).
We deduct net (losses) gains on non-trading derivative instruments, excluding current period cash settlements, from the retail gross margin calculation in order to remove the non-cash impact of net gains and losses on these derivative instruments. Retail gross margin should not be considered an alternative to, or more meaningful than, operating income, as determined in accordance with GAAP.
Below is a reconciliation of retail gross margin to income before income tax expense (in thousands):
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Three Months Ended March 31,
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2021
|
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2020
|
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|
Reconciliation of Retail Gross Margin to (loss) income before taxes
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|
|
|
|
|
|
(Loss) income before income tax (benefit) expense
|
$
|
(29,095)
|
|
|
$
|
11,993
|
|
|
|
|
|
|
Interest and other income
|
(86)
|
|
|
(160)
|
|
|
|
|
|
|
Interest expense
|
1,311
|
|
|
1,553
|
|
|
|
|
|
|
Operating (loss) income
|
(27,870)
|
|
|
13,386
|
|
|
|
|
|
|
Depreciation and amortization
|
6,036
|
|
|
8,796
|
|
|
|
|
|
|
General and administrative
|
12,671
|
|
|
25,676
|
|
|
|
|
|
|
Less:
|
|
|
|
|
|
|
|
|
Net asset optimization (expense) revenue
|
(140)
|
|
|
321
|
|
|
|
|
|
|
Net, gain (loss) on non-trading derivative instruments
|
7,054
|
|
|
(24,533)
|
|
|
|
|
|
|
Net, Cash settlements on non-trading derivative instruments
|
(1,189)
|
|
|
16,609
|
|
|
|
|
|
|
Non-recurring event - Winter Storm Uri
|
(64,900)
|
|
|
—
|
|
|
|
|
|
|
Retail Gross Margin
|
$
|
50,012
|
|
|
$
|
55,461
|
|
|
|
|
|
Financial data for business segments are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2021
|
|
|
Retail
Electricity
|
|
Retail
Natural Gas
|
|
Corporate
and Other
|
|
Eliminations
|
|
Consolidated
|
|
Total Revenues
|
$
|
78,755
|
|
|
$
|
34,390
|
|
|
$
|
(140)
|
|
|
$
|
—
|
|
|
$
|
113,005
|
|
|
Retail cost of revenues
|
107,524
|
|
|
14,644
|
|
|
—
|
|
|
—
|
|
|
122,168
|
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
Net asset optimization expense
|
—
|
|
|
—
|
|
|
(140)
|
|
|
—
|
|
|
(140)
|
|
|
Net, gain on non-trading derivative instruments
|
6,705
|
|
|
349
|
|
|
—
|
|
|
—
|
|
|
7,054
|
|
|
Current period settlements on non-trading derivatives
|
(1,188)
|
|
|
(1)
|
|
|
—
|
|
|
—
|
|
|
(1,189)
|
|
|
Non-recurring event - Winter Storm Uri
|
(64,900)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(64,900)
|
|
|
Retail Gross Margin
|
$
|
30,614
|
|
|
$
|
19,398
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
50,012
|
|
|
Total Assets at March 31, 2021
|
$
|
2,961,333
|
|
|
$
|
970,315
|
|
|
$
|
330,327
|
|
|
$
|
(3,897,648)
|
|
|
$
|
364,327
|
|
|
Goodwill at March 31, 2021
|
$
|
117,813
|
|
|
$
|
2,530
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
120,343
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2020
|
|
|
Retail
Electricity
|
|
Retail
Natural Gas
|
|
Corporate
and Other
|
|
Eliminations
|
|
Consolidated
|
|
Total revenues
|
$
|
121,768
|
|
|
$
|
44,592
|
|
|
$
|
321
|
|
|
$
|
—
|
|
|
$
|
166,681
|
|
|
Retail cost of revenues
|
100,383
|
|
|
18,440
|
|
|
—
|
|
|
—
|
|
|
118,823
|
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
Net asset optimization revenue
|
—
|
|
|
—
|
|
|
321
|
|
|
—
|
|
|
321
|
|
|
Net, loss on non-trading derivative instruments
|
(24,386)
|
|
|
(147)
|
|
|
—
|
|
|
—
|
|
|
(24,533)
|
|
|
Current period settlements on non-trading derivatives
|
14,965
|
|
|
1,644
|
|
|
—
|
|
|
—
|
|
|
16,609
|
|
|
Retail Gross Margin
|
$
|
30,806
|
|
|
$
|
24,655
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
55,461
|
|
|
Total Assets at December 31, 2020
|
$
|
2,906,139
|
|
|
$
|
941,569
|
|
|
$
|
318,865
|
|
|
$
|
(3,799,906)
|
|
|
$
|
366,667
|
|
|
Goodwill at December 31, 2020
|
$
|
117,813
|
|
|
$
|
2,530
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
120,343
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15. Subsequent Events
Declaration of Dividends
On April 21, 2021, we declared a quarterly dividend of $0.18125 per share to holders of record of our Class A common stock on June 1, 2021, which will be paid on June 15, 2021.
On April 21, 2021, we also declared a quarterly cash dividend in the amount of $0.546875 per share to holders of record of the Series A Preferred Stock on July 1, 2021. The dividend will be paid on July 15, 2021.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the unaudited condensed consolidated financial statements and the related notes thereto included elsewhere in this Report and the audited consolidated financial statements and notes thereto and management's discussion and analysis of financial condition and results of operations included in our 2020 Form 10-K filed with the Securities and Exchange Commission (“SEC”) on March 4, 2021. Results of operations and cash flows for the three months ended March 31, 2021 are not necessarily indicative of results to be attained for any other period. See "Cautionary Note Regarding Forward-Looking Statements" and "Risk Factors."
Overview
We are an independent retail energy services company founded in 1999 that provides residential and commercial customers in competitive markets across the United States with an alternative choice for natural gas and electricity. We purchase our natural gas and electricity supply from a variety of wholesale providers and bill our customers monthly for the delivery of natural gas and electricity based on their consumption at either a fixed or variable price. Natural gas and electricity are then distributed to our customers by local regulated utility companies through their existing infrastructure. As of March 31, 2021, we operated in 100 utility service territories across 19 states and the District of Columbia.
Our business consists of two operating segments:
•Retail Electricity Segment. In this segment, we purchase electricity supply through physical and financial transactions with market counterparties and ISOs and supply electricity to residential and commercial consumers pursuant to fixed-price and variable-price contracts. For the three months ended March 31, 2021 and 2020, approximately 70% and 73%, respectively, of our retail revenues were derived from the sale of electricity.
•Retail Natural Gas Segment. In this segment, we purchase natural gas supply through physical and financial transactions with market counterparties and supply natural gas to residential and commercial consumers pursuant to fixed-price and variable-price contracts. For the three months ended March 31, 2021 and 2020, approximately 30% and 27%, respectively, of our retail revenues were derived from the sale of natural gas.
Recent Developments
Winter Storm Uri
In February 2021, the U.S. experienced winter storm Uri, an unprecedented storm bringing extreme cold temperatures to the central U.S., including Texas. As a result of increased power demand for customers across the state of Texas and power generation disruptions during the weather event, power and ancillary costs in the Electric Reliability Council of Texas ("ERCOT") service area reached or exceeded maximum allowed clearing prices. As of March 31, 2021, we recorded a net loss of approximately $64.9 million as a direct result of winter storm Uri. Uncertainty exists with respect to the financial impact of the winter storm due in part to outstanding pricing and volume settlement data from ERCOT; the results of formal disputes regarding pricing and volume settlement data received to date, for which we are exploring all legal options; and any corrective action by the State of Texas, ERCOT, the Railroad Commission of Texas, or the Public Utility Commission of Texas.
Senior Credit Facility
On January 19, 2021, we increased the total commitments under our Senior Credit Facility to $227.5 million.
COVID-19
The outbreak of the novel coronavirus ("COVID-19") is a rapidly developing situation around the globe that has adversely impacted economic activity and conditions worldwide. In response to the COVID-19 pandemic, we
deployed a remote working strategy in March 2020 that enables certain of our employees to work from home, provided timely communication to team members, implemented protocols for team members' safety, and initiated strategies for monitoring and responding to local COVID-19 impacts. Our preparedness efforts, coupled with quick and decisive plan implementation, resulted in minimal impacts to our workforce.
As described further below under "Drivers of our Business", during the three months ended March 31, 2021, compared to the three months ended March 31, 2020, we had fewer organic customer acquisitions, which resulted in reduced customer acquisition costs. In addition, for the three months ended March 31, 2021 compared to three months ended March 31, 2020, we experienced lower customer attrition, slight increases in residential demand, and slight decreases in C&I demand. The financial impact of the decrease in C&I demand was offset by higher demand from residential customers, which have higher margins. Overall, we believe we have not experienced a material adverse impact to our business, financial condition or results of operations during the quarter ended March 31, 2021 as a result of the COVID-19 pandemic. We are continuing to monitor developments involving our workforce, customers and suppliers and the impact on our operations, business, financial condition, liquidity and results of operations for future periods.
Residential Customer Equivalents
We measure our number of customers using residential customer equivalents ("RCEs"). The following table shows our RCEs by segment during the three months ended March 31, 2021:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
RCEs:
|
|
|
|
|
|
|
(In thousands)
|
December 31, 2020
|
Additions
|
Attrition
|
March 31, 2021
|
% Increase (Decrease)
|
|
Retail Electricity
|
303
|
14
|
(38)
|
279
|
(8)%
|
|
Retail Natural Gas
|
97
|
1
|
(10)
|
88
|
(9)%
|
|
Total Retail
|
400
|
15
|
(48)
|
367
|
(8)%
|
The following table details our count of RCEs by geographical location as of March 31, 2021:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
RCEs by Geographic Location:
|
|
|
|
|
|
|
|
(In thousands)
|
Electricity
|
% of Total
|
Natural Gas
|
% of Total
|
Total
|
% of Total
|
|
New England
|
85
|
31%
|
15
|
17%
|
100
|
27%
|
|
Mid-Atlantic
|
100
|
36%
|
30
|
35%
|
130
|
35%
|
|
Midwest
|
33
|
11%
|
26
|
29%
|
59
|
16%
|
|
Southwest
|
61
|
22%
|
17
|
19%
|
78
|
22%
|
|
Total
|
279
|
100%
|
88
|
100%
|
367
|
100%
|
The geographical locations noted above include the following states:
•New England - Connecticut, Maine, Massachusetts and New Hampshire;
•Mid-Atlantic - Delaware, Maryland (including the District of Columbia), New Jersey, New York and Pennsylvania;
•Midwest - Illinois, Indiana, Michigan and Ohio; and
•Southwest - Arizona, California, Colorado, Florida, Nevada and Texas.
Across our market areas, we have operated under a number of different retail brands. We currently operate under six retail brands. During 2020 and 2019, we consolidated certain brands and billing systems in an effort to simplify our business operations where practical.
Drivers of Our Business
The success of our business and our profitability are impacted by a number of drivers, the most significant of which are discussed below.
Customer Growth
Customer growth is a key driver of our operations. Our ability to acquire customers organically or by acquisition is important to our success as we experience ongoing customer attrition. Our customer growth strategy includes growing organically through traditional sales channels complemented by customer portfolio and business acquisitions.
Our organic sales strategies are designed to offer competitive pricing, price certainty, and/or green product offerings to residential and commercial customers. We manage growth on a market-by-market basis by developing price curves in each of the markets we serve and comparing the market prices to the price offered by the local regulated utility. We then determine if there is an opportunity in a particular market based on our ability to create a competitive product on economic terms that provides customer value and satisfies our profitability objectives. We develop marketing campaigns using a combination of sales channels. Our marketing team continuously evaluates the effectiveness of each customer acquisition channel and makes adjustments in order to achieve desired targets.
Due to the COVID-19 pandemic, certain public utility commissions, regulatory agencies, and other governmental authorities in most of our markets continue to maintain orders prohibiting energy services companies from door-to-door marketing and in some cases telemarketing during the pandemic, which has restricted some of the manners we have historically used to market for organic sales. In response, we have focused on development of products and channels, partners for web sales, as well as accelerating our telemarketing sales quality programs. In November 2020, we began active door-to-door marketing activities in certain markets where not prohibited by states' COVID-19 restrictions.
During the three months ended March 31, 2021, we added approximately 15,000 RCEs primarily through our various organic sales channels. This amount was significantly lower than historical periods primarily due to limitation of our door-to-door marketing as a result of COVID-19 during the majority of 2020 and a reduction in targeted organic customer acquisitions as we focused our efforts to improve our organic sales channels, including vendor selection and sales quality. Although we expect to acquire less customers organically in future periods than we have historically while marketing restrictions are in place, which may cause our customer book to decrease, we are unable to predict the ultimate effect on our organic sales, financial results, cash flows, and liquidity at this time.
We acquire companies and portfolios of customers through both external and affiliated channels. Our ability to realize returns from acquisitions that are acceptable to us is dependent on our ability to successfully identify, negotiate, finance and integrate acquisitions.
Customer Acquisition Costs
Managing customer acquisition costs is a key component of our profitability. Customer acquisition costs are those costs related to obtaining customers organically and do not include the cost of acquiring customers through acquisitions, which are recorded as customer relationships.
We strive to maintain a disciplined approach to recovery of our customer acquisition costs within a 12-month period. We capitalize and amortize our customer acquisition costs over a two-year period, which is based on our estimate of the expected average length of a customer relationship. We factor in the recovery of customer acquisition costs in determining which markets we enter and the pricing of our products in those markets. Accordingly, our results are significantly influenced by our customer acquisition costs. Changes in customer acquisition costs from period to period reflect our focus on growing organically versus growth through acquisitions. We are currently focused on growing through organic sales channels; however, we continue to evaluate
opportunities to acquire customers through acquisitions and pursue such acquisitions when it makes sense economically or strategically.
As described above, certain public utility commissions, regulatory agencies, and other governmental authorities in all of our markets have issued orders that impact the way we have historically acquired customers, such as door to door marketing. Our reduced marketing resulted in significantly reduced customer acquisition costs during the three months ended March 31, 2021 compared to historical amounts. As long as these orders are in effect and marketing is reduced, we expect to incur reduced customer acquisition costs in future periods. However, we may incur increased costs through other manners of marketing, such as online marketing. We also expect our customer acquisition costs with respect to door to door marketing to return to historic levels once door to door marketing restriction orders are lifted from all markets.
Customer Attrition
Customer attrition occurs primarily as a result of: (i) customer initiated switches; (ii) residential moves; (iii) disconnection resulting from customer payment defaults; and (iv) pro-active non-renewal of contracts. Average monthly customer attrition for the three months ended March 31, 2021 and 2020 was 4.2% and 5.7%, respectively.
The current COVID-19 pandemic has caused regulatory agencies and other governmental authorities to take, and potentially continue to take, emergency or other actions in light of the pandemic that may impact our overall customer attrition, including prohibiting the termination of service for non-payment during the current COVID-19 pandemic. In addition, some state commissions continue discussions on allowing utilities to spread costs over time while allowing for full financial recovery plus cost of cash at a later date. This could create an advantage for incumbent utilities as energy service companies have to absorb or pass along COVID-19 related costs to customers, resulting in further disparity between market pricing and the utility price for customers. Furthermore, like us, due to restrictions on door-to-door activities, other energy service companies are limited in their ability to market, which may reduce customer initiated switches. We believe these orders and circumstances caused our customer attrition to be lower for the first quarter of 2021 compared to the first quarter of 2020. Consistent with our previously communicated strategy to shrink our C&I customer book, our customer attrition for C&I customers was slightly higher than the prior year because of our pro-active non-renewal of some of our large commercial contracts; however, this impact was more than offset by the decline in residential customer attrition during the current year. Although customer attrition was slightly lower during the first quarter of 2021, we are unable to predict the ultimate impact on overall customer attrition over the next six months, at this time.
Customer Credit Risk
Our bad debt expense for the three months ended March 31, 2021 and 2020 was (0.9%) and 3.3%, respectively, for non-purchase of receivable market ("non-POR") revenues. An increased focus on collection efforts, timely billing and credit monitoring for new enrollments in non-POR markets beginning in late 2020 have led to an improvement in the bad debt expense over the past several months, including the three months ended March 31, 2021. We have also been able to collect on debts that were previously written off, which has further reduced our bad debt expense during the three months ended March 31, 2021.
The current COVID-19 pandemic has caused regulatory agencies and other governmental authorities to take, and potentially continue to take, emergency or other actions in light of the pandemic that may impact our customer credit risk, including prohibiting the termination of service for non-payment during the current COVID-19 pandemic, requiring deferred payment plans for certain customers unable to pay their bills, and utilities increasing POR fees they charge us in an effort to recoup their bad debt losses. Although the Company noted no significant impact as a result of the COVID-19 pandemic related to customer credit risk for the three months ended March 31, 2021, because of the time lag between the delivery of electricity and natural gas, the issuance of an invoice, and the customer’s payment due date, there may be a substantial lag in time before we are able to determine specific trends in bad debt expense as a result of COVID-19. We are also monitoring other events that may have an impact on our credit risk, such as the expiration of unemployment benefits in many of our service territories.
Weather Conditions
Weather conditions directly influence the demand for natural gas and electricity and affect the prices of energy commodities. Our hedging strategy is based on forecasted customer energy usage, which can vary substantially as a result of weather patterns deviating from historical norms. We are particularly sensitive to this variability in our residential customer segment where energy usage is highly sensitive to weather conditions that impact heating and cooling demand.
Our risk management policies direct that we hedge substantially all of our forecasted demand, which is typically hedged to long-term normal weather patterns. We also attempt to add additional protection through hedging from time to time to protect us from potential volatility in markets where we have historically experienced higher exposure to extreme weather conditions. Because we attempt to match commodity purchases to anticipated demand, unanticipated changes in weather patterns can have a significant impact on our operating results and cash flows from period to period.
During the first quarter of 2021, the U.S. experienced winter storm Uri, an unprecedented storm bringing extreme cold temperatures to the central U.S., including Texas. As a result of increased power demand for customers across the state of Texas and power generation disruptions during the weather event, power and ancillary costs in the ERCOT service area reached or exceeded maximum allowed clearing prices. Although our hedge position was 120% of our forecasted demand in Texas for the month of February, we were still required to purchase power at unprecedented prices for an extended period of time during the storm.These price caps imposed by ERCOT for the duration of the storm and beyond have never been experienced in any deregulated market in which we serve.The policies imposed on the electricity markets by ERCOT related to pricing resulted in overall negative impact on our electricity unit margin in the first quarter of 2021.
See Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Recent Development for additional discussion about the impacts of winter storm Uri.
Asset Optimization
Our asset optimization opportunities primarily arise during the winter heating season when demand for natural gas is typically at its highest. Given the opportunistic nature of these activities and because we account for these activities using the mark to market method of accounting, we experience variability in our earnings from our asset optimization activities from year to year.
Net asset optimization resulted in a loss of $0.1 million and a gain of $0.3 million for the three months ended March 31, 2021 and 2020, respectively.
Non-GAAP Performance Measures
We use the Non-GAAP performance measures of Adjusted EBITDA and Retail Gross Margin to evaluate and measure our operating results as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
(in thousands)
|
2021
|
|
2020
|
|
|
|
|
|
Adjusted EBITDA (1)
|
$
|
32,667
|
|
|
$
|
30,300
|
|
|
|
|
|
|
Retail Gross Margin (2)
|
$
|
50,012
|
|
|
$
|
55,461
|
|
|
|
|
|
(1) Adjusted EBITDA for the three months ended March 31, 2021 includes a $60.0 million add back related to winter storm Uri. See discussion below.
(2) Retail Gross Margin for the three months ended March 31, 2021 includes a $64.9 million add back related to winter storm Uri. See discussion below.
Adjusted EBITDA. We define “Adjusted EBITDA” as EBITDA less (i) customer acquisition costs incurred in the current period, plus or minus (ii) net (loss) gain on derivative instruments, and (iii) net current period cash settlements on derivative instruments, plus (iv) non-cash compensation expense, and (v) other non-cash and non-recurring operating items. EBITDA is defined as net income (loss) before the provision for income taxes, interest
expense and depreciation and amortization. This conforms to the calculation of Adjusted EBITDA in our Senior Credit Facility.
We deduct all current period customer acquisition costs (representing spending for organic customer acquisitions) in the Adjusted EBITDA calculation because such costs reflect a cash outlay in the period in which they are incurred, even though we capitalize and amortize such costs over two years. We do not deduct the cost of customer acquisitions through acquisitions of businesses or portfolios of customers in calculating Adjusted EBITDA.
We deduct our net gains (losses) on derivative instruments, excluding current period cash settlements, from the Adjusted EBITDA calculation in order to remove the non-cash impact of net gains and losses on these instruments. We also deduct non-cash compensation expense that results from the issuance of restricted stock units under our long-term incentive plan due to the non-cash nature of the expense.
We adjust from time to time other non-cash or unusual and/or infrequent charges due to either their non-cash nature or their infrequency. We have historically included the financial impact of weather variability in the calculation of Adjusted EBITDA. We will continue this historical approach, but during the current quarter we incurred a net pre-tax financial loss of $64.9 million due to winter storm Uri, as described above. This loss was incurred due to uncharacteristic extended sub-freezing temperatures across Texas combined with the impact of the pricing caps ordered by ERCOT. We believe this event is unusual, infrequent, and non-recurring in nature.
Our lenders under the Company's Senior Credit Facility have allowed $60.0 million of the $64.9 million pre-tax storm loss to be added back as a non-recurring item in the calculation of Adjusted EBITDA for the Company's March 31, 2021 Debt Covenant Calculations. As our Senior Credit Facility is considered a material agreement and Adjusted EBITDA is a key component of our material covenants, we consider our covenant compliance to be material to the understanding of the Company's financial condition and/or liquidity.
We believe that the presentation of Adjusted EBITDA provides information useful to investors in assessing our performance and results of operations and that Adjusted EBITDA is also useful for an understanding of our financial condition and/or liquidity due to its use in covenants in our Senior Credit Facility. 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, historical cost basis and specific items not reflective of ongoing operations;
•the ability of our assets to generate earnings sufficient to support our proposed cash dividends;
•our ability to fund capital expenditures (including customer acquisition costs) and incur and service debt; and
•our compliance with financial debt covenants. (Refer to Note 9 "Debt" to Part I, Item 1 of this Report for discussion of the material terms of our Senior Credit Facility, including the covenant requirements for our Minimum Fixed Charge Coverage Ratio, Maximum Total Leverage Ratio, and Maximum Senior Secured Leverage Ratio.)
The GAAP measures most directly comparable to Adjusted EBITDA are net income (loss) and net cash provided by (used in) operating activities. The following table presents a reconciliation of Adjusted EBITDA to these GAAP measures for each of the periods indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
(in thousands)
|
2021
|
|
2020
|
|
|
|
|
|
Reconciliation of Adjusted EBITDA to net (loss) income:
|
|
|
|
|
|
|
|
|
Net (loss) income
|
$
|
(27,560)
|
|
|
$
|
10,068
|
|
|
|
|
|
|
Depreciation and amortization
|
6,036
|
|
|
8,796
|
|
|
|
|
|
|
Interest expense
|
1,311
|
|
|
1,553
|
|
|
|
|
|
|
Income tax (benefit) expense
|
(1,535)
|
|
|
1,925
|
|
|
|
|
|
|
EBITDA
|
(21,748)
|
|
|
22,342
|
|
|
|
|
|
|
Less:
|
|
|
|
|
|
|
|
|
Net, gain (loss) on derivative instruments
|
7,024
|
|
|
(24,587)
|
|
|
|
|
|
|
Net cash settlements on derivative instruments
|
(1,185)
|
|
|
16,608
|
|
|
|
|
|
|
Customer acquisition costs
|
213
|
|
|
1,345
|
|
|
|
|
|
|
Plus:
|
|
|
|
|
|
|
|
|
Non-cash compensation expense
|
467
|
|
|
1,324
|
|
|
|
|
|
|
Non-recurring event - Winter Storm Uri
|
60,000
|
|
|
—
|
|
|
|
|
|
|
Adjusted EBITDA
|
$
|
32,667
|
|
|
$
|
30,300
|
|
|
|
|
|
The following table presents a reconciliation of Adjusted EBITDA to net cash provided by operating activities for each of the periods indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
(in thousands)
|
2021
|
|
2020
|
|
|
|
|
|
Reconciliation of Adjusted EBITDA to net cash (used) provided in operating activities:
|
|
|
|
|
|
|
|
|
Net cash (used) provided in operating activities
|
$
|
(23,632)
|
|
|
$
|
39,389
|
|
|
|
|
|
|
Amortization of deferred financing costs
|
(259)
|
|
|
(250)
|
|
|
|
|
|
|
Bad debt expense
|
247
|
|
|
(2,355)
|
|
|
|
|
|
|
Interest expense
|
1,311
|
|
|
1,553
|
|
|
|
|
|
|
Income tax (benefit) expense
|
(1,535)
|
|
|
1,925
|
|
|
|
|
|
|
Non-recurring event - Winter Storm Uri
|
60,000
|
|
|
—
|
|
|
|
|
|
|
Changes in operating working capital
|
|
|
|
|
|
|
|
|
Accounts receivable, prepaids, current assets
|
(11,703)
|
|
|
(17,975)
|
|
|
|
|
|
|
Inventory
|
(1,365)
|
|
|
(2,690)
|
|
|
|
|
|
|
Accounts payable and accrued liabilities
|
4,798
|
|
|
10,818
|
|
|
|
|
|
|
Other
|
4,805
|
|
|
(115)
|
|
|
|
|
|
|
Adjusted EBITDA
|
$
|
32,667
|
|
|
$
|
30,300
|
|
|
|
|
|
|
Cash Flow Data:
|
|
|
|
|
|
|
|
|
Net cash (used) provided in operating activities
|
$
|
(23,632)
|
|
|
$
|
39,389
|
|
|
|
|
|
|
Cash flows used in investing activities
|
$
|
(520)
|
|
|
$
|
(536)
|
|
|
|
|
|
|
Net cash provided (used) in financing activities
|
$
|
33,959
|
|
|
$
|
(41,050)
|
|
|
|
|
|
Retail Gross Margin. We define retail gross margin as operating income (loss) plus (i) depreciation and amortization expenses and (ii) general and administrative expenses, less (iii) net asset optimization revenues (expenses), (iv) net gains (losses) on non-trading derivative instruments, (v) net current period cash settlements on non-trading derivative instruments and (vi) gains (losses) from non-recurring events (including non-recurring market volatility. Retail gross margin is included as a supplemental disclosure because it is a primary performance measure used by our management to determine the performance of our retail natural gas and electricity segments as
a result of recurring operations. As an indicator of our retail energy business’s operating performance, retail gross margin should not be considered an alternative to, or more meaningful than, operating income (loss), its most directly comparable financial measure calculated and presented in accordance with GAAP.
We believe retail gross margin provides information useful to investors as an indicator of our retail energy business's operating performance.
We have historically included the financial impact of weather variability in the calculation of Retail Gross Margin. We will continue this historical approach, but during the current quarter we added back the $64.9 million net financial loss incurred related to winter storm Uri, as described above, in the calculation of Retail Gross Margin because the extremity of the Texas storm combined with the impact of unprecedented pricing mechanisms ordered by ERCOT is considered unusual, infrequent, and non-recurring in nature.
The GAAP measure most directly comparable to Retail Gross Margin is operating income (loss). The following table presents a reconciliation of Retail Gross Margin to operating income (loss) for each of the periods indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
(in thousands)
|
2021
|
|
2020
|
|
|
|
|
|
Reconciliation of Retail Gross Margin to Operating (loss) income:
|
|
|
|
|
|
|
|
|
Operating (loss) income
|
$
|
(27,870)
|
|
|
$
|
13,386
|
|
|
|
|
|
|
Plus:
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
6,036
|
|
|
8,796
|
|
|
|
|
|
|
General and administrative expense
|
12,671
|
|
|
25,676
|
|
|
|
|
|
|
Less:
|
|
|
|
|
|
|
|
|
Net asset optimization (expense) revenue
|
(140)
|
|
|
321
|
|
|
|
|
|
|
Gain (loss) on non-trading derivative instruments
|
7,054
|
|
|
(24,533)
|
|
|
|
|
|
|
Cash settlements on non-trading derivative instruments
|
(1,189)
|
|
|
16,609
|
|
|
|
|
|
|
Non-recurring event - Winter Storm Uri
|
(64,900)
|
|
|
—
|
|
|
|
|
|
|
Retail Gross Margin
|
$
|
50,012
|
|
|
$
|
55,461
|
|
|
|
|
|
|
Retail Gross Margin - Retail Electricity Segment (1)
|
$
|
30,614
|
|
|
$
|
30,806
|
|
|
|
|
|
|
Retail Gross Margin - Retail Natural Gas Segment
|
$
|
19,398
|
|
|
$
|
24,655
|
|
|
|
|
|
(1) Retail Gross Margin - Retail Electricity Segment for the three months ended March 31, 2021 includes a $64.9 million add back related to winter storm Uri.
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 (used in) operating activities, or operating income (loss). Adjusted EBITDA and Retail Gross Margin are not presentations made in accordance with GAAP and have limitations as analytical tools. You should not consider Adjusted EBITDA or Retail Gross Margin in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA and Retail Gross Margin exclude some, but not all, items that affect net income (loss), net cash provided by operating activities, and operating income (loss), and are defined differently by different companies in our industry, our definition of Adjusted EBITDA and Retail Gross Margin may not be comparable to similarly titled measures of other companies.
Management compensates for the limitations of Adjusted EBITDA and Retail Gross Margin as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these data points into management’s decision-making process.
Consolidated Results of Operations
Three Months Ended March 31, 2021 Compared to Three Months Ended March 31, 2020
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In Thousands)
|
Three Months Ended March 31,
|
|
|
|
|
2021
|
|
2020
|
|
|
|
Revenues:
|
|
|
|
|
|
|
Retail revenues
|
$
|
113,145
|
|
|
$
|
166,360
|
|
|
|
|
Net asset optimization (expense) revenue
|
(140)
|
|
|
321
|
|
|
|
|
Total Revenues
|
113,005
|
|
|
166,681
|
|
|
|
|
Operating Expenses:
|
|
|
|
|
|
|
Retail cost of revenues
|
122,168
|
|
|
118,823
|
|
|
|
|
General and administrative expense
|
12,671
|
|
|
25,676
|
|
|
|
|
Depreciation and amortization
|
6,036
|
|
|
8,796
|
|
|
|
|
Total Operating Expenses
|
140,875
|
|
|
153,295
|
|
|
|
|
Operating income
|
(27,870)
|
|
|
13,386
|
|
|
|
|
Other (expense)/income:
|
|
|
|
|
|
|
Interest expense
|
(1,311)
|
|
|
(1,553)
|
|
|
|
|
Interest and other income
|
86
|
|
|
160
|
|
|
|
|
Total other expense
|
(1,225)
|
|
|
(1,393)
|
|
|
|
|
(Loss) income before income tax (benefit) expense
|
(29,095)
|
|
|
11,993
|
|
|
|
|
Income tax (benefit) expense
|
(1,535)
|
|
|
1,925
|
|
|
|
|
Net (loss) income
|
$
|
(27,560)
|
|
|
$
|
10,068
|
|
|
|
|
Other Performance Metrics:
|
|
|
|
|
|
|
Adjusted EBITDA (1) (2)
|
$
|
32,667
|
|
|
$
|
30,300
|
|
|
|
|
Retail Gross Margin (1) (3)
|
$
|
50,012
|
|
|
$
|
55,461
|
|
|
|
|
Customer Acquisition Costs
|
$
|
213
|
|
|
$
|
1,345
|
|
|
|
|
Average Monthly RCE Attrition
|
4.2
|
%
|
|
5.7
|
%
|
|
|
|
|
|
|
|
|
|
(1) Adjusted EBITDA and Retail Gross Margin are non-GAAP financial measures. See " — Non-GAAP Performance Measures" for a reconciliation of Adjusted EBITDA and Retail Gross Margin to their most directly comparable GAAP financial measures.
(2) Adjusted EBITDA for the three months ended March 31, 2021 includes a $60.0 million add back related to winter storm Uri.
(3) Retail Gross Margin for the three months ended March 31, 2021 includes a $64.9 million add back related to winter storm Uri.
Total Revenues. Total revenues for the three months ended March 31, 2021 were approximately $113.0 million, a decrease of approximately $53.7 million, or 32%, from approximately $166.7 million for the three months ended March 31, 2020, as indicated in the table below (in millions). This decrease was primarily due to a decrease in electricity and natural gas volumes as a result of smaller customer book in the first quarter of 2021 as compared to the first quarter of 2020, partially offset by an increase in natural gas and electricity unit revenue.
|
|
|
|
|
|
|
|
Change in electricity volumes sold
|
$
|
(52.4)
|
|
|
Change in natural gas volumes sold
|
(12.3)
|
|
|
Change in electricity unit revenue per MWh
|
8.4
|
|
|
Change in electricity unit revenue per MMBtu - Winter Storm Uri
|
0.9
|
|
|
Change in natural gas unit revenue per MMBtu
|
2.1
|
|
|
Change in net asset optimization revenue
|
(0.4)
|
|
|
Change in total revenues
|
$
|
(53.7)
|
|
Retail Cost of Revenues. Total retail cost of revenues for the three months ended March 31, 2021 was approximately $122.2 million, an increase of approximately $3.4 million, or 3%, from approximately $118.8 million for the three
months ended March 31, 2020, as indicated in the table below (in millions). This increase was primarily due to an increase in electricity supply costs due to winter storm Uri offset by a decrease in electricity and natural gas volumes as a result of a smaller customer book in 2021 and a change in the fair value of our retail derivative portfolio.
|
|
|
|
|
|
|
|
Change in electricity volumes sold
|
$
|
(39.1)
|
|
|
Change in natural gas volumes sold
|
(5.5)
|
|
|
Change in electricity unit cost per MWh
|
(4.6)
|
|
|
Change in electricity unit cost per MWh - Winter Storm Uri
|
65.8
|
|
|
Change in natural gas unit cost per MMBtu
|
0.5
|
|
|
Change in value of retail derivative portfolio
|
(13.7)
|
|
|
Change in retail cost of revenues
|
$
|
3.4
|
|
General and Administrative Expense. General and administrative expense for the three months ended March 31, 2021 was approximately $12.7 million, a decrease of approximately $13.0 million, or 51%, as compared to $25.7 million for the three months ended March 31, 2020. This decrease was primarily attributable to a decrease in sales and marketing costs in 2021 due to limitation of our door-to-door marketing as a result of COVID-19, lower bad debt expense in 2021 due to improved collection efforts and lower legal fees in the first quarter of 2021.
Depreciation and Amortization Expense. Depreciation and amortization expense for the three months ended March 31, 2021 was approximately $6.0 million, a decrease of approximately $2.8 million, or 32%, from approximately $8.8 million for the three months ended March 31, 2020. This decrease was primarily due to the decreased amortization expense associated with customer intangibles.
Customer Acquisition Cost. Customer acquisition cost for the three months ended March 31, 2021 was approximately $0.2 million, a decrease of approximately $1.1 million, or 85%, from approximately $1.3 million for the three months ended March 31, 2020. This decrease was primarily due to limitation on our ability to use door-to-door marketing as a result of COVID-19 and a reduction in targeted organic customer acquisitions as we focus our efforts to improve our organic sales channels, including vendor selection and sales quality.
Operating Segment Results
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
March 31,
|
|
|
|
|
2021
|
|
2020
|
|
|
|
|
|
|
(in thousands, except volume and per unit operating data)
|
|
Retail Electricity Segment
|
|
|
|
|
|
|
|
|
Total Revenues
|
$
|
78,755
|
|
|
$
|
121,768
|
|
|
|
|
|
|
Retail Cost of Revenues
|
107,524
|
|
|
100,383
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less: Net gain (loss) on non-trading derivatives, net of cash settlements
|
5,517
|
|
|
(9,421)
|
|
|
|
|
|
|
Non-recurring event - Winter Storm Uri
|
(64,900)
|
|
|
—
|
|
|
|
|
|
|
Retail Gross Margin (1) — Electricity
|
$
|
30,614
|
|
|
$
|
30,806
|
|
|
|
|
|
|
Volumes — Electricity (MWhs) (3)
|
622,128
|
|
|
1,091,425
|
|
|
|
|
|
|
Retail Gross Margin (2) (4) — Electricity per MWh
|
$
|
49.21
|
|
|
$
|
28.23
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail Natural Gas Segment
|
|
|
|
|
|
|
|
|
Total Revenues
|
$
|
34,390
|
|
|
$
|
44,592
|
|
|
|
|
|
|
Retail Cost of Revenues
|
14,644
|
|
|
18,440
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less: Net gain on non-trading derivatives, net of cash settlements
|
348
|
|
|
1,497
|
|
|
|
|
|
|
Retail Gross Margin (1) — Gas
|
$
|
19,398
|
|
|
$
|
24,655
|
|
|
|
|
|
|
Volumes — Gas (MMBtus)
|
3,829,474
|
|
|
5,282,299
|
|
|
|
|
|
|
Retail Gross Margin (2) — Gas per MMBtu
|
$
|
5.07
|
|
|
$
|
4.67
|
|
|
|
|
|
(1) Reflects the Retail Gross Margin attributable to our Retail Electricity Segment or Retail Natural Gas Segment, as applicable. Retail Gross Margin is a non-GAAP financial measure. See " —Non-GAAP Performance Measures" for a reconciliation of Retail Gross Margin to most directly comparable financial measures presented in accordance with GAAP.
(2) Reflects the Retail Gross Margin for the Retail Electricity Segment or Retail Natural Gas Segment, as applicable, divided by the total volumes in MWh or MMBtu, respectively.
(3) Excludes volumes (8,402 MWhs) related to Winter Storm Uri impact.
(4) Retail Gross Margin - Electricity per MWh excludes Winter Storm Uri impact.
Three Months Ended March 31, 2021 Compared to Three Months Ended March 31, 2020
Retail Electricity Segment
Total revenues for the Retail Electricity Segment for the three months ended March 31, 2021 were approximately $78.7 million, a decrease of approximately $43.1 million, or 35%, from approximately $121.8 million for the three months ended March 31, 2020. This decrease was largely due to lower volumes sold, resulting in a decrease of $52.4 million as a result of smaller customer book in 2021. This decrease was partially offset by higher retail electricity prices as a result of the decrease of C&I RCEs as a total percentage of our customer book, which resulted in an increase of $8.4 million and an increase of $0.9 million related to electricity revenue due to Winter Storm Uri.
Retail cost of revenues for the Retail Electricity Segment for the three months ended March 31, 2021 were approximately $107.5 million, an increase of approximately $7.1 million, or 7%, from approximately $100.4 million for the three months ended March 31, 2020. This increase was primarily due to fewer customers, resulting in a decrease of $39.1 million, a decrease in supply costs of $4.6 million, and a change in the value of our retail derivative portfolio used for hedging, which resulted in a decrease of $15.0 million and an increase in supply cost of $65.8 million related to Winter Storm Uri.
Retail gross margin for the Retail Electricity Segment for the three months ended March 31, 2021 was approximately $30.6 million, a decrease of approximately $0.2 million, or 1%, from approximately $30.8 million for the three months ended March 31, 2020, as indicated in the table below (in millions).
|
|
|
|
|
|
|
|
Change in volumes sold
|
$
|
(13.0)
|
|
|
Change in gross margin - Winter Storm Uri
|
64.9
|
|
|
Change in unit margin per MWh
|
(51.7)
|
|
|
Change in retail electricity segment retail gross margin
|
$
|
0.2
|
|
Retail Natural Gas Segment
Total revenues for the Retail Natural Gas Segment for the three months ended March 31, 2021 were approximately $34.4 million, a decrease of approximately $10.2 million, or 23%, from approximately $44.6 million for the three months ended March 31, 2020. This decrease was primarily attributable to lower volumes sold, which decreased total revenues by $12.3 million offset by an increase of $2.1 million related to higher natural gas rates.
Retail cost of revenues for the Retail Natural Gas Segment for the three months ended March 31, 2021 were approximately $14.6 million, a decrease of $3.8 million, or 21%, from approximately $18.4 million for the three months ended March 31, 2020. This decrease was primarily due to lower volumes resulting in a decrease of $5.5 million, higher natural gas prices, which resulted in an increase of $0.5 million, and a change in the value of our derivative portfolio used for hedging, which resulted in an increase of $1.2 million.
Retail gross margin for the Retail Natural Gas Segment for the three months ended March 31, 2021 was approximately $19.4 million, a decrease of approximately $5.3 million, or 21%, from approximately $24.7 million for the three months ended March 31, 2020, as indicated in the table below (in millions).
|
|
|
|
|
|
|
|
Change in volumes sold
|
$
|
(6.9)
|
|
|
Change in unit margin per MMBtu
|
1.6
|
|
|
Change in retail natural gas segment retail gross margin
|
$
|
(5.3)
|
|
Liquidity and Capital Resources
Overview
Our primary sources of liquidity are cash generated from operations and borrowings under our Senior Credit Facility. Our principal liquidity requirements are to meet our financial commitments, finance current operations, fund organic growth and/or acquisitions, service debt and pay dividends. Our liquidity requirements fluctuate with our level of customer acquisition costs, acquisitions, collateral posting requirements on our derivative instruments portfolio, distributions, the effects of the timing between the settlement of payables and receivables, including the effect of bad debts, weather conditions, and our general working capital needs for ongoing operations. We believe that cash generated from operations and our available liquidity sources will be sufficient to sustain current operations and to pay required taxes and quarterly cash distributions, including the quarterly dividends to the holders of the Class A common stock and the Series A Preferred Stock, for the next twelve months. Estimating our liquidity requirements is highly dependent on then-current market conditions, including impacts of the COVID-19 pandemic, Winter Storm Uri, forward prices for natural gas and electricity, market volatility and our then existing capital structure and requirements.
Liquidity Position
The following table details our available liquidity as of March 31, 2021:
|
|
|
|
|
|
|
|
($ in thousands)
|
March 31, 2021
|
|
Cash and cash equivalents
|
$
|
81,491
|
|
|
Senior Credit Facility Availability (1)
|
44,517
|
|
|
|
|
|
Subordinated Debt Facility Availability (2)
|
15,000
|
|
|
Total Liquidity
|
$
|
141,008
|
|
(1) Reflects amount of Letters of Credit that could be issued based on existing covenants as of March 31, 2021.
(2) The availability of the Subordinated Facility is dependent on our Founder's willingness and ability to lend. See "—Sources of Liquidity —Subordinated Debt Facility."
Borrowings and related posting of letters of credit under our Senior Credit Facility are subject to material variations on a seasonal basis due to the timing of commodity purchases to satisfy natural gas inventory requirements and to meet customer demands during periods of peak usage. Additionally, borrowings are subject to borrowing base and covenant restrictions.
Cash Flows
Our cash flows were as follows for the respective periods (in thousands):
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Three Months Ended March 31,
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2021
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2020
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Net cash (used) provided in operating activities
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$
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(23,632)
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$
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39,389
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Net cash used in investing activities
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$
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(520)
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$
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(536)
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Net cash provided (used) in financing activities
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$
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33,959
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$
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(41,050)
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Three Months Ended March 31, 2021 Compared to the Three Months Ended March 31, 2020
Cash Flows Used in Operating Activities. Cash flows used in operating activities for the three months ended March 31, 2021 increased by $63.0 million compared to the three months ended March 31, 2020. The increase was primarily the result of non-recurring Winter Storm Uri related costs of $64.9 million for the three months ended March 31, 2021.
Cash Flows Used in Investing Activities. Cash flows used in investing activities decreased by less than $0.1 million for the three months ended March 31, 2021. The decrease was primarily the result of reduction in capital spending during three months ended March 31, 2021.
Cash Flows Provided by Financing Activities. Cash flows provided by financing activities increased by $75.0 million for the three months ended March 31, 2021, primarily due to an increase in net borrowings under our Senior Credit Facility of $63.0 million and increase in sub-debt borrowing of $10.0 million during the three months ended March 31, 2021.
Sources of Liquidity and Capital Resources
Senior Credit Facility
As of March 31, 2021, we had total commitments of $227.5 million under the Senior Credit Facility, of which $164.7 million was outstanding, including $29.7 million of outstanding letters of credit, with a maturity date of July 31, 2022.
For a description of the terms and conditions of our Senior Credit Facility, including descriptions of the interest rate, commitment fee, covenants and terms of default, please see Note 9 "Debt" in the notes to our condensed consolidated financial statements.
As of March 31, 2021, we were in compliance with the covenants under our Senior Credit Facility. Based upon existing covenants as of March 31, 2021, we had availability to borrow up to $44.5 million under the Senior Credit Facility.
Amended and Restated Subordinated Debt Facility
Our Subordinated Debt Facility allows us to draw advances in increments of no less than $1.0 million per advance up to $25.0 million. Although we may use the Subordinated Debt Facility from time to time to enhance short term liquidity, we do not view the Subordinated Debt Facility as a material source of liquidity. See Note 9 "Debt" for additional details. As of March 31, 2021, there was $10.0 million outstanding borrowings under the Subordinated Debt Facility, and availability to borrow up to $15.0 million under the Subordinated Debt Facility.
Uses of Liquidity and Capital Resources
Repayment of Current Portion of Senior Credit Facility
Our Senior Credit Facility, matures in July 2022, and thus, no amounts are due currently. However, due to the revolving nature of the facility, excess cash available is generally used to reduce the balance outstanding, which at March 31, 2021 was $135.0 million. The current variable interest rate on the facility at March 31, 2021 was 3.75%.
Customer Acquisitions
Our customer acquisition strategy consists of customer growth obtained through organic customer additions as well as opportunistic acquisitions. During the three months ended March 31, 2021 and 2020, we spent a total of $0.2 million and $1.3 million, respectively, on organic customer acquisitions.
Capital Expenditures
Our capital requirements each year are relatively low and generally consist of minor purchases of equipment or information system upgrades and improvements. Capital expenditures for the three months ended March 31, 2021 and 2020 included $0.5 million and $0.5 million, respectively, related to information systems improvements.
Dividends and Distributions
During the three months ended March 31, 2021, we paid dividends to holders of our Class A common stock for the quarter ended December 31, 2020 of $0.18125 per share or $2.7 million in the aggregate. In order to pay our stated dividends to holders of our Class A common stock, our subsidiary, Spark HoldCo is required to make corresponding distributions to holders of Class B common stock (our non-controlling interest holders). As a result, during the three months ended March 31, 2021, Spark HoldCo made distributions of $3.8 million to our non-controlling interest holders related to the dividend payments to holders of our Class A common stock.
For the three months ended March 31, 2021, we paid $2.0 million of dividends to holders of our Series A Preferred Stock, and as of March 31, 2021, we had accrued $2.0 million related to dividends to holders of our Series A Preferred Stock, which we paid on April 15, 2021. For the full year ended December 31, 2021, at the stated dividend rate of the Series A Preferred Stock of $2.1875 per share, we would be required to pay dividends of $7.9 million in the aggregate based on the Series A Preferred Stock outstanding as of March 31, 2021.
On April 21, 2021, our Board of Directors declared a quarterly cash dividend in the amount of $0.18125 per share to holders of our Class A common stock and $0.546875 per share for the Series A Preferred Stock for the first quarter of 2021. Dividends on Class A common stock will be paid on June 15, 2021 to holders of record on June 1, 2021, and Series A Preferred Stock dividends will be paid on July 15, 2021 to holders of record on July 1, 2021.
Our ability to pay dividends in the future will depend on many factors, including the performance of our business and restrictions under our Senior Credit Facility. If our business does not generate sufficient cash for Spark HoldCo to make distributions to us to fund our Class A common stock and Series A Preferred Stock dividends, we may have to borrow to pay such amounts. Further, even if our business generates cash in excess of our current annual dividend (of $0.725 per share on our Class A common stock), we may reinvest such excess cash flows in our business and not increase the dividends payable to holders of our Class A common stock. Our future dividend policy is within the discretion of our Board of Directors and will depend upon the results of our operations, our financial condition, capital requirements and investment opportunities.
Share Repurchase Program
On August 18, 2020, our Board of Directors authorized a share repurchase program of up to $20.0 million of Class A common stock through August 18, 2021. The share repurchase program was suspended in March 2021 pursuant to an agreement with lenders under our Senior Credit Facility. During the three months ended March 31, 2021, we did not repurchase our Class A common stock.
Collateral Posting Requirements
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. Due to the COVID-19 pandemic, certain local regulated utilities and our supplier counterparties have contacted us inquiring about our financial condition and the impact the pandemic is having on our operations. These inquiries may lead to additional requests for cash or letters of credit in an effort to mitigate the risk of default in paying our obligations related to the future delivery of natural gas or electricity. As of March 31, 2021, we had not been required to post additional collateral as a result of COVID-19.
As discussed above, during the winter storm Uri event, we were required to post a significant amount of collateral with ERCOT. Despite these posting requirements, we consistently maintained, and continue to maintain, sufficient liquidity to conduct our operations in the ordinary course. As of March 31, 2021, we had not been required to post additional collateral as a result of the winter storm Uri.
Off-Balance Sheet Arrangements
As of March 31, 2021, we had no material "off-balance sheet arrangements."
Related Party Transactions
For a discussion of related party transactions, see Note 13 "Transactions with Affiliates" to Part I, Item 1 of this Report.
Critical Accounting Policies and Estimates
Our critical accounting policies and estimates are described in “Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” in our 2020 Form 10-K. There have been no changes to these policies and estimates since the date of our 2020 Form 10-K.
Refer to Note 2 "Basis of Presentation and Summary of Significant Accounting Policies" to Part I, Item 1 of this Report for a discussion on recent accounting pronouncements.
Contingencies
In the ordinary course of business, we may become party to lawsuits, administrative proceedings and governmental investigations, including regulatory and other matters. Except as described in Note 12 "Commitments and Contingencies" to Part I, Item 1 of this Report, as of March 31, 2021, management did 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. For a discussion of the status of current legal and regulatory matters, see Note 12 "Commitments and Contingencies" to Part I, Item 1 of this Report.